Petroleum Geology and Exploration of the Bongor Basin [1st ed. 2023] 9811926727, 9789811926723

Table of contents :
Foreword 1
Foreword 2
Preface
Contents
1 Introduction
1.1 Current Status of CNPC’s Oil and Gas Exploration Projects in Africa
1.2 History of Oil and Gas Exploration in the Republic of Chad
1.3 Exploration History of Permit H in Chad
1.3.1 Exploration by Former Operators
1.3.2 Exploration by CNPC
1.4 Experience of Efficient Exploration
1.4.1 Implementing “Saturation Exploration” and Achieving Continuous Breakthroughs in New Strata and Frontiers
1.4.2 Breaking the Routine and Accelerating the Pace of Exploration
References
2 Regional Geological Characteristics of the Central African Rift System
2.1 Regional Tectonic Characteristics
2.1.1 Basement Rock Characteristics
2.1.2 Formation and Evolution of Mesozoic-Cenozoic Rift Basins
2.2 Middle-Cenozoic Magmatic Activity
2.2.1 Petrological and Geochemical Characteristics
2.2.2 Periods of Magmatic Activity
2.2.3 Analysis of Tectonic Environment
2.3 Basin Types and Petroleum Geological Characteristics
2.3.1 Superimposed Rift Basins
2.3.2 Inverted Rift Basins
2.3.3 Regional Inversion Characteristics
References
3 Tectonic Characteristics of Basins
3.1 Basement Rock Characteristics
3.1.1 Rock Types
3.1.2 Determination of the Ages of Rocks
3.2 Tectonic Characteristics of Basins
3.2.1 Tectonic Characteristics of the Basement
3.2.2 Tectonic Units in the Basin
3.3 Tectonic Evolution of the Basin
3.3.1 Reconstruction of Burial History
3.3.2 Recovery of Extension-Compression History
3.3.3 Evolution History of Basin
3.4 Structural Style
3.4.1 Extensional Structural Style
3.5 Graben-Horst Integrated Slope
3.5.1 Inversion Structural Style
3.5.2 Strike-Slip Structural Style
3.5.3 Mud Diapir Structural Style
References
4 Characteristics of Lower Cretaceous Strata, Reservoirs, and Seals
4.1 Stratigraphic Characteristics
4.1.1 Lithostratigraphy
4.1.2 Biostratigraphic Division
4.1.3 Chronostratigraphy
4.2 Lower Cretaceous Sedimentary Characteristics
4.2.1 Sequence Stratigraphic Framework
4.2.2 Sedimentary Environment Analysis
4.2.3 Types of Sedimentary Systems
4.2.4 Sedimentary Facies Model
4.2.5 Distribution of Sedimentary Systems
4.3 Lower Cretaceous Reservoir Characteristics
4.3.1 Characteristics of Reservoir Architecture
4.3.2 Characteristics of Reservoir Rocks and Minerals
4.3.3 Characteristics of Reservoir Space
4.3.4 Characteristics of Diagenesis
4.4 Seal Characteristics
4.4.1 Sealing Mechanism of Mudstone Seal
4.4.2 Comprehensive Evaluation of Seal
References
5 Characteristics of Basement Rock Reservoirs
5.1 Reservoir Properties of Basement Rock Reservoirs
5.1.1 Binary Division Scheme of Basement Rock Lithology
5.1.2 Characteristics of Basement Rock Reservoir Space
5.1.3 Classification of Basement Rock Reservoirs
5.1.4 General Evaluation of the Reservoir Quality of Basement Rock
5.2 Controlling Factors for the Development of Basement Rock Reservoirs
5.2.1 Controlling Action of the Mechanical Properties of Rocks on Fracture Development
5.2.2 Controlling Action of Lithology on Physical Properties
5.2.3 Controlling Action of Rock and Mineral Composition on Physical Properties
5.2.4 Controlling Action of Burial Depth on Physical Properties
5.2.5 Influence of Diagenesis on Physical Properties
5.3 Reservoir Sequences of Buried Hills in Basement Rocks
5.3.1 Weathering and Leaching Zone (Zone A)
5.3.2 Fracture-Cavity Development Zone (Zone B)
5.3.3 Development Zone of Semi-Filled Fractures (Zone C)
5.3.4 Tight Zone (Zone D)
References
6 Geochemical Characteristics of Source Rocks and Petroleum
6.1 Source Rock Evaluation
6.1.1 Distribution of Dark Mudstones
6.1.2 Organic Matter Abundance
6.1.3 Organic Matter Type
6.1.4 Thermal Evolution Characteristics of Organic Matter
6.1.5 Identification of Depositional Environments of Source Rocks
6.1.6 Comprehensive Evaluation of Source Rocks
6.2 Geochemical Characteristics of Crude Oil
6.2.1 Physicochemical Characteristics of Crude Oil
6.2.2 Total Acid Number, Composition and Origin of Crude Oil
6.2.3 Crude Oil Group Composition
6.2.4 Geochemical Characteristics of Saturated Hydrocarbons in Crude Oil
6.2.5 Biomarkers Composition of Aromatic Hydrocarbons in Crude Oil
6.2.6 Carbon Isotopic Composition of Crude Oil
6.2.7 Crude Oil Maturity Analyses
6.3 Geochemical Characteristics of Natural Gas
6.3.1 Natural Gas Composition
6.3.2 Genetic Types of Natural Gas
6.3.3 Analysis of Natural Gas Maturity
6.4 Oil (Gas)-Source Correlation
6.4.1 Oil-Oil Correlation
6.4.2 Gas–Gas Correlation
6.4.3 Oil–Gas Correlation
6.4.4 Oil-Source Correlation
6.4.5 Gas-Source Rock Correlation
References
7 Geological Features of Hydrocarbon Reservoirs
7.1 Hydrocarbon Reservoir Types
7.1.1 Sandstone Reservoirs
7.1.2 Buried Hill Reservoirs in Basement Rocks
7.1.3 Combination Reservoir
7.2 Hydrocarbon Accumulation Periods
7.2.1 Inclusion Analysis
7.2.2 Hydrocarbon Generation and Expulsion Time of Source Rocks
7.2.3 Dynamic Oil and Gas Charging in the Great Baobab Oilfield
7.3 Main Controlling Factors of Hydrocarbon Enrichment
7.3.1 ‘Below Source Plays’ are the Main Hydrocarbon Accumulation Structures
7.3.2 Compressional Inversion Anticlines are the Main Hydrocarbon Trap Type
7.3.3 Subaqueous Fan and Fan Delta Sand Bodies are Main Reservoirs
7.3.4 Coupling of Felsic Basement Rock with a Strike-Slip-Extensional Environment Leads to the Widespread Development of Buried Hill Reservoirs
7.3.5 Composite Sandstone-Basement Rock Traps in Uplifts Between Depressions is the Favorable Play for the Formation of Large Oilfields
7.3.6 The Northern Slope is the Most Favorable Oil and Gas Enrichment Area
References
8 Seismic Reservoir Prediction Technology
8.1 Inversion Technology for Identifying Thin Sandstone Reservoirs in Areas with Igneous Rock Intrusions
8.1.1 Fine Interpretation of Complex Fault Blocks
8.1.2 Distribution Characteristics of Igneous Rocks
8.1.3 Reservoir Inversion in Strong Development Areas of Igneous Rocks
8.2 Characterization of Fan Body Boundaries Against High and Steep Backgrounds in Small Rifts
8.2.1 Stratigraphic Sedimentary Characteristics
8.2.2 Analysis of Petrophysical Characteristics of Reservoirs
8.3 Reservoir Prediction Technology for Basement Rock Buried Hills
8.3.1 Research of Seismic Forward Modeling
8.3.2 Seismic Prediction Technology for High-Quality Reservoirs
8.3.3 Seismic Fracture Prediction Technology
8.3.4 Evaluation of Favorable Reservoirs Using Logging-Seismic Synergy
References
9 Geological Evaluation and Interpretation from Logs
9.1 Lithological Identification of Basement Rock Using Logging Data
9.1.1 Logging Response Mechanism of Lithology
9.1.2 Qualitative Identification of Logging Lithology
9.1.3 Quantitative Identification of Lithology Using Logging
9.1.4 Distinguishing Between Felsic and Mafic Rocks
9.1.5 Dominant Lithology Sequence
9.2 Logging Evaluation of Oil Layers, Gas Layers, and Water Layers in Basement Rock
9.2.1 Qualitative Identification of Reservoirs Using Well Logging
9.2.2 Quantitative Interpretation and Classification of Basement Reservoir Parameters
9.3 Identification Technologies for Oil and Gas Layers
9.3.1 Fluid Property Diagnosis Using Data from Mud Logging, Coring, and Oil Test
9.3.2 Quantitative Identification of Oil Layers from Gas Survey Data
9.3.3 Relationship Between Oil Layers and Felsic Content, Wave Impedance, and Resistivity
9.3.4 Lower Limit Definition of Oil Layers
9.4 Wireline Logging Analysis of Ground Stress
9.4.1 Elliptical Borehole Method
9.4.2 Induced Fracture Method
9.4.3 Fast Shear Wave Azimuth Method
References

Citation preview

Lirong Dou Kunye Xiao Jingchun Wang

Petroleum Geology and Exploration of the Bongor Basin

Petroleum Geology and Exploration of the Bongor Basin

Lirong Dou · Kunye Xiao · Jingchun Wang

Petroleum Geology and Exploration of the Bongor Basin

Lirong Dou Research Institute of Petroleum Exploration and Development China National Petroleum Corporation Beijing, China

Kunye Xiao Research Institute of Petroleum Exploration and Development China National Petroleum Corporation Beijing, China

Jingchun Wang China National Oil and Gas Exploration and Development Company Ltd. Beijing, China

ISBN 978-981-19-2672-3 ISBN 978-981-19-2673-0 (eBook) https://doi.org/10.1007/978-981-19-2673-0 Jointly published with Petroleum Industry Press The print edition is not for sale in China (Mainland). Customers from China (Mainland) please order the print book from: Petroleum Industry Press. © Petroleum Industry Press 2023 This work is subject to copyright. All rights are solely and exclusively licensed by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors, and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, expressed or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer Nature Singapore Pte Ltd. The registered company address is: 152 Beach Road, #21-01/04 Gateway East, Singapore 189721, Singapore

Foreword 1

Permit H in Chad is the largest overseas risk exploration block obtained by CNPC. It is also a block in the areas from which many international oil companies have retreated after more than 30 years of exploration without any commercial discoveries. Permit H is difficult to explore due to complex geological conditions. Since CNPC became an operator in Permit H in 2007, the Bongor basin, as a relatively complete one in the block, was selected as a critical target, and more comprehensive research on petroleum geology was focused on the basin. CNPC made rapid exploration deployment and found several large and medium-sized oil discoveries. Based on the discoveries, a 6 million ton upstream and 6 million ton downstream integrated crude oil production base was established in Chad. As a unique rift basin in the Central African Rift System, the Bongor basin experienced strong strike-slip extension in the Early Cretaceous, weak extension in the Late Cretaceous and early Paleogene, and strong inversion and uplift in the late Paleocene. The geology structure of the Basin is significantly different from other Basins in the Central and Western African Rift System, and the hydrocarbon accumulation pattern of the Basin has changed significantly from those of Sudan. Therefore, the experience of China and Sudan rift basins cannot directly guide exploration in Bongor. Because of the strong inversion characteristics of the Basin, new reservoir-forming patterns and exploration technology were needed. Based on more than ten years of exploration and integrated analysis of the regional geology, structure, stratum, sedimentary reservoir, geochemistry, and oil and gas reservoir characteristics of the Bongor Basin, the authors of this book established the geological model and reservoir-forming pattern of strong inversion rift basin. They also determined that the “intra-source play” is the main exploration play. Strong inversion can not only increase the trap scale and improve the basement reservoir property but also significantly improve the economy of the reservoir. The intra-source sandstone and the buried hill can be combined as a whole and permit what the authors call stereoscopic exploration. This book also systematically summarizes the comprehensive supporting technologies of seismic and logging exploration in strong inversion rift basins to provide technical support for exploration and discovery. Baobab and other large oil discoveries in Permit H are the largest oil fields found in West Africa in the past 30 years. The major discovery of v

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the Precambrian basement reservoir has opened a new play of onshore hydrocarbon exploration in onshore Africa. The lead author of this book has long been committed to petroleum geological research and global risk exploration in the rift basin and has published three monographs and 61 papers on risk exploration. In his career, starting from 1994, he presided over several of PetroChina’s overseas exploration projects, such as the Sudan and Chad exploration projects. As to Permit H in Chad, he had been in charge from the evaluation stage of the new project with no commercial discovery in 2004 to an upstream and downstream integrated crude oil production base in 2011. This provided him with many first-hand data and practical experience in overseas risk exploration. The book is based on these combined with the latest research results. This monograph systematically summarizes hydrocarbon accumulation theory and exploration technology in typical strong inversion rift basins. Exploration in the Bongor Basin also provides a successful case of multi-basin risk exploration. This book enriches the petroleum geological theory of rift basins and is an important reference for exploring other similar basins and overseas risk exploration.

Beijing, China February 2018

William L. Fisher Jackson school of Geosciences Professor, former chairman of The Department of Geological Science The University of Texas at Austin Former assistant secretary Energy and Minerals U.S. Department of the Interior Former president, American Association of Petroleum Geologists

Foreword 2

In 1993, China became a net importer of oil, and international operations formed a significant part of China’s petroleum strategy. Overseas petroleum exploration is crucial to obtain international oil and gas resources and ensure national petroleum security. Over more than 20 years, overseas exploration has experienced rapid growth and development; from no exploration to small scale and then large scale, from being a non-operator to an operator, from onshore to offshore, from conventional to unconventional reservoirs, and from joint ventures to the sole proprietorship. By 2011, the “Overseas Daqing” had been established. China has traditionally had friendly relationships with African nations, the first choice to implement CNPC’s “go global” strategy. In the past 28 years, CNPC has achieved great successes in the oil and gas exploration and development in Sudan/South Sudan, demonstrating its technical strength and enhancing its international image. CNPC has also promoted oil and gas cooperation with countries neighboring Sudan, with Permit H in Chad being an example of such a project. Permit H is the largest overseas exploration block so far obtained by CNPC. Before CNPC’s activity, various international oil companies had conducted petroleum exploration but failed to make commercially viable discoveries in the block for over 30 years. Defeated by complex geological conditions and a challenging environment for exploration, they all eventually withdrew. From 2004 to 2006, CNPC took an equity stake in Permit H as a non-operator. During this period, a CNPC research team carried out the technical and economic evaluation of the seven basins in the block, selecting the relatively integrated Bongor Basin as the preferred area for exploration and the most likely to yield breakthroughs. The team conducted an in-depth study of petroleum geology in the area. After becoming the operator in January 2007, CNPC immediately deployed resources and undertook intensive exploration, rapidly discovering a series of large and medium-sized oil fields and, in doing so, establishing a fully integrated upstream and downstream petroleum industry for the nation of Chad. The Chad project has become another successful CNPC exploration project in Africa, following the company’s successes in Sudan.

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Foreword 2

The Bongor Basin is unique among the basins of the Central African Rift System (CARS). It underwent intense strike-slip-extension in Early Cretaceous, weak extension in Late Cretaceous, and reformation by intense inversion and uplifting in Late Cretaceous-Paleocene. Therefore, the geological and structural features of the Bongor Basin are significantly different from those of other basins in the Central and West African Rift System. The hydrocarbon accumulation conditions in the basin have also undergone significant changes over time. Therefore, the hydrocarbon accumulation model established in eastern China and Sudan is not a practical guide for oil and gas exploration in the Bongor Basin, so a new hydrocarbon accumulation model had to be established for the basin. Through more than ten years of studies and practice, the authors have established a geological and hydrocarbon accumulation model for strongly inverted rift basins and have identified “below-source rocks” reservoirs as the primary exploration strata. The strong inversion effect is conducive to increasing the sizes of traps, improving basement rock reservoirs, and significantly improving the trap economy. A major discovery in Precambrian crystalline basement rock reservoirs in the basin has opened up an entirely new play of onshore oil and gas exploration in Africa. This monograph summarizes hydrocarbon accumulation theory and exploration technology in typical strongly inverted rift basins. It is also a case study of a successful multi-basin risk exploration program in CNPC’s wholly-owned operations. The study enriches and develops petroleum geological theories for rift basins and has crucial reference significance for exploring other similar basins and overseas risk exploration in general. Although CNPC has been engaged in overseas risk exploration for 25 years, we are still a beginner in international petroleum exploration compared to the major Western oil companies. Shifting companys’ exploration focus to deep waters, polar regions, and unconventional resources will require a new generation of young geologists to be bold and innovative. I expect CNPC to make even more remarkable discoveries in overseas oil and gas exploration in the new era and succeed in theoretical and technological innovations.

Beijing, China February 8, 2018

Xiaoguang Tong Academician of the Chinese Academy of Engineering

Preface

Transnational oil and gas exploration faces numerous major challenges, such as short exploration timescales, high exploration costs, complex exploration targets, difficult field operation conditions, and oppressive contract terms. Only rapid, large-scale discoveries can guarantee investment recovery. Because of this, operators have to break free of the constraints of established geological understandings and take full advantage of theoretical and technological innovation when facing insurmountable obstacles that have often led to the failures of former operators. Only by taking a bold approach can significant oil and gas fields being discovered within limited exploration timescales and under pressure to assure investment recovery. After many years of exploration, the major Western oil companies have retained the favorable petroliferous blocks in onshore sedimentary basins in Africa and converted them into development blocks. Exploration conditions in the remaining blocks are complicated, and their exploration potential is not promising. The original contract area in Permit H in Chad covers an area of 44 × 104 km2 , which is one-third of the entire territorial area of the country. It is the largest risk exploration project undertaken since the introduction of CNPC’s “go global” strategy. Several major international oil companies had already explored the area but returned it to the government in 1999 without making any discoveries. Situated in the southern part of Permit H, the Bongor Basin is the only relatively integrated rift basin in the block without commercial oil and gas discoveries. Over thirty years of exploration, plenty of geological and geophysical prospecting work had been done, and multiple exploration wells had been drilled and failed. Following a great deal of intensive investigation, the authors concluded that former operators had an insufficient understanding of the inversion in the Bongor Basin and its impact on factors controlling hydrocarbon accumulation and impaired cognition of structural and sedimentary sequence features in continental rift basins. The result was unable to correctly identify the main play and the play fairways, including the Precambrian basement rock reservoirs. By January 2007, when CNPC took over Permit H as the operator, the unexpired exploration period for the block was less than five years. The discovery of viable large-scale fields within such a limited exploration period presented an enormous ix

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challenge. On top of this, in Chad, the rainy season lasts for four to five months every year, and tropical diseases are rife. Moreover, in this landlocked country with poor local infrastructure, transnational transportation cycles are long, and operation costs are high, further complicating exploration operations. In 2007, based on the research conducted between 2004 and 2006, a CNPC research team, including the authors, selected the Bongor Basin as the most promising breakthrough point for exploration and accelerated the pace of exploration in this area. We collected large samples—oil, gas, water, rocks, paleontology, etc.—and conducted multi-disciplinary basic research on the structure, stratigraphy, sedimentary sequences, reservoirs and seal, and petroleum geology. The most appropriate exploration technologies were adopted and integrated, and a “geological model and accumulation model for strongly inverted rift basins” was established. The new model was based on intensive exploration experience and differed substantially from the model previously developed for exploration in Sudan. Based on “understanding, practice, re-understanding, and re-practice,” we implemented a program of “threedimensional exploration,” rapidly discovering a series of large and medium-sized oil fields and achieving a “leapfrog” development. We broke through the barrier of oil flow, achieving a heavy oil flow in 2007, and broke through the high-yield conventional oil barrier in 2009. In 2012, we discovered large, productive, and prolific oil fields. In 2013, a major buried hill oil field was discovered in the Precambrian basement rock. The discovery of these reserves laid the foundation for the nation of Chad to establish a fully integrated upstream and downstream petroleum industry, and the country achieved energy independence in 2011. The project also enabled the country to export crude oil, and Chad’s oil entered the international market in 2014. The reserves and production scale of the Bongor Basin are now expanding continuously. Drilling of new wells in the West Doba Block and the Doseo Block has also revealed favorable exploration potential. This book aims to refine an understanding of the petroleum geological characteristics of strongly inverted rift basins, with the Bongor Basin as an example, and to describe CNPC’s experience of achieving efficient exploration through innovation in exploration concepts, theory, and technology. This will provide a reference for exploring other risk exploration blocks in Africa and encourage the acquisition of new risk exploration blocks. The book was conceived by Lirong Dou. The preface was written by Lirong Dou, Chap. 1 by Lirong Dou, Yong Hu, Jingchun Wang, and Renchong Wang; Chap. 2 by Lirong Dou, Renchong Wang, Yulin Lu, and Wangquan Wang; the first section of Chap. 3 by Mingyu Zhang and Zhibin Tian; the second, third, and fourth sections of Chap. 3 by Kunye Xiao, Lirong Dou, Chunfang Liu, Shuanghe Dai, and Demin Mao; Chap. 4 by Yebo Du, Ying Hu, Lirong Dou, and Hongri Song; Chap. 5 by Lirong Dou, Xuejun Wang, Mingyu Zhang, Xiaodong Wei, Zhibin Tian, and Guobin Bai; Chap. 6 by Dingsheng Cheng, Zhigang Wen, Lirong Dou, and Ying Hu; Chap. 7 by Lirong Dou, Jingchun Wang, Yong Hu, Renchong Wang, Hongri Song, Ying Hu, and Wei Li; the first and second sections of Chap. 8 by Gaojie Xiao, Kunye Xiao, Zaohong Li, and Qiaofeng Liang; the third section of Chap. 8 by Xiaodong Wei, Jingchun Wang, Jianlin Li, Yuguang Zhao, and Lizhong Ren; and Chap. 9 by Lirong

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Dou, Chuanshu Dai, Guohui Ni, Yongjie Xue, Qiaofeng Liang, and Yang Li. Finally, all of the chapters were reviewed and edited by Lirong Dou. The book summarizes more than ten years of research and exploration. Our research was funded by the Department of Science and Technology Management of China National Petroleum Corporation and China National Oil and Gas Exploration and Development Corporation. It was also strongly supported and actively participated in by the Research Institute of Petroleum Exploration and Development of CNPC, the Bureau of Geophysical Prospecting INC., China National Petroleum Corporation, CNPC Greatwall Drilling Company, Petrochina Yumen Oilfield Company, and other institutions, as well as the Chad Ministry of Petroleum and the Chad National Oil Company. The authors sincerely thank Academician Xiaoguang Tong and Professor William L. Fisher for kindly providing a foreword for this book. We also thank Academician Xiaoguang Tong, Academician Chengzao Jia, Academician Wenzhi Zhao, Gongxun Lv, Zhongcai Wang, Xiandeng Ye, Dezhi Bian, Longxin Mu, Liangqing Xue, Xiaohua Pan, Yongdi Su, Buqing Shi, Guangya Zhang, Lunkun Wan, and other leaders and experts for their guidance and assistance as our work progressed. Overseas risk exploration is an enormous, highly structured enterprise. A great number of Chinese and international personnel participated in the project. Therefore, we also particularly wish to thank all Chinese and international engineering and technical staff and their families for their quiet contributions to the project’s success. The project’s timescale for oil and gas exploration was short. The project’s purpose was, above all, to obtain large-scale oil and gas discoveries rapidly and thus ensure investment recovery. It is impossible in these circumstances to carry out an exhaustive sample analysis, and our understanding of geological conditions needs to be further enhanced in many respects. Beijing, China

Lirong Dou Kunye Xiao Jingchun Wang

Contents

1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1 Current Status of CNPC’s Oil and Gas Exploration Projects in Africa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 History of Oil and Gas Exploration in the Republic of Chad . . . . . . 1.3 Exploration History of Permit H in Chad . . . . . . . . . . . . . . . . . . . . . . . 1.3.1 Exploration by Former Operators . . . . . . . . . . . . . . . . . . . . . . . 1.3.2 Exploration by CNPC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4 Experience of Efficient Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1 Implementing “Saturation Exploration” and Achieving Continuous Breakthroughs in New Strata and Frontiers . . . . 1.4.2 Breaking the Routine and Accelerating the Pace of Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Regional Geological Characteristics of the Central African Rift System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 Regional Tectonic Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.1 Basement Rock Characteristics . . . . . . . . . . . . . . . . . . . . . . . . 2.1.2 Formation and Evolution of Mesozoic-Cenozoic Rift Basins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 Middle-Cenozoic Magmatic Activity . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.1 Petrological and Geochemical Characteristics . . . . . . . . . . . . 2.2.2 Periods of Magmatic Activity . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.3 Analysis of Tectonic Environment . . . . . . . . . . . . . . . . . . . . . . 2.3 Basin Types and Petroleum Geological Characteristics . . . . . . . . . . . 2.3.1 Superimposed Rift Basins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.2 Inverted Rift Basins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.3 Regional Inversion Characteristics . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1 2 4 5 7 7 13 14 15 23 25 27 27 28 31 32 39 40 44 44 54 59 63

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3 Tectonic Characteristics of Basins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Basement Rock Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.1 Rock Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.2 Determination of the Ages of Rocks . . . . . . . . . . . . . . . . . . . . 3.2 Tectonic Characteristics of Basins . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.1 Tectonic Characteristics of the Basement . . . . . . . . . . . . . . . . 3.2.2 Tectonic Units in the Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 Tectonic Evolution of the Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.1 Reconstruction of Burial History . . . . . . . . . . . . . . . . . . . . . . . 3.3.2 Recovery of Extension-Compression History . . . . . . . . . . . . . 3.3.3 Evolution History of Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4 Structural Style . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.1 Extensional Structural Style . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5 Graben-Horst Integrated Slope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.1 Inversion Structural Style . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.2 Strike-Slip Structural Style . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.3 Mud Diapir Structural Style . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

69 70 70 83 83 83 87 95 95 103 104 106 107 109 113 119 119 120

4 Characteristics of Lower Cretaceous Strata, Reservoirs, and Seals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 Stratigraphic Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.1 Lithostratigraphy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.2 Biostratigraphic Division . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.3 Chronostratigraphy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2 Lower Cretaceous Sedimentary Characteristics . . . . . . . . . . . . . . . . . 4.2.1 Sequence Stratigraphic Framework . . . . . . . . . . . . . . . . . . . . . 4.2.2 Sedimentary Environment Analysis . . . . . . . . . . . . . . . . . . . . . 4.2.3 Types of Sedimentary Systems . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.4 Sedimentary Facies Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.5 Distribution of Sedimentary Systems . . . . . . . . . . . . . . . . . . . . 4.3 Lower Cretaceous Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . 4.3.1 Characteristics of Reservoir Architecture . . . . . . . . . . . . . . . . 4.3.2 Characteristics of Reservoir Rocks and Minerals . . . . . . . . . . 4.3.3 Characteristics of Reservoir Space . . . . . . . . . . . . . . . . . . . . . . 4.3.4 Characteristics of Diagenesis . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4 Seal Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.1 Sealing Mechanism of Mudstone Seal . . . . . . . . . . . . . . . . . . . 4.4.2 Comprehensive Evaluation of Seal . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

125 125 127 131 134 135 135 138 139 143 144 151 151 152 155 159 162 162 165 169

5 Characteristics of Basement Rock Reservoirs . . . . . . . . . . . . . . . . . . . . . 5.1 Reservoir Properties of Basement Rock Reservoirs . . . . . . . . . . . . . . 5.1.1 Binary Division Scheme of Basement Rock Lithology . . . . . 5.1.2 Characteristics of Basement Rock Reservoir Space . . . . . . . . 5.1.3 Classification of Basement Rock Reservoirs . . . . . . . . . . . . .

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5.1.4 General Evaluation of the Reservoir Quality of Basement Rock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2 Controlling Factors for the Development of Basement Rock Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.1 Controlling Action of the Mechanical Properties of Rocks on Fracture Development . . . . . . . . . . . . . . . . . . . . . 5.2.2 Controlling Action of Lithology on Physical Properties . . . . 5.2.3 Controlling Action of Rock and Mineral Composition on Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.4 Controlling Action of Burial Depth on Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.5 Influence of Diagenesis on Physical Properties . . . . . . . . . . . 5.3 Reservoir Sequences of Buried Hills in Basement Rocks . . . . . . . . . 5.3.1 Weathering and Leaching Zone (Zone A) . . . . . . . . . . . . . . . . 5.3.2 Fracture-Cavity Development Zone (Zone B) . . . . . . . . . . . . 5.3.3 Development Zone of Semi-Filled Fractures (Zone C) . . . . . 5.3.4 Tight Zone (Zone D) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Geochemical Characteristics of Source Rocks and Petroleum . . . . . . . 6.1 Source Rock Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.1 Distribution of Dark Mudstones . . . . . . . . . . . . . . . . . . . . . . . . 6.1.2 Organic Matter Abundance . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.3 Organic Matter Type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.4 Thermal Evolution Characteristics of Organic Matter . . . . . . 6.1.5 Identification of Depositional Environments of Source Rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.6 Comprehensive Evaluation of Source Rocks . . . . . . . . . . . . . 6.2 Geochemical Characteristics of Crude Oil . . . . . . . . . . . . . . . . . . . . . . 6.2.1 Physicochemical Characteristics of Crude Oil . . . . . . . . . . . . 6.2.2 Total Acid Number, Composition and Origin of Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2.3 Crude Oil Group Composition . . . . . . . . . . . . . . . . . . . . . . . . . 6.2.4 Geochemical Characteristics of Saturated Hydrocarbons in Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2.5 Biomarkers Composition of Aromatic Hydrocarbons in Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2.6 Carbon Isotopic Composition of Crude Oil . . . . . . . . . . . . . . 6.2.7 Crude Oil Maturity Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3 Geochemical Characteristics of Natural Gas . . . . . . . . . . . . . . . . . . . . 6.3.1 Natural Gas Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.2 Genetic Types of Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.3 Analysis of Natural Gas Maturity . . . . . . . . . . . . . . . . . . . . . . . 6.4 Oil (Gas)-Source Correlation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.1 Oil-Oil Correlation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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204 205 205 208 209 212 212 217 220 222 222 224 229 233 233 233 234 234 236 243 244 253 253 254 256 259 262 270 278 278 278 281 285 287 287

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6.4.2 6.4.3 6.4.4 6.4.5 References

Gas–Gas Correlation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil–Gas Correlation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil-Source Correlation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas-Source Rock Correlation . . . . . . . . . . . . . . . . . . . . . . . . . . .....................................................

289 291 292 295 296

7 Geological Features of Hydrocarbon Reservoirs . . . . . . . . . . . . . . . . . . . 7.1 Hydrocarbon Reservoir Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1.1 Sandstone Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1.2 Buried Hill Reservoirs in Basement Rocks . . . . . . . . . . . . . . . 7.1.3 Combination Reservoir . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2 Hydrocarbon Accumulation Periods . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2.1 Inclusion Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2.2 Hydrocarbon Generation and Expulsion Time of Source Rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2.3 Dynamic Oil and Gas Charging in the Great Baobab Oilfield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3 Main Controlling Factors of Hydrocarbon Enrichment . . . . . . . . . . . 7.3.1 ‘Below Source Plays’ are the Main Hydrocarbon Accumulation Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3.2 Compressional Inversion Anticlines are the Main Hydrocarbon Trap Type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3.3 Subaqueous Fan and Fan Delta Sand Bodies are Main Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3.4 Coupling of Felsic Basement Rock with a Strike-Slip-Extensional Environment Leads to the Widespread Development of Buried Hill Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3.5 Composite Sandstone-Basement Rock Traps in Uplifts Between Depressions is the Favorable Play for the Formation of Large Oilfields . . . . . . . . . . . . . . . . . . . . 7.3.6 The Northern Slope is the Most Favorable Oil and Gas Enrichment Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

299 299 300 317 325 333 334

8 Seismic Reservoir Prediction Technology . . . . . . . . . . . . . . . . . . . . . . . . . 8.1 Inversion Technology for Identifying Thin Sandstone Reservoirs in Areas with Igneous Rock Intrusions . . . . . . . . . . . . . . . 8.1.1 Fine Interpretation of Complex Fault Blocks . . . . . . . . . . . . . 8.1.2 Distribution Characteristics of Igneous Rocks . . . . . . . . . . . . 8.1.3 Reservoir Inversion in Strong Development Areas of Igneous Rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2 Characterization of Fan Body Boundaries Against High and Steep Backgrounds in Small Rifts . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1 Stratigraphic Sedimentary Characteristics . . . . . . . . . . . . . . . 8.2.2 Analysis of Petrophysical Characteristics of Reservoirs . . . .

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344 351 359 361 362 365

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8.3 Reservoir Prediction Technology for Basement Rock Buried Hills . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.1 Research of Seismic Forward Modeling . . . . . . . . . . . . . . . . . 8.3.2 Seismic Prediction Technology for High-Quality Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.3 Seismic Fracture Prediction Technology . . . . . . . . . . . . . . . . . 8.3.4 Evaluation of Favorable Reservoirs Using Logging-Seismic Synergy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Geological Evaluation and Interpretation from Logs . . . . . . . . . . . . . . . 9.1 Lithological Identification of Basement Rock Using Logging Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.1 Logging Response Mechanism of Lithology . . . . . . . . . . . . . 9.1.2 Qualitative Identification of Logging Lithology . . . . . . . . . . . 9.1.3 Quantitative Identification of Lithology Using Logging . . . . 9.1.4 Distinguishing Between Felsic and Mafic Rocks . . . . . . . . . . 9.1.5 Dominant Lithology Sequence . . . . . . . . . . . . . . . . . . . . . . . . . 9.2 Logging Evaluation of Oil Layers, Gas Layers, and Water Layers in Basement Rock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.1 Qualitative Identification of Reservoirs Using Well Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.2 Quantitative Interpretation and Classification of Basement Reservoir Parameters . . . . . . . . . . . . . . . . . . . . . . 9.3 Identification Technologies for Oil and Gas Layers . . . . . . . . . . . . . . 9.3.1 Fluid Property Diagnosis Using Data from Mud Logging, Coring, and Oil Test . . . . . . . . . . . . . . . . . . . . . . . . . 9.3.2 Quantitative Identification of Oil Layers from Gas Survey Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3.3 Relationship Between Oil Layers and Felsic Content, Wave Impedance, and Resistivity . . . . . . . . . . . . . . . . . . . . . . . 9.3.4 Lower Limit Definition of Oil Layers . . . . . . . . . . . . . . . . . . . 9.4 Wireline Logging Analysis of Ground Stress . . . . . . . . . . . . . . . . . . . 9.4.1 Elliptical Borehole Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.2 Induced Fracture Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.3 Fast Shear Wave Azimuth Method . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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397 397 399 407 423 426 429 430 430 432 435 437 445 446 446 458 474 475 475 475 478 481 481 481 482 485

Chapter 1

Introduction

The modern oil industry began to take shape in 1859. Since then, oil companies, many of which have become super-major international enterprises, have been conducting exploration, development, and other operations in almost every corner of the world. Imbalances determine the structure of the industry in the distribution of oil and gas resources, differences in levels of economic development between nations, the physical and economic dislocation between the countries which host resources and the countries where they are primarily consumed, and of course, the pursuit of profit by the oil companies themselves (Tong 2018). Transnational oil and gas exploration has been carried out intensively and continuously for more than 100 years, and the more accessible onshore blocks have now undergone many rounds of exploration. As a result, international oil companies have shifted their focus to deep sea and polar regions. The remaining onshore blocks are now challenging to explore for geological, geographical, and other reasons. The success rate of risk exploration projects worldwide has fallen to only 10%, and the probability of discovering large oil and gas fields is significantly reduced (Rose 2001). Since the beginning of China’s ‘reform and opening up’, particularly with the explosive economic development of the 1980s, domestic oil production has been unable to keep pace with the development of the national economy. The “go global” initiative, conceived as a path towards equitable sharing of the world’s oil and gas resources, represents a means to counter this shortfall and is an important factor in ensuring China’s national energy security (Tong et al. 2002). In 1992, following extensive research and discussion, the China National Petroleum Corporation (hereinafter referred to as CNPC) proposed three development strategies: “stabilizing the east, developing the west”; “developing oil and gas simultaneously”; and “implementing international operations”. CNPC accordingly embarked on the “go global” initiative. Facing competition from major international oil companies, CNPC formulated a three-phase strategy (Zhou 2004). During the initial exploration phase (1993– 1996), CNPC bid for and won small-scale projects in Papua New Guinea, Peru, Sudan (No. 6 area), Thailand, and elsewhere. This was followed by the ‘growth and development’ phase (1997–2002), during which CNPC obtained projects in the Blocks © Petroleum Industry Press 2023 L. Dou et al., Petroleum Geology and Exploration of the Bongor Basin, https://doi.org/10.1007/978-981-19-2673-0_1

1

2

1 Introduction

1/2/4 and Blocks 3/7 in Sudan, a service contract in Venezuela, the Aktobe project in Kazakhstan, and other large-scale exploration and development projects, driving a rapid increase in reserves and production. In 2003, CNPC entered the ‘scale expansion’ phase and began to engage in the field of exploration, taking considerable risks and striving to find “golden eggs”. Africa, a region with traditionally friendly relations with China, was one of the earliest strategic targets for CNPC’s “go global” strategy and has been the most successful in terms of exploration and development results, delivering considerable benefits for all partners.

1.1 Current Status of CNPC’s Oil and Gas Exploration Projects in Africa The African continent covers an area of 3030 × 104 km2 , one-fifth of the planet’s total land area. The continent features cratonic basins, foreland basins, passive margin basins, continental rift basins, Etc., with sedimentary basins covering an area of 585 × 104 km2 . Africa’s remaining recoverable oil reserves are 169 × 108 t, about 7.5% of total world reserves (Burke et al. 2003). Africa has the fourth largest oil reserves globally, ranking behind the Middle East, North America, and Central and South America. The remaining recoverable gas reserves are 14.3 × 1012 m3 , accounting for about 6% of the world’s total reserves (BP Statistical Review of World Energy 2017). In 2014, it was estimated that Africa had 137 × 108 m3 (or 10%) of the world’s undiscovered oil resources (excluding China) and undiscovered gas resources of 9.97 × 108 m3 (or 7.4%) of the world’s gas resources (again excluding China) (Tong et al. 2004). Africa is the first crucial strategic area for CNPC to “go global” in oil and gas exploration and development. The company has acquired more than thirty exploration and development blocks in 10 African countries: Sudan, South Sudan, Chad, Niger, Algeria, Libya, Tunisia, Mauritania, Equatorial Guinea, and Mozambique. Following exploration evaluation, CNPC withdrew from Block 17-4 in Libya, Blocks Adrar and 102/112 in Algeria, Block M in Equatorial Guinea, Blocks 12 and 20 in Mauritania, Blocks 13 and 15 in Sudan, Blocks 471 and 298 in Nigeria, and Block NK in Tunisia. There have been no oil or gas discoveries in Block Tenere in Niger. The SLK project in Tunisia is operated only as a small development project. Block 4 in Mozambique is a large-scale gas development block in which CNPC has only equity participation. Block 438B in Algeria is still in the evaluation stage. In Block Agadem in Niger, following the discovery of three small oil and gas structures, CNPC discovered a series of oil and gas fields and built up the productivity of 100 × 104 t/a, with second-phase productivity planning underway. Excluding development projects, the success rate of CNPC’s risk exploration projects in Africa has reached 30%, which is considerably higher than the world average. In addition to CNPC’s efforts, Sinopec Group (SINOPEC) and the China National Offshore Oil Corporation (CNOOC) have also acquired some exploration blocks in Africa (Corcoran and Dore 2005).

1.1 Current Status of CNPC’s Oil and Gas Exploration …

3

In the 1970s, Chevron began oil and gas exploration in Kenya, Sudan, and South Sudan, collecting large volumes of gravitational, magnetic, and 2D seismic data and drilling a batch of exploration and appraisal wells. Chevron identified the essential characteristics of the structures and petroleum geology of the basins, such as the Muglad and Melut basins in Sudan/South Sudan (Awad MZ 2015). They also discovered the Unity Oil Field in Block 1, the Heglig Oil Field in Block 2, two small oil fields (AbuGabra and Sharaf) in Block 6, and the small Adar-Yale Oil Field in Block 3. Blocks 1, 2, 4, and 6 are located in the Muglad Basin, and Blocks 3 and 7 in the Melut Basin. Due to safety factors, the small scale of the discovered oil fields, and the sharp decline in oil prices, Chevron gradually withdrew from Sudan and Kenya in the 1990s. Later, several smaller companies conducted petroleum exploration in these blocks but made no significant discoveries. The Sudanese government awarded Block 6 to CNPC in 1995, and Blocks 1/2/4 and Blocks 3/7 to joint operation companies (GNPOC and PDOC), composed of CNPC and other companies, in 1997 and 2000, respectively. CNPC held 40% equity of GNPOC and 41% of PDOC and was thus a significant contributor to introducing a new era of oil and gas exploration in Sudan. Under the leadership of CNPC, following more than 20 years of only moderately successful exploration, two oil fields with an annual output of 15 million tons each and one oil field with an annual output of 3 million tons were discovered and are now in production in Sudan and South Sudan. In addition, CNPC also participated in exploring Blocks 13 and 15 in the Red Sea in Sudan, undertaking seismic survey operations and drilling two wells. However, the company ultimately withdrew when no significant discoveries were made. In July 2011, North and South Sudan became separated countries (the northern part is now generally referred to simply as “Sudan”). As a result, the project in Blocks 1/2/4 and 3/7 was divided and re-designated as two separate projects (Fig. 1.1). With the experience gained from more than 20 years of petroleum exploration and development, we have succeeded in establishing geological and hydrocarbon accumulation models for the passive rift basins—the Muglad and Melut—in Sudan and South Sudan, which are significantly different from the active rift basins in eastern China (Tong et al. 2004, 2006; Dou et al. 2005). We have discovered a world-class giant oil field—the Palogue Oil Field—and developed efficient exploration support technologies specifically suited to the African geological environment. Overall, Sudan has been one of CNPC’s most successful overseas exploration ventures. The company’s success in Sudan/South Sudan has also provided theoretical and technical support for obtaining large-scale risk exploration blocks in neighboring Niger and Chad.

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1 Introduction

Murzuq Basin

Egypt

Libya

Red Sea

Algeria Kufra Basin Tenere Basin Block Bilma

Block Tenere

Block Erdis Faya Basin

Termit Basin

Sudan

Niger Block Lake Chad

Block Agadem

Boral Basin

Chad

Rawat Basin

Baggara Basin

Block 6

Bongor Basin

Blue Nile Basin

Eritrea

Blocks 3/7

Blocks 1/2/4

Nigeria Salamat Basin

Doba Basin

Benue Trough

Doseo Basin

Muglad Basin

Central African Republic

Cameroon

Democratic Republic of Congo Atlantic

Gabon

Congo

0

250

500km

Melut Basin

Ethiopia

South Sudan Mongalla Basin Central African Shear Zone

Basin

National boundary line

Blocks of CNPC

Coastline

Fig. 1.1 Distribution of CNPC’s operation blocks in the Central and West Africa

1.2 History of Oil and Gas Exploration in the Republic of Chad The Republic of Chad is a landlocked country in Central Africa. As a former colony of France, it gained its independence on August 11, 1960. It has an area of 128.4 × 104 km2 and is bordered by Libya, Sudan, Central Africa, Cameroon, Nigeria, Niger, and several other countries (Fig. 1.1). Chad has an essentially agricultural economy, being particularly noted for livestock farming. Due to frequent domestic conflicts over the years, its economy is comparatively undeveloped and has poor infrastructure. Chad is, in fact, one of the least developed countries in the world. Chad’s first national Petroleum Law was promulgated in 1962, creating a mining tax system for exploration contracts (Cordrey 1965). A modified Petroleum Law was issued in 2007, which altered the basic contractual model to one of production sharing agreements. In 1969, the Chadian government issued a national exploration license (excluding Block Erdis) to Conoco as a royalty contract. Shell, Chevron, Total, ExxonMobil, and other companies joined Conoco in this initial round of oil exploration. Due to continual wars and other factors, some of these companies withdrew over the years, leaving the final equity split between ExxonMobil (40%), Chevron (35%),

1.3 Exploration History of Permit H in Chad

5

and Petroliam Nasional Bhd (Petronas) (25%). The operating company was named EEPCI. In 2003, supported by loans from the World Bank and other institutions, three oil fields—Kome, Bolobo, and Mandoum—were produced. The 1070 km ChadCameroon oil pipeline was constructed, marking the beginning of z oil exports from Chad. The initial oil production was 910 × 104 t/a. In 2014, Chevron transferred its equity to the Chadian government for $1.4 billion. Nevertheless, by 2017, EEPCI’s annual production output had fallen to less than 300 × 104 t. In November 1996, according to the original license requirements, EEPCI retained eight oil fields and three oil-bearing structures in Blocks Doba, Doseo, and Lake Chad and the surrounding exploration areas and returned the remaining contract areas to the Chadian government. In the same year, the government combined these blocks with Block Erdis in the northeast to form a new block—Permit H—with an area of 43.924 × 104 km2 . The new block was awarded to Cliveden. In 2001, a Canadian company, EnCana, purchased 50% equity and exclusive operating rights in Permit H from Cliveden. In December 2003, CNPC and CITIC Energy (Hong Kong) purchased 25% of the shares in Cliveden, with each company thus indirectly obtaining 12.5% equity in Permit H as non-operators (Klett et al. 2005). In 2006, CNPC purchased the entire equity of Permit H from Cliveden, CITIC Energy (Hong Kong), and EnCana by increasing its holding three times, finally acquiring 100% equity in Permit H. CNPC became the operator of Permit H on January 12, 2007. At this time, a new entity was created—China National Petroleum International (Chad) Co., Ltd.—marking a new beginning for oil and gas exploration in Permit H in Chad.

1.3 Exploration History of Permit H in Chad The contract model for Permit H is a tax and royalty contract with an exploration period of 5 + 3 + 3 years. At the end of each exploration period, part of the original contract area must be relinquished to the government. The first relinquishing area should be 50% of the original contract area and the second 25%. Ultimately all areas except the development zone should be relinquished. Regarding the contract, the first exploration period ended on February 22, 2011. Whereas, in January 2011, the Chad government granted a 5-year extension for exploration in Permit H, a valuable additional time during which CNPC made several large-scale discoveries and achieved significant breakthroughs in exploring buried hills in the block. All or parts of seven separated sedimentary basins fall within Permit H. Six basins/blocks—Lake Chad, Madiago, Bongor, Doba, Doseo, and Salamat—are Mesozoic-Cenozoic rift basins developed under the influence of the Central African Shear Zone. Block Erdis in the north is a Paleozoic cratonic basin that is the southern extension of the Kufra Basin, which lies in Libya (Figs. 1.1 and 1.2). The petroleum geological research and exploration history of Permit H can be naturally divided into two major stages—exploration by the previous operators and

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1 Introduction

Fig. 1.2 Geographical location of Permit H in Chad

exploration by CNPC—according to completion of exploration workload, exploration discoveries, application of technology, and the results obtained by different operators.

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1.3.1 Exploration by Former Operators Before 1999, gravitational, magnetic, and 2D seismic data for Permit H had been sporadically gathered over the years. Three exploration wells had been drilled, one in Block Lake Chad and two in the Bongor Basin, all of which were dry holes. During Cliveden’s time as the operator, from 1999 to 2000, no physical workload was undertaken. From 2001 to 2006, EnCana served as the operator and acquired some 2D seismic profiles in the Bongor Basin, Block West Doba, and Block Madiago. EnCana drilled wells Mimosa-1, Mimosa-2, Kubla-1, and Baobab-1 in the Bongor Basin, but the only discovery was a thin, heavy oil pay in the Mimosa area. Wells Mimosa-1 and Kubla-1 penetrated the basement. 3D seismic data were collected in the Mimosa area. Well Acacia-1 was drilled in Block Lake Chad in 2005, revealing mainly Upper Cretaceous-Cenozoic sandstone and mudstone strata, intercalated with intrusive rocks. Nothing was discovered, and the well was abandoned. wells Figuier1, Karite-1, and Nere-1 were drilled in Block West Doba in 2006, but the only result was a very conventional oil pay found in well Figuier-1. As of 2006, oil testing was not conducted in any wells in Permit H (Peterson 1983). The previous operators failed to identify the main block, play, and hydrocarbon accumulation zone and were unsuccessful, making no commercial discoveries. EnCana was discouraged by lack of success and ceased exploration efforts, and the block was ultimately sold. During the period 2004–2006, when CNPC purchased shares in Permit H as a nonoperator, the concepts applied in selecting favorable blocks, exploration deployment, and evaluation of favorable prospects were changed markedly from the approach of former operators. We spent three years digesting the accumulated data, comparing, analyzing, and investigating Permit H in-depth, and carrying out comparisons with rift basins in eastern China and Sudan. During this intensive research and investigation, the conclusions reinforced CNPC’s determination to purchase the equity in Permit H outright. CNPC finally signed a stock purchase agreement with EnCana in Calgary on December 8, 2006, formally becoming the operator of Permit Hand and entering a stage of intensifying exploration. However, we adopted the maxim “no matter how difficult it is, we need to step forward from the beginning”. We understood that, since our predecessors had failed despite their considerable efforts over a long period, it was necessary to break away from the path they had taken and discard existing concepts if we would successfully obtain large-scale discoveries.

1.3.2 Exploration by CNPC The outright stock purchase and intensification of exploration of Permit H were accompanied by a deepening of geological research. Our research results guided the stock purchase and exploration deployment, and subsequent exploration discoveries have continued to supplement and improve our understanding of the geological conditions, resulting in a spiral of “practice–cognition–re-practice–re-cognition”. This

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self-reinforcing spiral swiftly resulted in the discovery of high-quality, large-scale oil fields, followed by rapid productivity construction. Chad thus became another successful risk exploration project for CNPC in Africa, following the company’s success in the Sudan region (Tong 2003). Shortly after taking the original equity shares in Permit H in December 2003, we carried out the processing and interpretation of gravity and magnetic data, interpretation of seismic data, and analyses of drilling cuttings and oil samples. Based on our new understanding of geological conditions and our evaluation of petroleum systems, plays, hydrocarbon accumulation models, and petroleum resources assessment, we established an exploration evaluation approach of “selecting basins, locating plays, and quick discovering”. To facilitate the selection process, we compiled a set of ten evaluation indices for basins and blocks that had undergone relatively little exploration. Exhaustive analysis of sub-basin structures, combined with a rapid evaluation of source rocks, plays, and traps, allowed us to systematically compare the seven basins in the block from three fundamental aspects: accumulation conditions, resource potential, and economic evaluation (Tong 2009). It was immediately apparent that Block Erdis, located in northern Chad, is a cratonic basin dominated by the Lower Paleozoic sediments. It may generate gas, but it is far from the market, the exploration is challenging, and the potential is small. In addition, the area is strewn with land mines and other explosive materials from the many years of conflict the area had suffered. Therefore, this area was identified as a candidate for the first block to be returned to the government under the exploration license. Block Madiago in central Chad is characterized by simple structure, strong inversion, poor accumulation conditions, small resource potential, and difficulty in discovering commercial oil fields. Blocks Doseo and Salamat in southeastern Chad have moderately favorable accumulation conditions and resource potential. Commercial discoveries can be expected in these areas, but they are far from the existing export pipeline, and the threshold for viable commercial discovery is consequently high. Block West Doba in southwestern Chad is part of a proven oil-rich basin—the Doba Basin—but the block itself is too small. Three exploration wells had already been drilled without making any large-scale discoveries. Thus, we considered this to be a ‘second-tier’ exploration block. The Bongor Basin is an entire sedimentary basin in Permit H. Two exploration wells were drilled in the basin in1974 and 1976 but abandoned. Nevertheless, the drilling data confirmed that the basin is a strongly inverted rift basin, with only the Lower Cretaceous preserved. The Upper Cretaceous has been eroded, with an erosion thickness of up to 2500 m (Genik 1992, 1993). At the beginning of the twenty-first century, the former operators drilled five exploration wells in the basin, generally aimed at targets with “above source” play. Good hydrocarbon shows were obtained in wells Mimosa-1 and Kubla-1. Nevertheless, the understanding from reservoir interpretation was that the reservoir was thin, and the physical properties of the oil were not favorable. MDT collected only small amounts of heavy oil and high pour-point oil without oil well testing, and in the end, it was considered that there was no commercial potential. At the same time,

1.3 Exploration History of Permit H in Chad

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the former operators had not carried out systematic stratigraphic research or identification and definition of structural units, so their geological understanding was not quite sophisticated. Between 2004 and 2007, researchers confirmed that the Bongor Basin is a rift basin with high-quality Lower Cretaceous lacustrine source rocks. The basin area is 1.8 × 104 km2 . Previous exploration had revealed only thin reservoirs, poor quality oil, and small-scale accumulations, but the exploration efforts had been somewhat cursory. Following close examinations, it was found that source rock conditions in the basin are excellent. In addition, the Bongor Basin is only about 210 km away from the Chad-Cameroon pipeline. The technical and economic evaluation indicated that the economic threshold for development was 200 × 104 t/a, which we regarded as a feasible objective. Therefore, the Bongor Basin was the preferred block for achieving exploration breakthroughs. Three breakthroughs in exploration and three great leaps in development were achieved in rapid succession. The breakthrough not only revealed a new exploration stratigraphic succession, the “under source” play, CARS (Dou et al. 2015) but also first discovered the high-yield conventional oil from the Precambrian granitic basement rocks, which offers an entirely new play for onshore oil and gas exploration in Africa (Dou et al. 2014, 2015). (1) 2007–2009: First commercial discoveries obtained in the “above-source play” After becoming the operator of Permit H in 2007, we first conducted systematic oil testing in wells Ronier-1 and Mimosa-3, which were completed in the same year. The commercial oil flow with a density of 0.9352 g/cm3 was obtained in well Ronier-1 at the drilling depth of 1057.00–1070.80 m. The Ronier structure was thus confirmed to have the potential for commercial production. Accordingly, the Ronier 3D seismic survey, covering an area of 503 km2 , was quickly conducted. Oil testing was carried out in well Mimosa-3 at 567.50–587.50 m, and a low-yield heavy oil with a density of 0.9725 g/cm3 was obtained. A new interpretation plan was drawn up based on paleontological analysis and regional comparison of penetrated strata in all exploration wells and repeated interpretation and demonstration of critical regional seismic profiles. For the first time, we consolidated the nomenclature of the strata in the Bongor Basin, bolstering confidence in the likelihood of discovering conventional oil. It was also proposed that fault blocks in the structural lows could have an exploration value and that exploration efforts should be reoriented as quickly as possible to focus on reservoir prediction. At the end of January 2008, based on 3D seismic data interpretation, an exploration well, Ronier-4, was deployed in the southern faulted anticline of the Ronier structure. There was an ongoing civil war in Chad, so the work was undertaken as quickly as possible, and completion was ahead of schedule. In June of that year, oil testing was conducted for the interval of drilling depths of 1452.80–1486.40 m. High-yield conventional oil with a density of 0.8500 g/cm3 was obtained, and Well Ronier-4 thus became the first well in the Bongor Basin with daily production exceeding 1000bbl. In March 2009, Well Prosopis-1 was deployed to the east of well Ronier-1. A high-yield oil flow was obtained during oil testing at 595.80–1619.80 m (in the

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K Formation), with a density of 0.86 g/cm3 , and the single-well total test output exceeded 7000 BOE/d. In April, oil testing was conducted in the P Formation in well Baobab-1, obtaining a commercial oil flow density of 0.8900 g/cm3 . well Baobab S-1 was deployed in the faulted anticline in the downdip part of the Baobab structure, and a high-yield conventional oil with a density of 0.8700 g/cm3 was obtained in the P Formation during oil testing. The stratigraphic comparison revealed that our success in the P Formation in well Baobab S-1 emphatically challenged the general understanding of “under source” play for identifying targets for high-yield conventional oil. This considerably opened up the potential field for deep play exploration and increased our confidence in the likelihood of discovering large oil fields. It was considered that exploration should shift further towards the northern part of the basin for seeking fan deposits in the syn-rift strata, in which there is a higher probability of finding thicker reservoirs in the P Formation. Hence, it was decided to extend the extent of the Kubla 3D seismic survey to the northwest, to cover the area north of the Baobab structure. This enabled the later rapid discovery of the Baobab NE and Baobab N reservoirs, saving a great deal of time circumventing the conventional incremental exploration process (Shi et al. 2014). From 2007 to 2009, contiguous oil and gas-bearing areas were confirmed in the Ronier, Maye, Baobab, and Mimosa areas. We achieved a “leapfrog” development by “breaking through the industrial oil flow barrier in 2007, breaking through the conventional oil barrier in 2008, and discovering high-yield and enriched blocks in 2009”. This series of successes provided a reliable reserve foundation for embarking on the detailed design and construction of an integrated upstream and downstream project. (2) 2010–2012: Rapid discovery of multiple large-scale oil fields using the “below-source play” concept to determine exploration targets In 2010, focusing on the fast proving of the Prosopis-Baobab play, the scale of the reserve was expanded to provide reserve guarantees for first-phase productivity construction and long-term stable production. In pre-prospecting, potential plays from the Naramay and Kubla 3D seismic survey, the Southern Steep Slope, the West Bongor Basin, Etc., were identified as potential breakthrough points, and exploration efforts were increased for new plays. In the large Baobab area, a new exploration concept of “delineation drilling and expanding reserves in the Baobab and Baobab S fault blocks, and drilling new targets to the northeast for pre-prospecting” was adopted. A total of nine wells were drilled; as a result, the oil-bearing area of Block Baobab S was expanded to 25 km2 . Well Baobab NE-1 is a risk exploration well based on “optimal acquisition, premium processing, and rapid to locate wells” (Rose 1987). According to logging interpretation, it was completed in July 2010, with the reservoir found to be 183 m thick. High production was obtained in the hole interval at 1434–1484 m in the P Formation during oil testing. In October of that year, logging interpretation of well Baobab N-1, deployed on the northern slope of the northern Baobab subdepression, revealed the reservoir to be 108 m thick. Daily single-well oil equivalent during oil testing reached 1900 m3 . Based on rapid accumulation research and oil–water contact prediction,

1.3 Exploration History of Permit H in Chad

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wells Baobab N-4 and Baobab N-8 were deployed in the downdip position. Logging interpretation of well Baobab N-4 indicated a reservoir thickness of 168.13 m. The reservoir in well Baobab N-8 was up to 288.84 m thick. This confirmed the discovery of two large oil fields—Baobab NE and Baobab N—with reserves per unit area of over 1000 × 104 t/km2 . The oil column height in the Baobab N-1 reservoir reaches 1000 m, indicating this is a sizeable lithologic trap, another significant discovery. The discovery of the large Baobab Oilfield further confirms the potential of the Lower Cretaceous P Formation reservoir, which benefits from the effective seal provided by the pure mudstone of the overlying M Formation, to form a prime “under source play”, an understanding which has served to boost our exploration efforts further. Comprehensive comparative analysis of drilling, seismic, geological, and regional gravity data has confirmed that the Daniela area in the eastern part of the northern slope and the Baobab N area have similar geological structures and source-reservoircap assemblages. Although an earlier well drilled in this area had failed, earlyidentified traps were not implemented, and the target strata, identified using different evaluation criteria, were not identical. Based on previous exploration experience, we once again implemented the advanced deployment strategy of “first 3D exploration and then drilling”. 3D seismic acquisitions were carried out successively in the Daniela and Lanea areas, and wells Daniela-1 and Lanea-1were drilled. Thick reservoirs were found, with high yields obtained during oil testing. In addition, oil fields such as the Phoenix, Raphia S, Moul, Mango, and Delo were also discovered, driving a rapid increase in reserves. (3) Bold exploration, major breakthroughs in buried hills in basement rock, and the opening up of a new exploration domain Large areas of Precambrian granites and metamorphic rocks are exposed in the CARS. They are the remnants of the basement of Meso-Cenozoic rift basins and have been widely drilled in different basins. When EnCana was the operator, wells Mimosa-1and Kubla-1 were drilled and completed in the basement rock of the Bongor Basin. Between 2007 and 2012, 61 wells were drilled into the basement rock, completed without significant discoveries. The wells were often drilled purely speculatively due to the difficulty of effective target identification and prediction in the basement rock. Since our major discoveries in the P Formation in 2009, buried hill exploration has become problematic for the project team. In October 2010, well Baobab C-1 was drilled. This well is located in the high part of the large Baobab Structure. The primary purpose of the well was to explore the P Formation sandstones confirmed on both sides. The designed well depth was 1500 m, with the top of the basement predicted to be 1400 m. Drilling revealed that sandstone is not developed in the P Formation in the well. The basement was encountered at 1131 m, 270 m before expected contact. In the second section, lost circulation occurred during drilling into the basement rock, with oil staining observed on cutting surfaces. Finally, the basement was drilled through for a further 61.86 m—a total drilling depth of 1192.86 m— and drilling was completed ahead of schedule due to the non-return of drilling fluid. A total of 230 m3 of drilling fluid was lost. The casing was run to 1132.50 m to the top of the buried hill, and the buried hill section was left as an open hole, leaving room

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for subsequent oil testing. In addition, varying hydrocarbon shows were observed in basement rock sections in wells Baobab E-2, Phoenix-1, Raphia S-6, Raphia S-8, etc., and circulation was again lost in these wells. Hydrocarbon shows and lost circulation in these basement rock sections suggest that the basement rock may represent another new play for future exploration (Dou et al. 2015). Given the leakage in the basement rock section of well Baobab C-1, and the difficulty of drilling, we invited some experts to the site to discuss the situation with them and learn from their experience of buried hill exploration in the Liaohe Basin in China. We also invited the CNPC Research Institute of Petroleum Engineering to research drilling and completion techniques for basement rock to provide technical assurance for the planned next step—drilling specifically into the basement rock. In 2012, following several demonstrations and extensive preparations for drilling and completion, we optimized well Lanea E-2 in the structural belt, where the Lanea Oilfield (P Formation) found during 3D seismic acquisition in Block Lanea. The primary target was designed as Horizon P, which also offered the opportunity to explore buried hills. It was predicted that the top of the P Formation would be encountered at 700 m and the top of the basement at 820 m. The design called for drilling 130 m into the basement and completion at 950 m. This was the first time that the basement of a well was identified in the drilling design as a secondary target in its own right, offering opportunities to understand better the geology and hydrocarbon show of the basement rock section. For the first time in drilling engineering, a tripleopening design was used, and underbalanced drilling equipment was moved to the site in preparation. On December 3, 2012, well Lanea E-2 was spudded in. The basement was encountered at 826 m, with moderate hydrocarbon shows. Due to the high density of the drilling fluid, gas logging was very weak, and leakage occurred. Third-opening was at 834 m. According to the hydrocarbon shows, the decision was taken to complete the well at 1190 m. Underbalanced drilling was conducted in the basement rock section, with a total leakage of drilling fluid of 309 m3 . In the light of logging interpretation, the reservoir in the well is 60 m thick in the P Formation and 80.57 m thick in the basement rock section. Open-hole oil testing of the basement rock section obtained high-yield oil flow, with an oil density of 0.8575 g/cm3 . The success of Well Lanea E-2 was a significant boost to our confidence in the exploration of buried hills. Drawing on the experience and understanding gained from drilling the well, old wells were re-examined, and further oil testing was carried out. In January 2013, oil testing was conducted in Well Baobab C-1, obtaining highyield oil flow in an open hole in the basement section. The density of the oil was 0.8498 g/cm3 . Later, oil testing was carried out in the basement section of Well Baobab E-2, and a high yield was once again obtained. With a high-yield oil flow obtained from both the Lanea E and Baobab C buried hills, it was considered that the Bongor buried hill reservoir as a whole could offer an excellent exploration potential and the distinct possibility of large-scale discoveries. A new exploration stage—buried hill exploration—had begun. In that year, five oil-bearing buried hill zones—Lanea E, Baobab C, Raphia S, Phoenix S, and Mimosa E—were discovered in rapid succession. On July 21, 2013, Well Baobab C-1 entered trial production. By

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the end of 2017, it had produced nearly 42 × 104 m3 of oil, with a water cut of less than 0.5%, confirming good development prospects for buried hill reservoirs. In June 2013, focusing on these major discoveries in the exploration of buried hills in Chad and deepening the study of accumulation conditions in buried hills in the Precambrian basement rock, CNPC’s Department of Science and Technology Management approved the project of Analysis of Accumulation Conditions and Favorable Target Evaluation of Granite Buried Hills in the Bongor Basin, Chad (2013D-0902). This project aimed to comprehensively analyze the geological conditions, reservoir characteristics, accumulation conditions, and hydrocarbon enrichment patterns of buried hill reservoirs in Chad. (4) Crucial discoveries made in peripheral blocks during extensional prospecting While making discoveries in the Bongor Basin, we also continued our intensive research in Blocks West Doba and Doseo, deploying both 3D seismic prospecting and infilling 2D seismic lines in Block West Doba, and carrying out some microbial exploration in Blocks Doseo-Salamat. Targets were optimized, drilling out, and some vital discoveries. Well Figuier-1 is an exploration well completed in August 2006 in the West Doba Basin. The Upper Cretaceous in that area is relatively shallow and lacks an effective seal. A large set of mudstone dominates the lower Cretaceous intercalated with thin sandstone, and the reservoir is not well developed. Reservoir interpretation originally suggested only one oil pay with a thickness of 2 m. In March 2011, in-depth analysis and logging re-interpretation were carried out. In the Lower Cretaceous Mangara Formation, re-interpretation indicated the presence of two oil pays with a thickness of 3 m and four gas pays with a thickness of 9 m. Oil testing at the hole interval at 1237.40–1238.77 m obtained a commercial oil flow with a density of 0.8324 g/cm3 , opening another new domain for exploration in Block West Doba. Between January and May 2014, exploration efforts targeted the Lower Cretaceous, and three wells were drilled: Moringa-1, Citrus-1, and Sena-1. Oil and gas layers were interpreted by logging and marked for oil testing. In April 2014, based on our previous research, Well Ximenia-1 was deployed in the steep slope of the northern Doseo Basin. Interpretation of logging data indicated 12 m/4 oil pays, confirmed by oil testing. These exploration wells reveal that the peripheral basins have exploration potential, and this new understanding has inspired confidence in stepping up the exploration of the peripheral blocks.

1.4 Experience of Efficient Exploration Over the past ten years, the discoveries made in the exploration of Permit H, especially in the Bongor Basin, have represented another leap forward for CNPC in oil and gas exploration in the West and Central African Rift System, following on from the successful exploration of rift basins in Sudan. Permit H has become one of the

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most successful high-risk exploration projects among CNPC’s wholly-owned overseas operations. The Permit H project not only constructed an entire integrated up and downstream petroleum industry for the nation of Chad—achieving energy independence for the country in doing so—but also opened up channels for oil export sales and facilitated the entry of Chad’s oil into the international oil market, guaranteeing rapid investment recovery. On June 29, 2011, the upstream and downstream integration project was put into production. The President of Chad stated: “Today is a day of historical significance for the people of Chad. We have won the victory in the battle for energy independence and have benefited from cooperation with China. CNPC is great! Long live Sino-Chad cooperation!”. In ten years of intensive research and exploration, based on the principle of “practice–cognition–re-practice–re-cognition”, we have been able to construct a geological model and a hydrocarbon accumulation model for the strongly inverted Bongor rift basin, which is quite different from the models developed for rift basins in eastern China and Sudan. We have also succeeded in integrating supporting technologies for efficient exploration in the unique African environment and have gained valuable exploration experience.

1.4.1 Implementing “Saturation Exploration” and Achieving Continuous Breakthroughs in New Strata and Frontiers Worldwide, exploration of stratigraphic-lithological traps is often the main objective in the intermediate and late stages of basin exploration and provides the leading source for reserve addition. However, exploration periods are generally short, only about 5–10 years. Accordingly, the rapid discovery of large-scale oil fields requires a “three-dimensional exploration” strategy. Thus, from the beginning, we set out to explore both structural and non-structural traps, shallow and deep strata, and conventional and unconventional reservoirs. We mainly focused on exploring stratigraphiclithologic traps (Beaumont et al. 1999). The scientific research team established an “identification technology for stratigraphic-lithological traps in strongly inverted rift basins” based on seismic data, well logging, and sequence stratigraphic studies. In 2010, for the first time, we discovered a high abundance stratigraphic-lithological trap on a monoclinic background—the Baobab N high-yield sandstone reservoir. Reservoir thickness in a single well reached 288 m. Since then, many other stratigraphiclithological accumulations, such as RS, have been discovered. Analysis of seismic and logging data from the reservoirs has allowed us to scientifically predict favorable factors for the hydrocarbon accumulation of the buried hill’s basement rock. In 2012, multiple buried hill targets were identified in basement rock, with drilling obtaining high-yield oil flow. This discovery represents the biggest buried hill oil field group in granite basement rock discovered during China’s overseas exploration efforts.

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1.4.2 Breaking the Routine and Accelerating the Pace of Exploration (1) Exploration discoveries greatly accelerated by the strategy of “3D seismic acquisition first and then drilling exploration well” Oil and gas exploration in Chad faces considerable challenges in commercial terms, construction, and security—such as short contract periods, inability to collect seismic data during the five months long annual rainy season, harsh field operating conditions, long cycles of cargo transportation, high operating costs, etc. In addition, there are technical challenges posed by significant differences in many of the acquisition parameters of 2D seismic data collected by the previous operators over the years (Lawyer and Kay 1984). This has led to great variations in data quality and mis-tie for different years. Conventional exploration usually adopts the procedure of 2D seismic deployment first, followed by the deployment of exploration wells. 3D seismic exploration is generally only carried out after potential commercial discovery has been obtained from exploration wells. This process often takes 1–2 years to drill evaluation wells, significantly prolonging the exploration cycle. With this approach, it is impossible to quickly investigate favorable plays and targets in a large block area or to conduct exploration evaluation on multiple favorable plays. Consequently, the strategy must be adjusted, and we have established the principle of “scientific deployment and efficient implementation” as the key to the rapid discovery of large oil fields. In the favorable plays, “3D seismic deployment first, then exploration wells” permits more rapid exploration operations. It is based on an exhaustive analysis of basin fill and structure. Analyzing essential petroleum geological conditions in the basin—such as source rock, reservoir, and caprock evaluation—allows us to identify and optimize favorable structural plays in basins quickly. Favorable structural perspective plays are thereby marked for detailed investigation by combining high-quality seismic data and evaluating actual geological conditions in planning exploration projects. This method has the advantages of “accurate target selection, fast exploration, discovery, and short exploration cycle”. It also provides more reliable seismic data for three-dimensional exploration and lithological exploration, significantly shortening the timescales required for exploration and discovery. From 2007 to 2012, in the northern slope of the Bongor Basin, rapid exploration deployment on the “3D exploration first, then drilling” principle was carried out. A total of five 3D seismic deployments were completed, according to the new exploration strategy of “3D exploration first and then exploration wells”. A high-yield oil flow was obtained in the first exploration well of each of the five rounds. The significant beneficial effect of the new exploration strategy was immediately confirmed, and the exploration and discovery cycle was considerably shortened (Fig. 1.3). In the first half of 2007, 2D seismic data was used to map the Ronier structure on the northern slope of the main sub-basin, resulting in an exploration breakthrough with the discovery of the Ronier Oil Field, which has a structural-lithological accumulation. Subsequent 3D seismic coverage revealed the plane characteristics of the

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Fig. 1.3 “3D seismic acquisition first, then drilling exploration well” seismic work area and distribution of key exploration wells in the northern slope

structure to be quite different from the two-dimensional structure map. The 3D structure map showed that the structure is fragmented and that fault blocks are more developed. This more detailed and reliable data will provide support for further well deployment. The discovery of the Ronier Oil Field strengthened our confidence that gradually shifting the exploration focus to deep strata and conventional oil would be a rewarding strategy. In the second half of 2007, a comprehensive geological analysis of the Maye area (adjacent to the Ronier Oil Field) indicated that the Maye area is close to the marginal part of the current residual basin. It has excellent petroleum geological conditions, near source rock, provenance, and good reservoir development. However, the faults are complex, and the combination is difficult to interpret. If the acquisition of 2D seismic data by infill first carried out, then, after processing and interpretation, an exploration well was deployed, and only then were3D seismic exploration deployed for a full evaluation of development potential, the whole process would have taken at least 2–3 years. Based on the judgment of the area’s general oil and gas potential, and without drilling, deployment of the “3D exploration first and then exploration well” strategy was boldly proposed. In October 2007, 3D seismic exploration was deployed in the Maye area (Fig. 1.4). The results of 3D seismic interpretation showed that the configurations of the faults and traps are quite different from those suggested by 2D seismic interpretation. Guided by the new 3D structural map, Wells Prosopis C-1 and Prosopis-1 were drilled in December 2008 and March 2009, respectively. Testing in the K Formation obtained a high-yield oil and gas flow, confirming the discovery of the Prosopis Oil Field. The discovery of this oil field boosted exploration confidence and reinforced our belief in the deployment strategy of “3D seismic exploration first, then exploration well”. As long ago as 1974, a former operator had drilled a dry hole—Naramay-1— in the Naramay area. The area features a NE-trending strike-slip fault. 2D seismic

1.4 Experience of Efficient Exploration

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(b) 3D time-structural map

Fig. 1.4 Comparison of 2D and 3D time-structural maps on the top lower Member of the K Fm. in the Maye area

profiles and structural maps show that faults are well developed in the area and that the structure is highly complex. We considered that the failure of the exploration well may have been due to a failure to understand the structure entirely. Accordingly, to identify the optimum drilling target more accurately, our new deployment strategy of “3D seismic first” was implemented in the area. In October 2008, 3D seismic data was acquired in the Naramay area, and Well Cassia N-1 was targeted according to the new structure map. Drilling was completed on December 15, 2009, with logging interpretation revealing 51.21 m thick/12 oil pays and 12.81 m thick/4 gas pays, with the third and fourth oil pay obtaining a high-yield oil and gas flows in testing. The successful exploration of these two areas using 3D seismic acquisition indicates that the concept of deploying “3D seismic exploration first and then drilling” is highly effective for areas with special petroleum geological conditions and highly complex structures. Data acquisition and well deployment using 3D seismic were carried out in three areas from 2009 to 2011, and a high-yield commercial oil flow was obtained in the first exploration well anytime. In October 2009, 3D seismic data was collected in the Kubla area to the east. A previous operator had already drilled an exploration well—Kubla-1—in the work area in 2004, which was abruptly completed when the basement rock was encountered. The 2D seismic profile does not clearly show the top surface of the basement, and the fault combination is challenging to determine (Fig. 1.5a). Using conventional 3D seismic exploration, the top of the basement can be clearly explained, and the interpretation of sedimentary strata and fault combinations is also more accurate (Fig. 1.5b). Not only was the Kubla structure found to be oil-bearing, but, in addition, the Baobab NE fault-nose structural oil reservoir, the Baobab N large-scale lithological oil reservoir, and the Phoenix and Raphia large-scale structural-lithological oil reservoir were all discovered. Based on the Daniela 3D seismic data collected in the course of eastward expansion in October 2010, oil fields such as the Daniela were discovered. Based on the Daniela E (Lanea) 3D seismic data collected in October 2011, the Lanea Oil Field, with a

18

1 Introduction

scale of hundreds of millions of tons, was discovered, and an entirely new domain of the buried hills play was opened up for further exploration (Fig. 1.6). Figures 1.4, 1.5, and 1.6 show apparent differences in horizon interpretation, fault combinations, and trap configurations between 2 and 3D seismic interpretations. If Well Kubla-1

TWT (ms)

500

1000

1500

2000

(a) 2D seismic profile Well Kubla-1

TWT (ms)

500

1000

1500

2000

(b) 3D seismic profile Fig. 1.5 Comparison of 2D seismic profile a and 3D seismic profile b through well Kubla-1

1.4 Experience of Efficient Exploration

19

400

2-816

625

TD-0

600 1200

100

875

800

750

0

Daniela E-2 2

Nafoura-1

2-82 TD-0

2

213

TD-03 -87

-08-

1400

CNPC

BN119E

X

TD-02

-820

1400

11 25

1000 1000

1500

1400

1000

800 TD-0

EOC-TD-05-215

7

1375

Lanea-1

1000

EOC-TD-05-213

250

Daniela S-2

800

1200

1000

3-86

1500

TD-0

1400

14 00

00

2-824

1200

14

1250

Lanea-2 20

00

10

00

0

5

-80

7

81 1

22 00

Lanea SE-1

2125 2250 2375 2500 2625

Guiera-1

4

2-

3-86

-0

TD-0

TD

00 24

-02

50

5-211

TD

22

TD-0

Lanea E-4

212

2200

EOC-

Lanea E-1 1875

800

1200

65

100

1400

1600

3-8

2125

0 180

TD -0

(a) 2D time-structural map

2850

25

26

2750

2750

(b) 3D time-structural map

Fig. 1.6 Comparison of 2D and 3D time-structural maps on the top P formation in the Lanea E area

2D infill seismic lines were first deployed and then exploration wells were drilled based on previous seismic lines, the same discoveries might be made, but 3D seismic deployment would have been delayed by 1–2 years. Thus, applying the exploration strategy of “first 3D seismic deployment and then drilling” in the northern slope of the Bongor Basin has accelerated the speed and improved the exploration success rate, significantly shortening the cycle of exploration and discovery. This confirms the scientificity and high efficiency of the new exploration strategy in exploration areas with special petroleum geological conditions and complex geological conditions. (2) Bold deployment of secondary 3D seismic exploration and fine characterization of the basement top and internal architecture of buried hills “Wide-azimuth, broadband and high-density” is a new geophysical seismic exploration technology. Vast azimuth data can improve illumination, enhance imaging accuracy of the top surfaces of high and steep buried hills, and provide a reliable foundation for processing and predicting the development characteristics of intraburied hill faults or fractures at various levels of azimuths. “High-density” refers to the acquisition of smaller bins with smaller sampling intervals. It is achieved using high shot density, which significantly increases sampling density, signal-to-noise ratios, and seismic data’s induced (receiving) energy. It also prevents aliasing in seismic signals and achieves complete sampling of small-scale geological phenomena such as weak reflections and diffraction in the interiors of buried hills. It is also better at converging multiple images, which is conducive to the detailed and accurate imaging of the top surfaces of steep buried hills. The core function of broadband excitation and reception is the excitation, reception, and application of low-frequency seismic

20

1 Introduction

emissions. Low-frequency emissions are characterized by strong penetration, ability to eliminate noise pollution, high energy stability, etc. Expanding low frequencies improves deep reflection energy from the interiors of buried hills. It also increases the relative bandwidth, enhancing the interpreter’s ability to characterize geological details and changes in the interiors of buried hills. For instance, the weathering crust on the top of buried hills, small faults, development zones of fractures and caves within buried hills, etc., are difficult to identify and describe using conventional seismic data. In 2013 and 2014, 3D seismic acquisition with “wide-azimuth, wideband, and high-density” was deployed in Baobab C, Phoenix S, and Lanea E, a series of buried hill oil reservoirs discovered in the northern slope of the Bongor Basin. The acquisition parameters were significantly improved compared with conventional 3D seismic data (Table 1.1). The processing and interpretation results effectively guided the evaluation and drilling of the buried hills and provided more detailed and credible data for reserves estimations and the evolution of the development plan (see Chap. 8). (3) Geological data provides a guarantee for rapid evaluation and development of oil fields The purpose of overseas oil and gas exploration is not only to find large-scale reserves but, more importantly, to “quickly discover oil show and put into production”. It is generally best to put wells into production as early as possible. Hence, it is necessary to obtain accurate geological data in the exploration stage and consider the intake of data required for the development. For example, we need to consider the data required for surface engineering and connection to the export oil pipeline in the appraisal stage. We also need to ensure that the data required to prepare feasibility reports on all aspects of projects can be obtained quickly and accurately. With Chad’s relatively poor local infrastructure and under-developed economy, no qualified laboratory can provide reliable analysis and testing. All samples must be transported by air to a third country for analysis. Obtaining transport licenses, extended transportation periods, etc. significantly increase the time required for analysis. Accordingly, samples must be collected in time, properly stored, quickly transported, and qualified for analysis to ensure the timely preparation of relevant research reports and feasibility studies. Samples of paleontological strata, source rocks, reservoirs, caprocks, etc., are collected during the exploration well stage, and samples of oil, gas, and water are collected during the testing stage to ensure that the timescales required for various analyses are met. All samples from the oil fields of the Chad project are quickly transported to China and provided to technical staff involved in geological engineering, surface engineering, and pipeline engineering, who perform analysis to ensure scientific preparation of feasibility reports and the smooth progress of engineering construction. It only took four-and-a-half years from the initial discovery of oil fields in 2007 to establish the integrated upstream and downstream project. During this period, the pace of exploration and development was not impacted by a lack of data. In 2013, the planned overall development target of 600 × 104 t/a was achieved. In addition, by that time, development and research work in the buried hill oilfield was also in full swing.

1.4 Experience of Efficient Exploration Table 1.1 Comparison of parameters of “wide-azimuth, wide-band and high-density” and conventional seismic acquisition and geometry in Chad

21

3D seismic exploration with “wide-azimuth, broadband and high-density”

Conventional 3D seismic exploration

Geometry

28 lines × 10 shots × 320 traces

16 lines × 5 shots × 100 traces

Largest cross line distance (m)

3487.5

2475

Vertical largest 3035 geophone distance (m)

1975

Largest geophone distance (m)

3166

5297

Bin (m × m)

12.5 × 12.5

25 × 25/12.5 × 12.5

Number of receiving traces (trace)

8960

1600

Perpendicular offset (m)

125

250

Shot point spacing 25 (m)

50

Seisline spacing (m)

250

250

Geophone station spacing (m)

25

50

Azimuth (°)

15

15

Fold

448

80/20

Types of seismic source

Vibroseis

Vibroseis

Excited vibrator vehicle -time

1-2 vibrator vehicles × 1 time

4 vibrator vehicles × 2 times

Recording length (s)

6

6

Sweep length (s)

12

10

Sweep frequency (Hz)

4 ~ 80

8–80

Aspect ratio

0.87

0.6

Shot density (Ten thousand pairs/km2 )

286.7

12

22

1 Introduction

(4) An excellent scientific research team and top-quality scientific research are the basis for rapid discovery of large-scale oil fields The project company also holds various technical symposiums and seminars, large and small, and other professional activities related to exploration projects. Our final decisions regarding exploration deployment, implementation plans, dynamic adjustments, sampling plans, content analysis, etc., are all made after carefully considering the opinions of other professionals, often expressed and discussed in the environment of technical symposiums. The project company has a solid technical team, including geological, seismic, logging, mud logging, and other specialists. We often hold exchange meetings on Saturdays to discuss exploration technology; we not only analyze exploration dynamics but also exchange understandings of geological research, often in the form of “brainstorming” sessions. During these sessions, news and views on research progress are exchanged, questions raised, and drilling strategies adjusted according to the latest drilling dynamics, seismic interpretation plans, coring and sampling plans, etc. Moreover, scientific research personnel from the overseas center, the principal scientific support institution for the project, actively participate in the project. They not only participate in technical exchanges with the project company but have also integrated into the project itself, forming a team of their own. Front-line technicians use their vacation time to communicate with technical support institutions in China, forming a genuine scientific research team with “integration of scientific research-production, integration of front and rear, and integration of Party A and Party B”. Support units undertake cooperative projects, but do not only study the projects. They provide timely analysis and interpretation results of samples based on the needs of the project company, engage in technical exchanges, and report for approval after reaching a consensus. (5) Strongly inverted basins should be viewed dialectically Geologically, strongly inverted basins are often unfavorable for preserving oil and gas and are not physically conducive to forming large oil and gas fields (Macgregor 1995). When experts first examined Permit H in Chad, many believed that only heavy oil discoveries would be made in the Bongor Basin. They considered that, because the basin had experienced strong inversion, it was unlikely that there would be any large-scale conventional oil fields. Consequently, they gave the impression to the Chad government that it would be difficult, expensive, and probably futile to explore thin oil in the basin. Nevertheless, there are two sides to everything. The adverse effects of inversion have received too much attention in the past, and its positive effects have been largely ignored. However, by thinking about the problems positively, we established new understandings gathered new experiences, and made surprising discoveries. Strong inversion causes basins to uplift, resulting in significant erosion, which may lead to the destruction of shallow plays, hydrocarbon losses from reservoirs caused by intercommunication of faults, and formation of biodegraded heavy oil reservoirs, etc. These are undoubtedly negative factors. Nevertheless, the positive effect of strong inversion is that it can increase the amplitude and scale of traps. Oil and gas can

References

23

migrate and accumulate again, forming larger reservoirs. More critically, if there has been erosion following uplift, deep “below-source plays” that are difficult to drill (for example, in the Muglad, Melut, Doba, and other basins) become much shallower and much more accessible (Lirong et al. 2013). A reduction of 1000– 2000 m (a typical range for surface erosion of uplifted strata) in drilling footage in a single well can reduce the investment required for drilling and completion. Our ten years of exploration have proven that, although the Bongor Basin has experienced strong compression, uplift, and denudation, large-scale oil fields such as the Great Baobab Oil Field can still be found. More than 90% of the reserves in this field are thin oil, and individual well production is high. The single well cost is much lower than that of the surrounding projects, which significantly improves the economic feasibility of the Permit H project. In the past, due to their great burial depths in peripheral basins, “below-source plays” were rarely drilled. Occasionally, conventional oil reservoirs were found, but their development potential was small. It was considered difficult to find thick oil reservoirs in the early stages of exploration in the Bongor Basin. However, exploration concepts and strategy have changed, and exploration shifts to the margins of the inverted residual basin and “below-source play” to explore subaqueous fans and fan delta sand bodies of the early rift period to find thick sand bodies. Exploration practice has confirmed that the thickest oil reservoirs are distributed in the Baobab N and Baobab NE areas, with a net reservoir thickness of 288 m and single well daily production of over 7000 barrels. After we had obtained high-yield conventional oil shows from Well Ronier-4, the then Minister of Petroleum of Chad, Mr. Nasser, published an article in a national newspaper, Progress, on August 14, 2008, praising CNPC for carrying out exploration in the Bongor Basin, which, in the past, the experts had been led to believe was impossible.

References Awad MZ. Petroleum geology and resources of the Sudan. Berlin: Geozon Science Media UG; 2015. Beaumont EAF, Norman H, Edward AB, et al. Exploring for oil and gas traps; 1999. Burke K, MacGregor DS, Cameron NR. Africa’s petroleum systems: four tectonic ‘Aces’ in the past 600 million years. Geol Soc Lond Spec Publ. 2003;207(1):21–60. Cheng DS, Dou LR, Xiao KY, et al. Origin of high acidity oils in the intensively inversed rift basin,Bongor Basin. Acta Petrologica Sinica. 2014. Dou L, Wei X, Wang J, et al. Characteristics of granitic basement rock buried-hill reservoir in Bongor Basin, Chad. Acta Petrolei Sinica. 2015;36(8):897–904 and 925. Corcoran DV, Dore AG. A review of techniques for the estimation of magnitude and timing of exhumation in offshore basins. Earth Sci Rev. 2005;72(3):129–68. Cordrey EA. Petroleum development in central and southern Africa. AAPG Bull. 1965;49:1257–91. Genik GJ. Petroleum geology of Cretaceous-Tertiary rift basins in Niger, Chad, and Central African Republic. AAPG Bull. 1993;77(8):1405–34.

24

1 Introduction

Genik GJ. Regional framework, structural and petroleum aspects of rift basins in Niger, Chad and the Central African Republic. Tectonophysics. 1992;213(1):169–85. Ke W, Tong X, Wen Z, et al. Hydrocarbon geological characteristics and potential prospect of Basins in Bengal Gulf West[J]. J Southwest Petroleum University (Science & Technology Edition), 2014. Klett TR, Gautier DL, Ahlbrandt TS. An evaluation of the US Geological Survey world petroleum assessment 2000. AAPG Bull. 2005;89(8):1033–42. Lawyer LC, Kay BV. The challenge of the Sudan. Lead Edge. 1984;3(2):26–8. Lirong D, Dingsheng C, Li Z, et al. Petroleum geology of the Fula sub-basin, Muglad Basin, Sudan. J Pet Geol. 2013;36(1):43–59. Lirong D, Kunye X,Yong H. Petroleum geology and a model of hydrocarbon accumulation in the Bongor Basin, the Republic of chad, ACTA petroleiSinica. 2011;32:3 Macgregor DS. Hydrocarbon habitat and classification of inverted rift basins. Geol Soc, London, Spec Publ. 1995;88:83–93. Peterson JA. Assessment of undiscovered conventionally recoverable petroleum resources of Northwestern, Central, and Northeastern Africa (including Morocco, Northern and Western Algeria, Northwestern Tunisia, Mauritania, Mali, Niger, Eastern Nigeria, Chad, Central African Republic, Sudan, Ethiopia, Somalia, and Southeastern Egypt). Geological Survey, Missoula, MT(USA); 1983. Rose PR. Dealing with risk and uncertainty in exploration: how can we improve? AAPG Bull. 1987;71(1):1–16. Rose PR. Risk analysis and management of petroleum exploration ventures. AAPG; 2001. p. 17–48. Shi ZS, Wang TQ, Fang LH, et al. Study Exploration Potential and Transformation of Muglad Basin and Melut Basin on Basis of Analogy. China Petrol Explor. 2014;29(2):67–76. Tearpock DJ, Bischke RE, Brewton JL. Quick look techniques for prospect evaluation. Subsurface Consultants & Association; 1994. Tong XG, Dou LR, Tian ZJ. Strategies of international petroleum exploration of Chinese petroleum companies. China Petrol Explor. 2004;9(1):58–64. Tong XG, Li HW, Xiao KY, et al. Application of play quick analysis technique in oversea basins with low-degree exploration. Acta Petrolei Sinica. 2009;03:317–23. Tong XG, Zhang GY, Wang ZM, et al. Distribution and potential of global oil and gas resources. Pet Explor Dev. 2018;45(4):727–36. Tong XG, Dou LR, Tian ZJ. Research on china’s transnational oil and gas exploration and development strategy in the early 21st century. Beijing: Petroleum Industry Press; 2003. Tong XG. Hydrocarbon accumulation and exploration mode of melut basin in sudan. The 4th World Chinese Conference on Geological Sciences; 2002. Tong XG, TIAN, PAN, et al. Geological mode and hydrocarbon accumulation mode in Muglad passive rift basin of Sudan. Acta Petrolei Sinica. 2004; Tong X. Petroleum geologic property and reservoir-forming pattern of Melut Basin in Sudan. Acta Petrolei Sinica. 2006;27(2):1–5.

Chapter 2

Regional Geological Characteristics of the Central African Rift System

The African Plate comprises several ancient cratonic (stable continental) nuclei. These Archean cratonic nuclei were formed 3.8–2.5 billion Ma ago. They have experienced multiple stages of continental crust accretion and orogenic movements and developed large quantities of magmatic rocks around 560 Ma. The cratonic nuclei were torn apart by a series of gigantic shear zones and orogenic belts but re-converged during the formation of the Gondwana supercontinent about 550 Ma, forming the precursor of the present-day African continent (Cahen et al. 1984; Key 1992). During the Pan-African movement (750–550 Ma), Africa became a single craton, and a series of large basement linear tectonic belts formed (Guiraud et al. 2005). These tectonic belts controlled and influenced the rejuvenation of the Phanerozoic structure and the formation and evolution of the basins in the rift systems of the African continent. The tectonic activity that accompanied the disintegration of Gondwana and the opening of the South Atlantic in the Early Cretaceous led to the formation of three subplates in Africa: the West African subplate, the Nubian subplate, and the South African subplate (Kogbe 1980). A series of sedimentary basins developed along the boundaries between these subplates, the West and Central African Rift System (WCARS) (Fig. 2.1). The interaction of the three subplates in the Mesozoic and Cenozoic created a few stress fields acting in different directions in various parts of WCARS. Simultaneously, some basins were extending while others underwent tension, pull-apart, tension-shear, compression-shear, compressional inversion, etc. (Fairhead et al. 2013). WCARS extends from the Mali Gao Graben on the West African coast to the Anza Basin of Kenya in East Africa. It is around 7000 km long and can be further divided into the West African Rift System (WARS) and the Central African Rift System (CARS) (Vail 1972). The major difference between the two is that, in the Late Cretaceous, WARS was filled with a set of marine sediments, while CARS was filled with continental deposits (Genik 1993). In recent years, a series of oil and gas fields have been discovered in the Termit Basin of WARS (the section within Chad is called Block Lake Chad), and a wealth of oil and gas show has been obtained in the Chad Basin and the Benue Graben, and a large number of oil and gas fields have also been discovered in the Doba-Doseo Basins in CARS and the © Petroleum Industry Press 2023 L. Dou et al., Petroleum Geology and Exploration of the Bongor Basin, https://doi.org/10.1007/978-981-19-2673-0_2

25

26

2 Regional Geological Characteristics …

Fig. 2.1 Schematic diagram of WCARS evolution. From Fairhead et al. (2013)

0

Libya

Algeria

500km

Egypt

Kafra Tenere Red Sea

Mali

Sudan Niger

Chad

Termit

Bornu

Nigeria Bi da

Yola

ue

n Be

Nere--1 Figuier--1

Khartoum Blue Nile

White Nile

Acacia--1

Baggara one ear Z n Sh frica Ronier--1 A l tra Cen Muglad Bongor Salamat Doseo South Sudan Doba Central African Republic Jonglei

Eritrea

Melut

Ethiopia Loelli

Atlantic Ocean

Mongalla

Cameroon Democratic Republic of Congo

Kenya Anza

Central African Shear Zone

National boundary

West African Rift System

Sampled well location of intrusive rock

Uganda Tanzania

Indian Ocean

Fig. 2.2 Distribution of the main rift basins in WCARS. Modified from Genik (1993)

Muglad, Melut, the Blue Nile, other basins in Sudan/South Sudan, the Anza Basin in Kenya (Fig. 2.2) (Bang et al. 2011). WCARS has become a crucial petroleum province of the African continent, with CARS having more oil and gas resources than WARS (Achauer et al. 1992).

2.1 Regional Tectonic Characteristics

27

2.1 Regional Tectonic Characteristics As its name suggests, situated in the heart of the continent, the Central African Shear Zone (CASZ) is a pan-African active zone lying between the Congo Craton and the Nubian Craton (Schandelmeier and Pudlo 1990). It is a huge lithospheric transformshear zone, stretching 4000 km from the Gulf of Guinea in the west, passing through Cameroon, southern Chad, and the Central African Republic to Sudan and South Sudan in the east, and then into Kenya to the south (Makris and Rihm 1991). CASZ is part of the same fault zone as the Pernambuco dextral shear fracture system in Brazil, formed during the Pan-African orogenic period (Bumby and Guiraud 2005). Dextral strike-slip extension of CASZ formed a series of Meso-Cenozoic rift basins, including the Bongor, Doba, Doseo, Salamat, Baggara, Muglad, White Nile, Blue Nile, Khartoum, Rawat, Melut, and Anza Basins (Fig. 2.2) (Mascle et al. 1988).

2.1.1 Basement Rock Characteristics Formation of the Precambrian Basement rock Regardless of specific age or location, the Basement rock of CASZ is a metamorphic or igneous rock combination unconformably covered by a sedimentary sequence (Landes 1960) and has provided the foundation for the formation and evolution of the basins. Basement rock outcrops with complex lithologies are found across the continent. The active zone west of 14 °E predominantly consists of acidic igneous and metamorphic rocks, and the thermal metamorphic zone east of 14 °E is primarily acid plutonic outcrops (Windley 1984). Precambrian granite, granodiorite, granitic gneiss, etc. outcrop widely in southern Chad. Precambrian marble is locally developed. The lithologies of the Basement rock exposed in two exploration wells in the Doba Basin are granite, gneiss, schist, pegmatite, and granodiorite. Rb/Sr analysis of granite outcrops in the western Doba Basin shows that it was formed at 481 ± 23 Ma (Genik 1992). The basement in South Sudan and southern Sudan comprises Precambrian granite, granodiorite, granitic gneiss, amphibolite, graphite-schist, marble, quartzite, etc. (Vail 1978). The Muglad and Melut Basins basement primarily consist of granite and granodioritic gneiss formed at 540 ± 40 Ma (Schull 1988; GRAS 2005; Awad 2015). Precambrian marble has also been drilled in Well Bamboo AG-1 in the Muglad Basin, and Precambrian marble outcrops with developed fractures have been found in northern Sudan and southwestern Chad (Klitzsch 1984). Strengthen of the principal basement contours and basement faults of the PanAfrican Craton predating Cambrian determine the strike and evolution characteristics of the Cretaceous Central African rift (Christie-Blick and Biddle 1985). Two sets of basement fault systems—WNW-ESE-trending and NE-SW trending—developed in the area (Genik 1992; Bumby and Guiraud 2005). Interpretation of high-resolution aeromagnetic data from the Yola Rift east of the Benue Graben reveals that the major basement faults may have formed in the Precambrian, generally striking NE-SW with

28

2 Regional Geological Characteristics …

Fig. 2.3 Precambrian crystalline rock outcrops with dual-layer structure

small strikes running N-S, NW-SE, and WNW-ESE (Ogunmola et al. 2016). These basement structures controlled the formation and evolution of the Late Mesozoic rift basins (Girdler et al. 1969). Weathering and Denudation of Basement Rock During the Cambrian-Jurassic Central Africa was in a stable platform stage during the Cambrian-Jurassic, with weak fault activity and an arid climate (Bumby and Guiraud 2005; Guiraud et al. 2005). The Basement rock was exposed in large areas, mainly by physical weathering, forming extensive planation surfaces. Outcrop observations reveal a weathered layer 10–50 m thick on the surface, composed of stones of varying sizes, formed by large-scale spherical weathering (Wilson and Guiraud 1992). These stones cover massive crystalline rocks and combine them to form an obvious double-layer structure (Fig. 2.3). Upper Jurassic coal measure strata were drilled in the Blue Nile Basin (Guiraud et al. 2005), and two small gas-bearing structures were discovered (Awad 2015). In East Africa, rift strata of the Karoo age (during the Early-Middle Mesozoic) developed under the Cretaceous rifts in the Anza and other basins and are in regional unconformity contact with the overlying Cretaceous rift sequence (Liu and Chen 2014).

2.1.2 Formation and Evolution of Mesozoic-Cenozoic Rift Basins CASZ is a fault zone composed of a series of strike-slip faults. Fault activity during the Late Mesozoic strongly influenced and controlled the formation and evolution of the basins, which have apparent strike-slip-tension structural characteristics. Regionally, CASZ experienced three rift cycles (Binks and Fairhead 1992). The development and evolution of the basins in different parts of the zone were not only controlled by

2.1 Regional Tectonic Characteristics

29

basement faults but were also affected by the movement of the three major subplates relative to each other, as well as plate movements on a larger scale (the European and Arabian plates, among others). The filling and tectonic styles of the strata have also changed significantly over time. (Genik 1992, 1993; Bumby and Guiraud 2005; Fairhead et al. 2013). According to the tectonic locations of the basins and differences in basin evolution, CASZ can be divided geologically into two basin groups. One is associated with large-scale dextral strike-slip faults (the “Central Rift Basin Group”). This group includes the Bongor and Doba-Doseo-Salamat rift basins, the Baggara Basin, and the Sufyan subbasin of the Muglad Basin. The other is with oblique extension in Sudan/South Sudan (the “Eastern Rift Basin Group”), which includes the Muglad, Melut, Khartoum, and Blue Nile Basins, as well as the Anza Basin in Kenya (Fig. 2.2) (Khain 1992). In terms of basin structure, the biggest differences between the two groups are in inversion intensity and in the extent of the third rifting phase, which occurred at the end of the Late Cretaceous. The Central Rift Basins underwent intensive inversion in the Late Cretaceous, and the third rifting phase was comparatively weak (Millegan 1990). However, the Eastern Rift Basins show little or no evidence of inversion in the Late Cretaceous but were affected by the later opening of the Red Sea (Fairhead 1988b). Here, the third rifting phase was strong and accompanied by sedimentary filling by a set of “coarse–fine-coarse” continental clastic deposits that provided the main play for the Melut and other basins (Fig. 2.4) (Dou et al. 2005).

Age ( Ma )

Western Rift Basins Bongor

Doba-Doseo

Eastern Rift Basins Muglad

Melut

Pliocene-Pleistocene 5.33

Lower

Cretaceous

Upper

Paleogene Neogene

Stratigraphy

Miocene

23.03

Oligocene

33.9

Eocene

56.0

Paleocene

66.0

Maastrichtian

72.1

Campanian

83.6

Santonian

86.3

Coniacian

89.8

Turonian

93.9

Cenomanian

100.5

Albian

113

Aptian

125

Barremian

129.4

Hauterivian

132.9

Valanginian

139.8

Berriasian

145.0

Precambrian crystalline basement rock

Deep lacustrine shale

Sandstone

Mudstone

Volcanic rock

Basement

Reservoir

Fig. 2.4 Comprehensive column of the different basins of CASZ (Age according to the International Commission on Stratigraphy (ICS) 2015)

30

2 Regional Geological Characteristics …

Intense Rifting During the Early Cretaceous In the early Early Cretaceous, the Gondwana supercontinent disintegrated, and associated extensional faulting formed a three-armed rift system, with one arm running parallel to the equator and the others running north and south in the South Atlantic (Elder et al. 1984). The ‘equatorial’ arm penetrated the African continent (Moulin et al. 2010), inducing simultaneous dextral strike-slip extension of the largescale fault zones between the subplates in the Pan-African active zone on the African continent (Guiraud et al. 2005; Fairhead et al. 2013), an activity which lasted until the Albian age. This regional rifting formed a series of sedimentary basins in central Africa. The Bongor, Doba, Doseo, Salamat, and other basins in southern Chad may all been part of a large, interconnected rift group formed at that time. NW and NE trending basement faults controlled the development of a faulted lake basin with an obvious strike-slip pull-apart structure. Dextral displacement of the Doseo and Salamat basins reached 35 km (Genik 1992). In a few rifts, a complete Lower Cretaceous coarse– fine-coarse cycle of fluvial-lacustrine clastic strata with a thickness of up to 5000 m was deposited, including a set of deep lacustrine shale strata rich in organic matter, with a thickness of 500–1500 m, which was deposited during the Middle-Early Cretaceous (Browne and Fairhead 1983). This set of shale layers overlies the earlier “highs between depressions” strata, providing high-quality regional caprocks and emerging as principal source rocks in Central Africa. NW-trending faults in the Muglad, Melut, White Nile, other basins in Sudan/South Sudan, characterized by NESW oblique extension, controlled the development of a series of large rifts (Benkhelil et al. 1988). Rifting During the Late Cretaceous-Paleocene Entering the Late Cretaceous, a second rifting phase developed in CASZ, depositing a 1000–3000 m thick continental clastic formation, initially fine but progressively coarsening. Moving eastward from the Doba Basin, the shale content in the Upper Cretaceous decreases. The sandstone content increases, reflecting that the eastern basins, such as the Sufyan subbasin, were less affected by inversion than the western basins (Bosworth 1992). The Santonian event was a major collision between the African Plate and the European Plate that caused the direction of the regional stress field to change from S-N to NE-SW, producing an N-S compressional tectonic environment in the African Plate (Guiraud and Bosworth 1997) that resulted in varying degrees of inversion in the Central Rift Basin Group in Central Africa (Genik 1992, 1997; Dou et al. 2011). However, the NW-trending Eastern Rift Basin Group continued to subside, and another set of lacustrine sedimentary strata during rifting phase was deposited. For instance, in the Upper Cretaceous in the Muglad Basin developed in the central part of the basin—the Kaikang Graben, the Nugara, and the Sufyan subbasin— are composed of 1500–3000 m thick littoral-shallow lacustrine strata mainly fluvial channel sandstone, flood plain mudstone, and littoral-shallow lacustrine mudstone. These strata form the main caprocks in the region (Tong et al. 2004; Dou et al. 2006).

2.2 Middle-Cenozoic Magmatic Activity

31

The Melut Basin, on the other hand, lacks both regional caprocks and effective source rocks and primarily consists of a large set of sandstone intercalated with thin mudstone (Dou 2005; Dou et al. 2006) (Fig. 2.4). A set of 1500–3000 m thick continental clastic strata were also deposited in the Doba-Doseo-Salamat Basins (Genik 1992, 1993). By the end of the Paleocene, strike-slip activity in CASZ had ceased, and the rifting phase ended with a regional unconformity. Rifting During the Paleogene Entering the Eocene, fault activity in CASZ ceased, and the Central Rift Basin Group entered a stage of thermal subsidence. In the Doba, Doseo, and other basins, faulting ends at the top of the Cretaceous. During the Paleogene, post-rift-type sedimentation occurred. Affected by the accelerating NE-oriented movement of the Africa-Arabian Plate, the separation of the Red Sea, and rifting in East Africa (Lowell and Genik 1972), the large-scale rift basin in the NW-trending Eastern Rift Basin Group entered a new rift development period. During this period, extension occurred selectively in the rift where the boundary fault ran perpendicular to the direction of maximum stress in the extension-stress field. In the Muglad, Melut, Anza, and other basins, 1000– 3000 m thick Paleogene strata were deposited until the Oligocene end (Fig. 2.4). Extension in small rift basins, such as the Blue Nile and Khartoum, became weak or stopped altogether, possibly because the NE-trending transfer fault altered the displacement between the faults. This episode of rifting again ended with a regional unconformity (Giedt 1990). Post-Rift Stage During the Miocene, the basins of the CASZ stopped evolving and underwent different degrees of compressional inversion due to the extrusion from N40° to N70 °E (Fairhead et al. 2013). Magmatic activity accompanied the uplifting of the Adamawa Uplift in the west, and the Matriq and Babanusa Uplifts in the east were also formed. All of the basins in CASZ are in the post-rifting phase. The thickness of alluvium was 0–300 m and distributed evenly across the whole area.

2.2 Middle-Cenozoic Magmatic Activity Central Africa went through frequent periods of magmatic activity during the MesoCenozoic. Apart from large numbers of magmatic outcrops, igneous rocks have been drilled in the Melut and Muglad Basins in Sudan and South Sudan, the Doba, Bongor, and Termit Basins in Chad, the Benue Graben in Nigeria, etc (Petters and Ekweozor 1982). In addition, studies have identified a low magnetic anomaly in the Gongola branch of the Benue Graben, which may be caused by basic rock mass located at a depth of 6–10 km. This indicates that magmatic activity in the deep part of the Benue Graben was also extensive, comparable in scale to the activity on the surface (Coulon et al. 1996; Abubakar 2014).

32

2 Regional Geological Characteristics …

Since 2007, magmatic rocks have been drilled in many wells in the Termit Basin (including Block Lake Chad), the Bongor Basin, and the western block of the Doba Basin. To study the period of magmatic activity in-depth, systematic geochemical and isotopic dating analyses were performed on well Acacia-1 in the Termit Basin (Block Lake Chad), wells Figuier-1 and Nere-1 in the West Doba Basin, and well Ronier-1 in the Bongor Basin (Table 2.1) (well locations are shown in Fig. 2.2). Combining our results with those of previous studies, the periods of magmatic activity during the Mesozoic and Cenozoic and the resulting changes like the basins are discussed.

2.2.1 Petrological and Geochemical Characteristics Attitude and Petrological Characteristics of Igneous Rocks Seismic and drilling data show that, in CASZ, the magmatic rock is mainly sandwiched within sedimentary rocks and that there is a trans-layer phenomenon on seismic profiles. Generally, there are 1–3 layers, the thickest of which can be more than 100 m and the thinnest only 10–20 m. For example, igneous rocks were drilled at 1889–1994 m in well Ronier-1 in the Bongor Basin, with a thickness of 96 m. This set of igneous rock is dense and has low matrix porosity. However, the microresistivity curve shows knife-stab-like low-value spikes of varying amplitudes, indicating microcracks have developed to a certain extent. The over- and underlying strata of the igneous rock have ‘baked’ characteristics. They have undergone a slight metamorphosis, particularly the overlying strata, which have metamorphosed into slate, mica, etc., indicating that the igneous rocks are later intrusions. The thickness of the upper metamorphic interval is 32 m, and the thickness of the lower metamorphic interval is 16 m (Fig. 2.5). Thin-section identification indicates that the igneous rock in the study area is diabase (Fig. 2.6), gray-black to black in appearance and revealing a diabase structure under a polarizing microscope. The main mineral components are plagioclase and clinopyroxene, with small amounts of enstenite and magnetite. The clinopyroxene appears as augite, a light-brownish-yellow, prismatic, tabular, granular, hypoautomorphic crystal. Simple twin crystals occur occasionally. Small euhedral plagioclase is often wrapped. The plagioclase presents as slender, columnar, colorless, euhedral crystals, irregularly arranged. Twin crystals are developed in albite, and Carlsbad-albite compound twins sometimes occur. Geochemical Characteristics Characteristics of Major Elements The content of silicone (SiO2 ) as the main element is between 47.77 and 51.52% and belongs to the diabase. Most titanium content (TiO2) is low, less than 2.5% and only samples R016, N007, and N010 have higher TiO2 content (3.24%, 3.56%, and 4.25%, respectively). Total iron content (TFe2 O3 ) is 8.71%–15.58%, aluminum

Doba

Block Lake Chad in the Termit Basin

0.47 0.53

1625 −1630 1660 −1665 50 −60

N037

N042

F003

Figuier-1

0.68

1615 −1620

N035

Partly outcropped

Upper cretaceous

Lower cretaceous

975 −980

N019 Sill, with translayer characteristics on the seismic profile

0.65

965 −970

N017

0.91

0.32

0.43

0.34

0.46

950 −955

0.70

0.98

N014

Upper cretaceous

940 −945

Sill, with translayer characteristics on the seismic profile

0.39

0.44

0.43

0.30

N012

915 −920

1550 −1555

A020

Nere-1

1515 −1520

A014

N007

1490 −1495

A011

Upper cretaceous

1465 −1470 Sill, with translayer characteristics on the seismic profile

1980 −1985

R029

Acacia-1

1960 −1965

R025

A008

0.29

1950 −1955

0.48

1940 −1945

0.67

0.58

R023

Lower cretaceous

K (%)

R021

Sill, with translayer characteristics on the seismic profile

1895 −1900

Age

1915 −1920

Ronier-1

R012

Bongor

Attitude

Depth (m)

R016

Well

Sample number

Basin

Table 2.1 Analysis results of K–Ar age of intrusive rocks in sedimentary strata of basins in Chad

15.40

4.971

7.156

12.34

9.200

4.476

7.273

9.809

12.59

4.320

5.352

4.785

5.880

4.935

3.458

3.460

5.439

6.116

6.720

(mol/g)

40 Ar rad

× 10–11

90.17

59.76

70.50

67.34

79.25

69.35

74.46

72.80

66.59

44.27

49.51

62.93

65.43

62.49

51.81

50.66

64.82

65.34

60.10

40 Ar rad

(%)

(continued)

95.0 ± 2.0

87.4 ± 3.3

93.5 ± 2.9

101.7 ± 3.3

79.8 ± 2.2

74.4 ± 2.3

88.9 ± 2.6

79.0 ± 2.3

72.6 ± 2.0

62.8 ± 1.8

68.8 ± 1.9

63.1 ± 2.2

62.9 ± 2.1

59.6 ± 2.1

67.5 ± 3.1

65.3 ± 3.1

64.2 ± 2.2

51.9 ± 1.7

65.6 ± 2.4

Apparent age (±1σ, Ma)

2.2 Middle-Cenozoic Magmatic Activity 33

F011

Sample number

Well

Attitude Sill, with translayer characteristics on the seismic profile

Depth (m) 1680 −1685 Lower cretaceous

Age 0.55

K (%) 8.638

(mol/g)

40 Ar rad

× 10–11 77.07

40 Ar rad

(%) 88.4 ± 2.5

Apparent age (±1σ, Ma)

Note The analysis work was conducted by the Institute of Geology, China Earthquake Administration. The constants used are λ = 5.543 × 10–10 /a, λe = 0.581 × 10–10 /a, λβ = 4.962 × 10–10 /a, and 40 K/K = 1.167 × 10−4 mol/mol

Basin

Table 2.1 (continued)

34 2 Regional Geological Characteristics …

2.2 Middle-Cenozoic Magmatic Activity

35

Fig. 2.5 Well logging interpretation results of igneous rock in well Ronier-1

(Al2 O3 ) content is between 11.53 and 15.55% and magnesium (MgO) content is 2.39%–9.98%. The contents of sodium and potassium (Na2 O + K2 O) are 2.52%– 6.36%, and the Na2 O/K2 O ratio is 2.15–8.21, showing significant sodium enrichment. On the TMS classification diagram (Fig. 2.7), most samples fall within the basalt zone, with a few projected into the trachybasalt and basaltic andesite zones, with only sample R018-2 falling within the basaltic trachyandesite zone. The sample points are distributed near the boundary in the subalkaline series. In the TFe2 O3 /MgO-SiO2 diagram, the samples mostly fall within the tholeiite area and its vicinity. Characteristics of Trace Elements The trace elements analysis results show that the content of high field-strength elements (HFSE) in the samples is high. The content of Nb is (12.4–38.3) × 10–6 in the Late Cretaceous diabase, and (7.95–22.7) × 10–6 in the Paleogene diabase. The content of Zr is (87–202) × 10–6 in the Late Cretaceous diabase and (70.6–169) × 10–6 in the Paleogene diabase. The contents of Cr and Ni vary widely ((25–1162) × 10–6 and (14–320) × 10–6 , respectively). The Zr/Y ratio and Th/U ratios of the Late Cretaceous diabase are high (4.88–7.68 (average 6.09) and 3.49–4.95 (average 4.19), respectively). The Rb/Ba ratio, Zr/Nb ratio, Rb/Nb ratio, La/Th ratio, and

36

2 Regional Geological Characteristics …

Fig. 2.6 Intrusive rock section of well Ronier-1 (for sample numbers, see Table 2.1). PI—plagioclase; Cpx—clinopyroxene

Fig. 2.7 TAS diagram of igneous rocks in Chad (template from Le Bas et al. 1986)

2.2 Middle-Cenozoic Magmatic Activity

37 100

Figuier--1

Ronier--1

Nere--1

Acacia--1 Sample/Primitive Mantle

Sample/Primitive Mantle

100

10

10

1

1 Rb Th Nb K Ce Sr Nd Zr Eu Gd Dy Ho Tm Lu Ba U Ta La Pb P Sm Hf Ti Tb Y Er Yb

(a) Late Cretaceous

Rb Th Nb K Ce Sr Nd Zr Eu Gd Dy Ho Tm Lu Ba U Ta La Pb P Sm Hf Ti Tb Y Er Yb

(b) Paleogene

Fig. 2.8 Spider diagram of trace elements for diabase (standard values of the Primitive Mantle from Sun and McDonough 1989)

La/Nb ratio in the Paleogene diabase are high (0.03–0.08 (average 0.05), 5.51–9.98 (average 7.77), 0.45–1.92 (average 0.87), 7.76–12.93, (average 9.58) and 0.62–1.32 (average 0.86), respectively). The Rb/Sr ratio is between 0.01 and 0.05, with an average of 0.03, consistent with the ratio of the primitive mantle (Rb/Sr = 0.03) (Wu et al. 2005). In a spider diagram of trace elements (Fig. 2.8), there is no obvious difference between the curves of the Late Cretaceous diabase and the Paleogene diabase, both of which show significant enrichment of large ion lithophile elements (LILE) and HFSE, and significant depletion of compatible elements. Characteristics of Rare Earth Elements The total REE ∑REE in the Late Cretaceous diabase varies between (61.15–136.29) × 10–6 , and that in the Paleogene diabase varies between (47.61–139.33) × 10–6 . The LREE/HREE ratio of the Late Cretaceous diabase varies from 3.79 to 5.87, while that of the Paleogene diabase changes from 3.31 to 5.95. The (La/Yb)N ratio is low. In the Late Cretaceous diabase, it varies from 4.03 to 8.31, with an average of 5.85. In the Paleogene diabase, it ranges from 3.31 to 7.78, with an average of 4.48, indicating that the mantle experienced considerable partial melting in both cases. The distribution curves of rare earth elements (Figs. 2.9 and 2.10) show right-dip characteristics. The Late Cretaceous diabase and Paleogene diabase have similar rare earth abundances, both showing enrichment of LREE (light rare earth elements) and depletion of HREE (heavy rare earth elements). There is no negative Eu anomaly, indicating that fractional crystallization of plagioclase did not occur to any significant extent. The presence of olivine and pyroxene may cause the fractionation of LREE relative to HREE. The low HREE content of the diabase implies that a residual phase of garnet may be present in these diabase source areas. Isotopic Characteristics of Sr, Nd, and Pb The ranges of 143 Nd/144 Nd and 87 Sr/86 Sr values for diabase in the study area are relatively narrow. For Late Cretaceous diabase, (87 Sr/86 Sr)i ranges from 0.704167 to

38

2 Regional Geological Characteristics … 200

Fig. 2.9 Distribution pattern of rare earth elements for the Late Cretaceous diabase Sample/Primitive Mantle

100

10 Figuier--1 Nere--1

1

Rb

Pr Ce

Eu Nd

Sm

Tb Gd

Ho Dy

Tm Er

Lu Yb

200

Fig. 2.10 Distribution pattern of rare earth elements for the Paleogene diabase Sample/Primitive Mantle

100

10

Ronier--1 Acacia--1 1 Rb

Pr Ce

Eu Nd

Sm

Tb Gd

Ho Dy

Tm Er

Lu Yb

0.706564, with an average of 0.705110 and (143 Nd/144 Nd)i is between 0.512451 and 0.512703, averaging 0.512586. For the Paleogene diabase, (87 Sr/86 Sr)I is between 0.703545 and 0.705380, averaging 0.704028, and (143 Nd/144 Nd)i ranges from 0.512690 to 0.512847, with an average of 0.512763. The (143 Nd/144 Nd)i value of the Late Cretaceous diabase is smaller than that of the Paleogene diabase, while it is (87 Sr/86 Sr)i value is greater. These characteristics are similar to the Mesozoic and Cenozoic diabase that occurs along the southeastern coast of China (Ho et al. 2003). The εNd (t) value of the Late Cretaceous diabase varies greatly from 1.4 to 3.2, with the εNd (t) value of the Paleogene diabase being higher, ranging from 2.6 to 5.6. In the diagram of (143 Nd/144 Nd)i -(87 Sr/86 Sr)i of the diabase in the study area (Fig. 2.11), there is a significantly negative correlation between them. The Paleogene

2.2 Middle-Cenozoic Magmatic Activity

39

DM

Figuier 1

Hoggar

Nere 1 Ronier 1

0.5130

Acacia 1

(143Nd/144Nd) i

St.H CL BSE

0.5125 EM II

EM I 0.5120 0.702

0.704

0.706

0.708

(87Sr/86Sr) i

Fig. 2.11 Diagram of (143 Nd/144 Nd)i -(87 Sr/86 Sr)i of diabase. Template from Zindler and Hart (1986), Franz et al. (1999)

diabase has similar isotope ratios of Sr and Nd. However, the Late Cretaceous diabase experienced significant spatial evolution. The Pb isotope ratios of diabase in the study area are generally consistent, with only a small range of variation. All samples have relatively high contents of radiogenic lead, with 206 Pb/204 Pb of 18.14–18.96, 207 Pb/204 Pb of 15.56–15.62, 208 Pb/204 Pb of 38.33–38.88, and higher ratios of 206 Pb/204 Pb, 207 Pb/204 Pb (18.28–18.5, 15.45– 15.53, 37.2–38.0) and 208 Pb/204 Pb than Atlantic N-type MORB (Saunders 1988). The Pb isotopic composition of the diabase in the study area is between the endmember components of DM and EM II, and the influence of the EM I component is small. The sample points fall between those of the Benue Graben, Hoggar, and the Cameroon volcanic belts and coincide with the trend from the Early Cretaceous to the Neogene (Coulon et al. 1996; Ngako et al. 2006).

2.2.2 Periods of Magmatic Activity Twenty samples were carefully selected for K–Ar age analysis, with seven samples selected in parallel for Ar–Ar dating to test the accuracy of the K–Ar dating and allow mutual verification (Table 2.1). The analysis results show that magmatic activity in the study area can be divided into two key periods: the Late Cretaceous (95–75 Ma) and the Paleogene (66–52 Ma).

40

2 Regional Geological Characteristics …

Magmatic Activity During the Late Cretaceous The K–Ar and Ar–Ar isotopic age data from the Late Cretaceous are mostly concentrated between 95 and 75 Ma, principally in wells Nere-1 and Figuier-1 in the Doba Basin. The Diabase belongs to the olivine tholeiite series. Diabase of a similar age was also found in well Kumia-1 in the Lake Chad Basin, basalt (97 ± 1.2 Ma), multiple exploration wells in the Doseo Basin (wells Tega-1, Keita-1, and Kikwey1) (Genik 1992), well Kwat-1(99.5 ± 4.3 Ma), and in the Al-Fashaga outcrop (85.6 ± 5.2 Ma) in the Melut Basin in Sudan. Diabase 91 m thick (82 ± 8 Ma) was drilled in the northwestern Muglad Basin (McHargue et al. 1992), with its age equating to the second period of volcanic activity in the Benue Graben (97–81 Ma) (Coulon et al. 1996). This is also in line with the period of alkaline volcanic activity of the dyke swarm parallel to the coast near Rio de Janeiro, Brazil, on the other side of the Atlantic Ocean (82–83 Ma) (Moulin et al. 2010). Magmatic Activity During the Paleogene The Paleogene K–Ar and Ar–Ar isotopic age data are mainly concentrated between 66 and 52 Ma, primarily in well Ronier-1 in the Bongor Basin and well Acacia-1 in the Lake Chad Basin. The diabase is dominated by the olivine tholeiite series, with a small amount of quartz tholeiite series. The age of the trachybasalt found by Genik (1992) in well Naramay-1 in the Bongor Basin is 56–52 Ma, when volcanic activity was occurring throughout Central and West Africa. There was also a wide incidence of basaltic eruptions in the Benue Graben and the Cameroon Volcanic Belt (volcanic line). Evidence of this volcanic activity is found in wells Sobat-1 (67.1 ± 3.1 Ma), Kwat-1 (66.6 ± 3.1 Ma), Reel-1 (56.5 ± 3.0 Ma), and Miyan-1 (53.0 ± 8.2 Ma), etc. in the Melut Basin in Sudan. Vicat et al. (2002) studied an outcrop of pantellerite (69 ± 1.4 Ma) near Lake Chad and concluded that it might be related to magmatic activity in the Cameroon volcanic belt. Three igneous rocks have also been drilled in the Anza Basin, Kenya, which all date to the Paleogene (Winn et al. 1993). A phase of volcanic activity at 60–50 Ma also developed in Brazil, which is considered the result of ‘hot spots’ (Moulin et al. 2010). After the Oligocene, the basin entered a stage of thermal subsidence, and magmatic activity significantly weakened, eventually stopping altogether. Magmatic activity mainly occurred as broad basement uplift—for example, in Hoggar, Darfur, the Cameroon volcanic belt, and Tebisti in Central and West Africa—with the development of abundant alkaline basalts and related products.

2.2.3 Analysis of Tectonic Environment Continental Rift Environment During the Late Cretaceous-Paleogene Volcanism is closely related to the geotectonic environment and contains much tectonic information. Studies have shown that the chemical compositions of rocks can

2.2 Middle-Cenozoic Magmatic Activity

41

accurately reveal the geotectonic environments in which they developed. Discriminant diagrams of trace elements, such as diagrams of Ti-Zr- Y, Hf-Th-Ta, Nb-Zr-Y, Ti-Zr, Zr/Y–Z, are the most commonly used to determine the nature of tectonic environments. As shown in Figs. 2.12 and 2.13, the diabase in the basins in the study area falls within intraplate basalt and intraplate tholeiite zones, indicating that it formed in an intra-plate tectonic environment. Diabase in the basins of the study area is characterized by sodium enrichment, with Na2 O/K2 O ranging from 2.15 to 8.21. Geochemically, the large ion Fig. 2.12 Ti-Zr-Y discriminant diagram (template from Pearce and Cann 1973). A—island arc tholeiite; B—MORB; C—calc-alkaline basalt; D—intraplate basalt

Fig. 2.13 Hf-Th-Ta discriminant diagram (template from Wood 1980). A—N-MORB; B—E-MORB and intraplate tholeiite; C—alkaline intraplate basalt; D—island arc tholeiite

42

2 Regional Geological Characteristics …

lithophile elements are significantly enriched, the compatible elements are significantly depleted, and the high field-strength elements Nb and Ta are enriched. Sr and Nd isotope analysis shows that diabase is produced by mixing two endmember components of depleted mantle DM and enriched mantle EMII and that the Mesozoic (Late Cretaceous) diabase has a higher (87 Sr/86 Sr)i ratio and a lower (143 Nd/144 Nd)i ratio than the Paleogene diabase, showing obvious characteristics of evolution over time. The evolution of mantle components over time may have a tight connection to the asthenospheric upwelling and lithospheric thinning in Central Africa and West Africa since the Mesozoic. The above characteristics reveal the tectonic attributes of the continental rifts in the diabase in this area. The Basins Change from “Passive” to “Active” in Three Rifting Episodes According to its origin, rifting can be divided into two categories: active and passive (Sengor and Burke 1978; Morgan and Baker 1983). Active rifting is a direct response to extension caused by mantle upwelling or dome formation. Passive rifting is caused by thinning the asthenosphere due to tensile stress following the passive upwarp of the crust. Actual rift systems can show components of active and passive mechanisms that are end-member combinations of idealized models (Allen and Allen 1990). In eastern China, the Bohai Bay Basin is a typical active rift basin (Lirong et al. 2013). Three episodes of rift bed successions characterize the rift basins in Central Africa. According to the tectonic characteristics and magmatic properties, it is inferred that their very nature changed significantly during the Cretaceous-Paleogene evolution. In the Early Cretaceous, the disintegration of the Gondwana supercontinent and the opening of the South Atlantic led to the formation of WCARS (Fairhead and Binks 1991). In Southern Chad, the result was predominantly strike-slip extension, while there was an extensive oblique extension in Sudan (Mello and Katz 1997). There was no significant magmatic activity, so it is generally considered a “cold initial” rift (Genik 1993), although some studies have argued that it was a passive rift (Genik 1992; Tong et al. 2004). CASZ is sandwiched between the three subplates and is affected by the drifting of the surrounding plates and internal stress within the subplates. The stress fields of basins at different tectonic locations were changing during the Cretaceous-Cenozoic (Fairhead et al. 2013), so the nature of the basins themselves were also bound to change (Schiefelbein et al. 1999). There was little volcanic activity during the Early Cretaceous, and basin formation was related to the opening of the Pacific. Thus, it is considered to be that the Early Cretaceous basins were passive rift basins (Japsen et al. 2012). Magmatic activity began in the Late Cretaceous, mainly concentrated in CASZ and its vicinity (Guiraud et al. 1992). The squeezing action in the Santonian age, during the middle Late Cretaceous, caused the Benue Graben, the Doba Basin, and the Bongor Basin to rotate 15° counterclockwise (Genik 1993), accompanied by an increase in the frequency of magmatic activity. Intrusive rocks of the Santonian age have been drilled in the Doba and Muglad Basins, although extension centered on the Muglad, Melut, Anza, and other basins in the east. Magmatic activity in the Early Paleogene was more frequent and more widespread. A volcanic belt 1600 km long formed in Cameroon at 65–30 Ma, with its lithology

2.2 Middle-Cenozoic Magmatic Activity

43

dominated by granite and syenite. Several large Cenozoic volcanic centers also developed in Central Africa, with no obvious change in the thickness of the crust beneath these ‘hot spots’ and no mantle plume inferred to exist (Pasyanos and Nyblade 2007). As a result of induced intra-plate rifting, the Cenozoic Benue Graben rotated 21° counterclockwise (Fitton 1980). Continental basalts have been drilled in many basins in Central Africa. Their age is about 65 Ma, corresponding to the beginning of the third rifting phase. The overall profile of the regional Bouguer gravity anomaly shows a negative gravity anomaly due to the thinning of the crust and mantle upwelling in the context of a strong and extensive positive Bouguer gravity anomaly in the Muglad Basin (Fig. 2.14) (Fairhead et al. 2013). The development and characteristics of igneous rocks in the Late Cretaceous and Paleogene basins are similar to those in the Bohai Bay Basin in eastern China. The latest high-resolution 3D seismic data from the Muglad Basin in Sudan and the northern Kaikang trough reveal that the Paleogene boundary faults have listric characteristics (Browne and Fairhead 1983). The overall structure of the basin became "ox head-shaped" (Jorgensen and Bosworth 1989). These characteristics indicate that the Paleogene rifts were caused by the upwelling of the asthenosphere. Hence, the Paleogene rifts can be inferred as active rifts while they were in a transitional phase during the Late Cretaceous (Lirong 2004).

Regional

Bouguer gravity (mGal) +40 Residual +60 Observed +80

NE

SW 0 (km)

2.25g/cm3 2.42g/cm3 2.65g/cm3 2.70g/cm3

20

2.86g/cm3 Moho 3.30g/cm3

40 0

100

200

300 (km)

Fig. 2.14 The profile of regional Bouguer gravity anomaly cross the Muglad Basin (from Fairhead et al. 2013)

44

2 Regional Geological Characteristics …

2.3 Basin Types and Petroleum Geological Characteristics Various classification schemes have been given for the rift basins in Central and West Africa. Genik (1993), for example, divided the rift basins in Niger, Chad, and the Central African Republic into extensional basins and tenso-shear basins according to their different formation mechanisms (Klemme 1980). The rift basins in Central and West Africa have all undergone tension-extension, strike-slip, and compression to varying degrees during their evolution. The physical locations of the basins within the rift system determine the variations in their tectonic characteristics (Biro 1976). After more than 20 years of continuous exploration and research, based on overall analysis and comparison of the tectonic locations and evolution, sedimentary filling, controlling factors for hydrocarbon accumulation, etc. of the principal rift basins in CAS, we have divided the basins in CAS into two broad categories: superimposed rift basins and inversion rift basins. The former has developed two or three rift cycles, with vertical upward oblique superposition. In particular, the Paleogene rift cycle developed. The basins are characterized by great formation thickness and a low degree of inversion. The sedimentary cycles in the rifting phase in the Early Cretaceous and Late Cretaceous developed or were retained in inversion rift basins, and a significant inversion occurred during the Late Cretaceous-Paleocene (Girdler 1983). Rift cycles were not developed in the Paleogene. Superimposed rift basins are primarily developed in the eastern rift basin group (Burke et al. 2003). However, the Termit Basin in the West African Rift System also belongs to this type (Liu et al. 2012). Inversion rift basins can be further divided into two subtypes: weak inversion type and strong inversion type. Weak inversion rift basins, such as the Doba-DoseoSalamat Basin, generally preserves the Cretaceous rifting phase deposits. On the other hand, in strong inversion rift basins, such as the Bongor Basin and the Benue Graben of the West African Rift System, most or all of the Upper Cretaceous is denuded (Lirong et al. 2011). Superimposed rift basins are primarily found in the eastern rift basin group. Inversion rift basins are largely distributed within CASZ and the nearby central rift basin group (Thomas 1996).

2.3.1 Superimposed Rift Basins Superimposed rift basins are mainly developed in Sudan/South Sudan and Kenya and include the Muglad, Melut, Anza, etc. basins. Those lacustrine basins developed in the Early Cretaceous and have undergone three stages of rift development: the Early Cretaceous, the Late Cretaceous, and the Paleogene (Fig. 2.15). There is a local unconformity between the Upper and Lower Cretaceous, but they are largely inherited. The extension direction of the rift in the Paleogene is inconsistent with the underlying Cretaceous rift. Regional squeezing at the end of the Paleogene ended the rifting phase, forming many squeezed anticlines and causing widespread regional uplifting and denudation (Petters 1979).

Ghazal Zarqa

68 71.3 83.5

II

85.6 Subbasin

Bentiu

I Abu Gabra

Lower

120

Lau Adar

137 Precambrian basement

(a) Muglad Basin

Yabus Samma

Melut

Galhak

Al Renk

Al Gayger

Seal

Pay zone

Source

Seal

Pay zone

Reservoir

Sag Rifting episode III

Jimidi Oligocene

Rifting episode II

Baraka

Aradeiba Cretaceous

Subbasin

Miadol

Rifting episode I

65

Tectonic cycle

Agor Daga

Eocene-Paleocene

54.8

Amal

Pliocene

Form.

Upper

Nayil

Paleocene Darfur Group

EoceneOligocene

Upper

Paleogene

23.8

Holocene

Lower

Tendi

Series

Miocene

III

Paleogene

10

Lithology

Neogene

Adok

Strata System

Cretaceous

Lower Miocene

Sag

Fault depression

Upper Miocene— Pliocene

Form.

Tectonic cycle

45

Fault depression

Series

Lithology

Fault depression

Neogene

System

(Ma)

Source

Age

Strata

Reservoir

2.3 Basin Types and Petroleum Geological Characteristics

Precambrian basement

(b) Melut Basin

Fig. 2.15 Comprehensive stratigraphic columns in the Muglad Basin (a) and Melut Basin (b)

Geological Features Muglad Basin The Muglad Basin is located in southern Sudan and the northwestern part of South Sudan. It is the largest rift basin in the Central African Rift System, 800 km long in the northwest direction, 200 km wide in the northeast direction, and covering an area of 12 × 104 km2 . According to gravity, aeromagnetic, and seismic data, the Muglad Basin is divided into the Sufyan subbasin, the Nugara subbasin, the Fula subbasin, the Kaikang Trough, the Bamboo subbasin, the Heglig subbasin, the Tomat Uplift, the Babanusa Uplift, the Abei Slope, and other tectonic units (Figs. 2.16 and 2.17). The maximum thickness of the strata is 16 km (Awad 2015). The basin experienced three rifting stages and thermal subsidence during the postrift period (Fig. 2.15a). The total amount of extension is 17.2%. Of these stages, the deposition period of the AbuGabra Formation was the first active rifting episode, accounting for more than 60% of the total amount of extension. During this period, coarse–fine-coarse fluvial and lacustrine strata were deposited, and a set of dark, deep lacustrine shale contained organic matter. The Bentiu Formation was deposited during a thermal subsidence stage when a set of fluvial sandstones developed in which thin layers of mudstone are intercalated. Deposition of the Darfur Group

46

2 Regional Geological Characteristics …

0

25

Fula

50km

Block 2

Subb

asin

Ba

ban

N

usa

Up

Block 1

Eastern Slope

mb

Ba

oo

Su

bb

lift

A′

asi

n

Uri ty

ba

ya uf

S

b Su

t lif Up at m To

n

Sub

bas

in

Kaikang Trough

sin

Nugara Subbasin

Abei Slope Block 6 Block 4 A Sudan Fault

South Sudan

Oilfield

Fig. 2.16 Structural outline of the Muglad Basin. From Duo et al. (2006)

A

A′

0

Neogene Tendi Nayil Amal

Depth (m)

3000

Darfur 6000 Bentiu

Abu Gabra

9000

West slope of Kaikang Trough

Kaikang Trough

Unity Subbasin

Fig. 2.17 Structural outline of the Muglad Basin. Adapted from Shi et al. (2014). For location, see Fig. 2.16

occurred during the second active rifting stage, which accounts for about 15% of the total amount of extension. The Darfur Group is composed, from bottom to top, of the Aradeiba Formation, the Zarqa Formation, the Ghazal Formation, and the Baraka Formation. The Amal Formation was deposited during the second thermal subsidence stage. The Nayil-Tendi Formation was deposited during the third rifting stage, accounting for about 25% of the total amount of extension and concentrated mainly in the Kaikang Trough and the Nugara subbasin. The Adok Formation was deposited during the third thermal subsidence stage. The first and third cycles had a strong extension. The second cycle had a weak extension, depositing a large set of terrestrial strata with different thicknesses and lithological associations corresponding to the diverse tectonic cycles of the individual stages. Fault activity during the rifting phase controlled the subsidence center and depocenter for the basins and

2.3 Basin Types and Petroleum Geological Characteristics

47

depressions (Fairhead 1986). A wider sedimentary range formed during the post-rift period, and the position of the rift migrated from time to time (Tong et al. 2004). For example, the extension direction of the rift in the Paleogene was NE-SW, representing a counterclockwise rotation of 15°–20° from its previous NNE-SSW orientation. This rotation corresponds to a contemporaneous change in the regional stress field. Melut Basin The Melut Basin is wedge-shaped being narrow in the northwest and wide in the southeast. The basin converges in the northwest direction, spreads out to the south, and extends into Ethiopia. It is 400 km long in the northwest direction and 200 km wide in the northeast direction, with a total area of 2.7 × 104 km2 . The maximum thickness of the formation is 10 km (Awad 2015). According to the basement structure, the residual thickness of the strata, the distribution of regional faults, etc., the Melut Basin is divided into five depressions, and one high—the Northern Depression, the Eastern Depression, the Central Depression, the Southern Depression, the Western Depression, and the Western High, and the structural framework was formed in the Early Cretaceous (Balestrieri et al. 2016). The assemblage of the depressions is dominated by series connections, with occasional parallel connections. The strike of the depressions changes from NW-SE to NNW-SSE from north to south. The Western Depression, the Central Depression, and the Southern Depression show a combination of parallel connections, and other depressions display a combination of series connections. The depressions are all characterized by the half-graben rift, and the highs are characterized by fault horst. The vertical superimposition of depressions and highs reflects evolution from multiple highs and depressions to a unified subbasin. The number of depressions and highs gradually decreases from bottom to top, segmentation gradually weakens, and the structure finally becomes a unified subbasin in the Neogene (Dou 2005; Tong et al. 2005) (Figs. 2.18 and 2.19). Like the Muglad Basin, the Melut Basin experienced three periods of large-scale rifting activity and subsequent post-rift-subsidence stages (Fig. 2.15b). The Early Cretaceous was the most crucial period of rift development, and the major source rocks of the basin were also deposited during this period. There was a weak rift development period during the Late Cretaceous when the sedimentary strata were dominated by sandstone without regionally distributed lacustrine mudstones. Relatively strong rift development also occurred during the Paleogene. The tectonic environment was more affected by the opening of the Red Sea and the East African Rift Valley, which had the characteristics of active rift development with intense volcanic activity (Gregory 1894). Since the Melut Basin is much further away from CASZ than the Muglad Basin, it was relatively weakly influenced by the strike-slip, while the effect of the East African Rift System during the late period was more obvious (Fairhead 1992). As a result, the accumulation conditions of the Melut Basin are similar to those of the Muglad Basin in some respects (Lirong et al. 2006) but also have their characteristics.

48

2 Regional Geological Characteristics …

0 Palogue Oil Field

50km

A′

No

rth

ern

De

pre

ssi on

rn

ste Ea

Adar--1

De

A

on

si es

pr

B′

Nal--1

ra

nt

Ce

B

ep

lD re

ste We

n

io ss

t

rn D

plif

ste We

rn U

C′

epr on

essi

C

ern

uth

So p De s res ion

Boundary fault

Major fault

Oilfield

Depression

Uplift

Well position

Sobat--1

Fig. 2.18 Structural outline of the Melut Basin (from Dou 2005)

Anza Basin The Anza Basin lies in the north-central part of Kenya, meeting the Lamu Basin in the south. The basin is shaped like a “trumpet” opening to the south, with a NW–SE spreading. It is 560 km long and 130 km wide, covering an area of up to 6.7 × 104 km2 (Morley et al. 1992; Winn et al. 1993; Foster and Gleadow 1996). The basement of the Anza Basin is composed of Precambrian metamorphic rocks. The sedimentary cover developed in the Late Jurassic and continued into the Neogene. The southeast part of the basin is superimposed on the Karoo rift. The Neogene in the northwestern part of the basin is superimposed on the Great Rift Valley, which extends in a nearly north–south direction. The basin consists of three tectonic units: the Yamicha Depression, the Matasade Uplift, and the Chalbi-Kaisut Depression. The Yamicha Depression is the main body of the Cretaceous deposits in the basin, with a thickness of over 13 km in the center of the depression, which was

2.3 Basin Types and Petroleum Geological Characteristics

49

Fig. 2.19 Structural cross-sections of the Melut Basin (from Dou 2005). For location, see Fig. 2.18

the center of both sedimentation and subsidence during the Cretaceous. The thickness of the strata gradually decreases to the northwest but still reaches 5000-7000 m. The Anza Basin underwent sedimentation and filling of early rift and late postrift, mainly rifting of the Karoo age, Cretaceous-Paleogene rifting, and Neogene rifting deposits. This process formed a prominent double-layer sedimentary filling structure of lower rifts and upper Neogene wide coverage-type subbasins. The basin is dominated by Cretaceous rift deposits. However, Jurassic, Triassic, and Permian deposits occur sporadically in the lower part of the basin, east of the NS-trending main fault in the south (Figs. 2.20 and 2.21) (Liu and Chen 2014). Tectonic Characteristics of Basins The main strike of the rift in the Eastern Rift Basin Group is NW–SE, controlled by basement faults. The strike of the boundary faults of a few rifts is NS—for example, the eastern boundary fault in the Fula subbasin—but the faults in the sedimentary layers in the depressions are essentially NW–SE-trending (Fig. 2.22), reflecting the

50

2 Regional Geological Characteristics … SW Kaisut Subbasin

0

Kaisut Depression

Matasade Uplift

Kaisut Uplift

NE Yamicha Subbasin Duma stepfault belt

Yamicha N Depression (west)

Central Uplift

Eastern steep Yamicha N slope belt Depression (east) Neogene Paleogene

2000

Upper Cretaceous Depth (m)

4000

6000

8000

10000

Fluvial-alluvial fan

Fan delta

Fluvial-delta

Delta

Semi-deep lacustrine

Shallow lacustrine

Fault

Lower Cretaceous

0

5

10 15km

Jurassic

Fig. 2.20 Structural cross-section of the Anza Basin. Modified from Liu and Chen (2014)

primarily NE-SW orientation of the main regional stress field. The boundary faults and main faults controlling the rifts are generally steep in section and arranged in a ‘domino’ pattern (Daly et al. 1989). For example, the dip angle of the boundary faults of the main rifts in the Muglad Basin is between 30° and 60°, mostly greater than 45°. A balanced cross-sectional analysis of typical extensive seismic profiles shows that the main extension period of the rift was the Early Cretaceous, during which about 50% of the full extension occurred. Due to the relatively vertical fault plane, the overall extension of the basin is small. The total extension of the Muglad and Melut Basins reached 75 km, representing a stretching factor of 1.25–1.40. Of this total, the extension of the Muglad Basin is 26% (32 km) in the north and 32% (30 km) in the South, and the extension of the Melut Basin is 21% (22 km) (McHargue et al. 1992). Accumulation Model The Eastern Rift Basins were intensively extended and faulted during the Early Cretaceous, providing the prerequisites for the formation of faulted deep lacustrine basins and a superior hydrocarbon-generating environment. Extensive semi-deep– deep lacustrine dark mudstone deposits, rich in lacustrine organisms, formed primary source rocks in the Lower Cretaceous. The organic matter is predominantly Type II1 , and the thermal evolution analysis of source rocks indicates that the maturity threshold depth of the Lower Cretaceous source rocks ranges between 2500 and 2900 m (Mohamed et al. 1999, 2000; Tong et al. 2004; Dou et al. 2005, 2007, 2013). The low formation temperature in the Early Cretaceous and rising in the Paleogene caused these source rocks to begin generating hydrocarbons in large quantities at the end of the Paleogene, with the oil and gas characterized by late accumulation (Bouaziz et al. 2015). The main reservoirs in this area are primarily composed of quartz sandstone and feldspathic quartz sandstone of medium–high porosity. However, differences in the tectonic locations and evolutionary histories of the Muglad and Melut Basins have led to significant disparities between the basins in the temporal and

2.3 Basin Types and Petroleum Geological Characteristics

51

Fig. 2.21 Comprehensive column of the Anza Basin. Modified from Liu and Chen (2014)

spatial distributions and the effectiveness of reservoirs. For example, the average quartz content in sandstones in the Paleogene Yabus and Samma Formations in the Melut Basin is more than 80%, with porosity of over 25% and permeability greater than 1000 mD. The average quartz content of sandstones in the Cretaceous Bentiu Formation in the Muglad Basin is 74%. The great bulk of the reserves (80%) is distributed above the Lower Cretaceous source rocks, forming an "above-source play" for hydrocarbon accumulation (Yandoka et al. 2017). In recent years, some discoveries of the "in-source play" type have been made in the AbuGabra Formation, mainly in the Sufyan, Fula, and Bamboo Subbasins and the surrounding areas.

52

2 Regional Geological Characteristics …

Fig. 2.22 Fault distribution of different formations in the Fula Subbasin, Muglad Basin

However, the scale of reserves is not large. Although the hydrocarbon accumulation conditions of the Muglad Basin are similar to those of the Melut Basin in some respects, they are pretty distinctive in others due to the different tectonic locations of the basins. Hydrocarbon Accumulation in the Antithetic Fault Block in the Muglad Basin In the Muglad Basin, the Late Cretaceous and Paleogene rifts superimposed on one another, resulting in the widespread shattering of the Lower Cretaceous structure. Many earlier uplifts and anticlines also suffered fracturing, forming a series of antithetic fault block traps (Nie et al. 2004). The wide distribution of the Upper Cretaceous regional cover in the Aradeiba Formation allowed a wealth of oil and gas to accumulate directly in the reservoirs in the Bentiu and lower Aradeiba Formations, forming multiple antithetic fault block hydrocarbon accumulations (Fig. 2.23). Statistics indicate that more than 70% of demonstrated reserves in the Muglad Basin are in the antithetic fault block traps of the Bentiu and Aradeiba Formations (Bang et al. 2015). The large Fula Oil Field in the Fula Depression has reserves of nearly 1 × 108 t. The OWC of the Bentiu Formation reservoir is inclined in a NE-SW direction, with a tar mat developed at the bottom of the reservoir (Dou et al. 2013). Inter-Age Accumulation of Oil and Gas in the Melut Basin In the Late Cretaceous, there was slight significant subsidence in the Melut Basin, which has no large-scale shore-shallow lacustrine facies. Instead, the basin was dominated by huge and extensively distributed sandstone deposits. The sandstone thickness/formation thickness ratio is much higher than that of strata of the same age in

2.3 Basin Types and Petroleum Geological Characteristics

53

Fig. 2.23 The distribution model of hydrocarbon accumulations in the Muglad Basin (from Lirong et al. (2006). a—Post-rift period (Late Cretaceous); b—Syn-rift period (early Late Cretaceous); c—Post-rift period (late Early Cretaceous); d—Syn-rift period (Early Cretaceous)

the Muglad Basin. The sandstone thickness/formation thickness ratio (generally 55– 83%) of the upper segment of the Upper Cretaceous is higher than that of the lower segment of the Upper Cretaceous (47–65%). The Upper Cretaceous lacks regionally distributed mudstones to cover oil and gas accumulation, so the oil and gas generated in the underlying Lower Cretaceous source rocks migrated vertically along faults and accumulated in the Paleogene sequence of the rift stage. More than 95% of the demonstrated reserves discovered are in the Paleogene (Fig. 2.24). An example is the Palogue Oil Field, which has an area of more than 80 km2 and geological reserves of 5 × 108 t. The major reservoirs are in the Palaeogene Yabus and Samma Formations, with thin oil reservoirs discovered in the deep Upper Cretaceous and the Lower Cretaceous. Enrichment and Accumulation of Hydrocarbons Controlled by Structural Accommodation Zones in the Plane The superimposition of multi-stage rifts in the Eastern Rift Basins means that accommodation zones are highly significant in hydrocarbon accumulation. According to their scales and characteristics, two types of accommodation zones are distinguished.

Fig. 2.24 The distribution model of hydrocarbon accumulations in the Melut Basin. From Dou et al. (2007)

54

2 Regional Geological Characteristics …

The first type is inter-depression accommodation zones, which are found between subbasins (or depressions); the second is intra-depression accommodation zones, which occur within the depressions themselves. For instance, the transfer zone between the Bamboo and Unity Depressions in the Muglad Basin is a typical inter-depression accommodation zone. It is an early paleohigh that has undergone long-term successive stages of development. Later faults and active source rocks on both sides of the zone have provided large volumes of oil and gas (Morley et al. 1990a, 1990b). Oil fields such as the El Toor, Toma South, Wizeen, Wizeen North, El Nar, El Nar North, El Harr, and Faras East have been discovered, providing high yields. Most local traps in this belt are structurally antithetic fault blocks, and the pay zone is the Bentiu-Aradeiba sandstone, with 20% of the total demonstrated reserves of the two depressions (Tong et al. 2004). Intra-depression accommodation zones are more conducive to the enrichment of oil and gas. The demonstrated reserves in the Fula-Moga accommodation zone in the Fula Depression account for 90% of the total reserves in the entire depression, and 90% of those are concentrated in the compressional anticline in the BentiuAradeiba Formations. In the Northern Depression of the Melut Basin, the Palogue accommodation zone developed during the Paleogene, controlling the development of delta sand bodies and providing a favorable enrichment area for oil and gas. As a result, a world-class large oil field—the Palogue Oilfield—was formed (Petracca 1986).

2.3.2 Inverted Rift Basins The inversion effect in the basins of Central Africa has been widely documented (Genik 1992, 1993; Lirong et al. 2011; Xiao et al. 2014). The Benue Graben in the West African Rift System is a typical strongly inverted rift (Popoff 1990). The “Central Rift Basins” of CARS show prominent inversion characteristics, with the inversion gradually becoming weaker from west to east (Burke et al. 1972). The Doba-Doseo-Salamat Basin Group The Doba, Doseo, and Salamat Basins (also known collectively as the Southern Chad Basin) are located in southern Chad and the northern part of the Central African Republic and are controlled by the Borogop Fault (Fig. 2.25). The total area of the three basins is 10.5 × 104 km2 and they and the Bongor Basin may be a single large rift basin before the Paleogene, the Southern Chad Basin. Of the three, the Doba Basin is mostly within Chad, and the Doseo and Salamat Basins span Chad and the Central African Republic. The Doba Basin has undergone the highest degree of exploration, with nearly 1.5 × 108 t of recoverable reserves already discovered. The Doseo Basin has also been explored to some extent, with several small oil and gas fields discovered. The Salamat Basin has the lowest degree of exploration, with only a sparse seismic grid. Only one exploration well has been drilled—well Aoukale-1 in the Central African Republic.

2.3 Basin Types and Petroleum Geological Characteristics

55

Fig. 2.25 Structural outline of the Doba-Doseo-Salamat Basins. Modified from Genik (1992)

There are two principal types of faults in the basins: rotating plane normal faults and listric normal faults, steep in the upper part and gentle in the lower part. In section, the dipping angles of the listric faults are generally between 50°and 60°, with individual faults having angles up to 80°–90° (Fig. 2.25), which is significantly steeper than comparable faults in the Eastern Rift Basins. In profile, most of the main faults run from the basement up to the bottom of the Paleogene. The fault displacement of boundary faults, or faults controlling secondary structural belts in the basins, decreases from bottom to top, generally displaying a negative flower structure combination style. Most of the antithetic or synthetic transfer faults associated with main syn-sedimentary faults in the Southern Chad Basin run through the bottom boundary of the Upper Cretaceous. These accommodation faults mostly formed in the Early Cretaceous. In the basin, the faults and structures are NW–SE-trending, running obliquely to the basin’s boundary. This is because the extension direction during the Early Cretaceous was mainly NE-SW, matching the direction of the regional stress field. The main faults are NW-trending, although there are many NE-trending faults in the basin (mainly transfer faults), and the displacement is only a few hundred meters. The basin group has experienced two rifting phases. During the early Cretaceous, intense activity in the syn-sedimentary faults caused extensive extensional rifting. This was the principal period of faulting, and, at this time, the basin formed part of the strike-slip extension faulted depression group. During the late Cretaceous, syn-sedimentary faults developed, with fault displacement becoming successively smaller, the intensity of fault activity weakening, and the control effect of the faults on the Upper Cretaceous decreasing. The basin at this time appears to have been a weak extensional rift. During the Paleogene, fault activity stopped, and the formation thickness stabilized. The basin then underwent post-rift deposition during the depression period, with the reversal intensity of the rift valley weakening from west to east (Figs. 2.26, 2.27 and 2.28).

56

2 Regional Geological Characteristics … A

A′

0

Lower Cretaceous

Upper Cretaceous

TWT (ms)

1000

2000

Basement

2189m

3000

Fig. 2.26 Regional seismic profile of the Doba Basin (for location, see Fig. 2.25) 0

Kibea--1

B

B′ Cenozoic Upper Cretaceous Lower Cretaceous

TWT (ms)

1000

2000

3000

Basement

4000

Central Depression

Kikwey tectonic zone

Southern slope

Fig. 2.27 Regional seismic profile of the Doseo Basin (for location, see Fig. 2.25) 0

C

DO431exty

DO431 Cenozoic Upper Cretaceous

2000

3000

Lower Cretaceous

TWT (ms)

1000

Basement

4000

Fig. 2.28 Regional seismic profile of the Salamat Basin (for location, see Fig. 2.25)

C′

2.3 Basin Types and Petroleum Geological Characteristics

57

Three sets of sedimentary strata developed in the basins. From old to young, they are Lower Cretaceous fluvial and lacustrine deposits, Upper Cretaceous fluvial sandstone deposits, and Neogene fluvial coarse clastics and lacustrine sandstones. The thickest of the strata is up to 1500 m. The Cretaceous is still relatively complete of these deposits, with a deposition thickness of 3000–5000 m. Baggara Basin-Sufyan Subbasin The Baggara Basin is a small graben located in southwestern Sudan. It extends the Salamat Basin, which lies to the east. The area is less than 2000 km2 . Seismic data for the area are few, with few two-dimensional data available. In the plane, the basin shows en echelon faults, reflecting the basin’s strike-slip and pull-apart properties. The maximum thickness of the formation in the basin is estimated to reach 9 km (GRAS 2005). However, only one exploration well has been drilled— well Khadari-1—which revealed a formation similar to the Muglad Basin. The top of the Paleogene is a regional unconformity (Fig. 2.29). Situated in the northernmost part of the Muglad Basin, the Sufyan Subbasin is a significant tectonic unit in the CASZ, with a length of 70 km, a width of 40 km, and an area of 2800 km2 . Two sets of faults—NNW-SSE-trending and NE-SW-trending— are developed in the depression (Fig. 2.30). The NNW-SSE-trending faults control deposition, and the NE-SW-trending faults are adjusting faults. The depression has obvious characteristics of a pull-apart basin. The total extension of the depression is 38.3%. Extension during the Early Cretaceous was 34% (88.9% of the total extension), during the Late Cretaceous 3.1%, during the Paleogene 1.3%, and during the Neogene a further 1.3%. The stretching factor is 1.36–1.49 (Yassin et al. 2017). Three rifting episodes also occurred in the depression. Of these, the Lower Cretaceous was the main stage, with a thickness of up to 5000 m. Upper Cretaceous rifts developed in succession, with the boundary faults controlling deposition. The thickness of the formation is 1000–1500 m. Paleogene rifts are not well developed and contain depression-type deposits with a thickness of less than 300 m (Fig. 2.31). Apatite fission-track analysis of wells SufS-1 and Tomat-1 indicates that the depression developed successively. At the same time the Tomat Uplift was uplifted by more than 1000 m during the Late Cretaceous-Paleocene, reflecting the differential influence of regional uplifting. Overall, the inversion of the basin is not significant, and ‘flower’ structures are only found in the east (Fig. 2.32). Hydrocarbons Accumulation Characteristics In the Doba and Doseo Basins, the Lower Cretaceous, which is in the mature-highmature stage, is the only effective source rock. The Upper Cretaceous is the principal play, the main trap type is a compressional anticline, and the primary reservoir body is composed of fluvial arkose. The Kome, Bolobo, Miandoum, Belanga, Mangara, Kibea, and other oil fields have been discovered in these basins, all having “abovesource play” accumulation characteristics (Walters 1991). The largest oil field is the Kome Oil Field, with recoverable reserves of nearly 0.72 × 108 t (Peterson 1983). It is a typical compressional anticline structure (Genik 1992). The Sufyan Subbasin has been relatively extensively explored, and oilfields such as the Sufyan, Sufyan

58

2 Regional Geological Characteristics …

Fig. 2.29 a Structure map of the top Bentiu and b NNW-SSE trending seismic profile of the Baggara Basin

W, and Higra have been discovered. The main oil pay is the upper member of the Augare Formation in the Lower Cretaceous, which has thin reservoirs. Heavy oil has been discovered in only one well in the Bentiu Formation. This shows that the pool-forming pattern and hydrocarbon distribution law of the Central Rift Basins are quite different from those of the Eastern Rift Basins (Elder et al. 1984).

2.3 Basin Types and Petroleum Geological Characteristics

59

Fig. 2.30 Fault strike of different formations in the Sufyan Subbasin, Muglad Basin

2.3.3 Regional Inversion Characteristics Since the Late Cretaceous, major global tectonic events have included the collision of the Eurasian and African plates, the continued expansion of the Pacific Ocean, and the formation of the Madagascar Ocean caused by the separation of India and Madagascar. Due to these and other tectonic processes, several short-lived but widely

60

2 Regional Geological Characteristics …

distributed regional compression/compression-shear structures, tectonic inversions, and other events developed within the African Plate, resulting in three structural layers in the region. Three major regional unconformities developed between these layers: the unconformity between the Early Cretaceous rift sequence and the Late Cretaceous rift sequence, the unconformity between the Paleogene rift sequence and the Late Cretaceous, and the unconformity between the Neogene and the Paleogene (Guiraud and Maurin 1992). The unconformity formed during the Late Cretaceous Santonian Period (85–83 Ma) has received the most interest (Guiraud and Bosworth 1997). The abundance of seismic data from basins in CASZ, particularly the wealth of three-dimensional seismic data acquired in recent years, indicates that there may have been three phases of inversion events in the region: the Santonian event, the Paleocene event, and the Miocene event. The impact of the Santonian event itself may have been exaggerated, and it may include the Paleocene event. The most significant inversion period is likely to be throughout the Late Cretaceous-Paleocene, when all the upper and lower Cretaceous strata in CASZ experienced unified deformation, forming many compressional inversion anticlines (Oden et al. 2016). This inversion period was mainly concentrated in the Bongor Basin and the Doba-Doseo-Salamat Basins in the west of CASZ. The Miocene inversion was a regional event that ended the evolution history of the rift basins in CASZ and brought the entire area into a depression stage. The boundary faults of the rifts in the rift basin are generally steep. Thrusting and formation of reverse faults did not occur easily under compression, so a series of compressional anticlines formed. These anticlines are often concentric, with the anticlinal axis perpendicular to the boundary fault and the closure amplitude of different layers having the characteristics of “small at the bottom and large at the top” (Fig. 2.31).

Fig. 2.31 Seismic profile of the Sufyan Subbasin, Muglad Basin (for location, see Fig. 2.30c)

2.3 Basin Types and Petroleum Geological Characteristics Fig. 2.32 3D seismic profile of the Heglig Oil Field in the Muglad Basin (from Hassan et al. 2017) showing the inversional anticline structure on the top Bentiu Fm

61

F1

A

Top of the Ar

adeiba Fm. sa

Top of th

ndstone

e Bentiu

Fm.

Santonian Event After the Santonian age, the Central African region entered the Late Cretaceous cycle of rift development, contacting the underlying first rift cycle with a regional unconformity that corresponds to the top of the Bentiu Formation in the Muglad Basin (Fairhead et al. 2013). In the Muglad Basin, the Darfur Group was in unconformable contact with the underlying Bentiu Formation during the second rift stage. Inverted asymmetric anticlines and reverse faults have been identified on the top of the Bentiu Formation in the Heglig Oilfield (Fig. 2.32) (Hassan and Nadi 2015; Hassan et al. 2017). Overall, however, the anticline amplitude and the displacement of the reverse fault are comparatively small, indicating a low compression intensity. From the perspective of the Muglad Basin, the centers of deposition and subsidence in each rift in the Bentiu Formation and the overlying Aradeiba Formation are primarily successive. There is no apparent compressional inversion. In the rift basins in the west of CASZ, such as the Doba-Doseo-Salamat Basin, both the Lower and the Upper Cretaceous are composed of successive sedimentary developments (Figs. 2.26, 2.27 and 2.28). In the eastern part of the Khartoum-BlueNile Basin Group, the Upper Cretaceous and the underlying Lower Cretaceous are in apparent angular unconformity contact, which shows that the Santonian event had a more profound impact on the rift basins in eastern Sudan (Robertson Research International 1985). Paleocene Event In the rift basins in the west of CASZ, the Paleocene event corresponded to an episode of magmatic activity about 65 Ma. Intrusive rocks of this period have been drilled in the Bongor and Doba Basins. In the western Doba Basin, the entire Cretaceous compressional inversion was uplifted by 2500 m (Genik 1992). The Upper Cretaceous was uplifted to the surface (Fig. 2.26), with a degree of inversion similar to the Benue Graben. In the Doseo Basin (Fig. 2.33), the Salamat Basin (Fig. 2.28), and the Sufyan in the Muglad Basin, large numbers of flower structures developed (Fig. 2.31). In

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2 Regional Geological Characteristics …

Fig. 2.33 Typical flower structure in the Doseo Basin (DO-431)

some areas of the basins, semi-graben-type rifts and normal faults, which had formed in earlier stages, experienced reversed activity, forming negative inversion structures. In seismic profiles, a structural form of normal faults, “lower depression and upper uplift”—or upper folds and lower normal faults—developed. Miocene Event Intensive reverse uplifting occurred in central Africa at the end of the Oligocene– Miocene. This was a regional tectonic event, which ended the development of the rift basins in CASZ and caused the zone to enter a stage of thermal subsidence. This event left a large regional unconformity that extends across almost all WCARS. A regional unconformity also formed in the Eastern Basin Group, with broad basin sediments. In the Kaikang trough of the Muglad and Melut Basins, there is unconformable contact between the Paleogene and the Neogene. Compression in the Melut Basin is stronger than in the Muglad Basin, where a series of compressional anticlines formed (Fig. 2.34).

References

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Fig. 2.34 Compressional anticline structure formed by inversion at the end of Miocene in the Western Depression of the Melut Basin

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Bouaziz A, El Asmi AM, Skanji A, et al. A new borehole temperature adjustment in the Jeffara Basin (southeast Tunisia): Inferred source rock maturation and hydrocarbon generation via onedimensional modeling. AAPG Bull. 2015;99(9):1649–69. Browne SE, Fairhead JD. Gravity study of the Central African Rift System: a model of continental disruption 1. The Ngaoundere and Abu Gabra rifts. Tectonophysics. 1983;94(1–4):187–203. Bumby AJ, Guiraud R. The geodynamic setting of the Phanerozoic basins of Africa. J Afr Earth Sc. 2005;43(1):1–12. Burk K, Dewey JF. Two plates in Africa during the Cretaceous? Nature. 1974;249(5455):313–6. Burke KC, Dessauvagie TFJ, Whiteman AJ. Geological history of the Benue Valley and adjacent areas. Afr Geol. 1972;1(8):187–205. Burke K, MacGregor DS, Cameron NR. Africa’s petroleum systems: four tectonic ‘Aces’ in the past 600 million years. Geol Soc Lond Spec Publ. 2003;207(1):21–60. Cahen L, Snelling N, Delhal J & Vail J. The geochronology and evolution of Africa, Clarendon Press. 1984. Coulon C, Vidal P, Dupuy C, Baudin P, Popoff M, Maluski H, Hermitte D. The mesozoic to early cenozoic magmatism of the Benue Trough (Nigeria); geochemical evidence for the involvement of the St Helena Plume. J Petrol. 1996;37(6):1341–1358. Daly MC, Chorowicz J, Fairhead JD. Rift basin evolution in Africa: the influence of reactivated steep basement shear zones. Geol Soc Lond Spec Publ. 1989;44(1):309–34. Dou L, Xiao KY, Hu Y, Petroleum geology and a model of hydrocarbon accumulations in the Bongor Basin, the Republic of Chad, AC TA PET ROLEI SINICA, 2011, 32(3). Lirong D, Dingsheng C, Zhi L, et al. Petroleum geology of the Fula sub-basin, Muglad Basin, Sudan. J Petrol Geol. 2013;36(1):43–59. Lirong D, Kunye X, Dingsheng C, et al. Petroleum geology of the Melut Basin and the Great Palogue Field, Sudan. Mar Pet Geol. 2007;24(3):129–44. Lirong D, Zhiwei Z, Dingsheng C. Regional seal control on oil accumulation in Muglad Basin of Sudan. Acta Petrol Sinica. 2006;27(3):22–26. Elder RB, Attanucci V, Clark PA, et al. Adar-Yale reservoir analysis study, Melut Block, Sudan. 1984. Fairhead JD, Binks RM. Differential opening of the Central and South Atlantic Oceans and the opening of the West African rift system. Tectonophysics. 1991;187(1–3):191–203. Fairhead JD. Geophysical controls on sedimentation within the African rift systems. Geol Soc Lond Spec Publ. 1986;25(1):19–27. Fairhead JD. Late Mesozoic rifting in Africa. Triassic-Jurassic Rifting Cont Breakup Orig Atlantic Ocean Passive Margins Part B Dev Geotectonics. 1988a;22:821–31. Fairhead JD. Mesozoic plate tectonic reconstructions of the central South Atlantic Ocean, the role of the West and Central African Rift System. Tectonophysics. 1988b;155(1–4):188–91. Fairhead JD. The West and Central African rift system: forward. Tectonophysics. 1992;213(1– 2):139–40. Fairhead JD, Green CM, Masterton SM, et al. The role that plate tectonics, inferred stress changes and the stratigraphic unconformities have on the evolution of the west and Central African rift system and the Atlantic Continental Margins. Tectonophysics 2013;594:118–127. Fitton JG. The Benue trough and Cameroon line—a migrating rift system in West Africa. Earth Planet Sci Lett. 1980;51(1):132–138. Foster DA, Andrew JW Gleadow. Structural framework and denudation history of the flanks of the Kenya and Anza Rifts, East Africa. Tectonics (1996);15(2): 258–271. Friedrich L et al. Metamorphism, isotopic ages and composition of lower crustal granulite xenoliths from the Cretaceous Salta Rift, Argentina. Contrib Miner Petrol (1999);134(4):325–341. Genik GJ. Petroleum geology of Cretaceous-Tertiary rift basins in Niger, Chad, and Central African Republic. AAPG Bull. 1993;77(8):1405–34. Genik GJ. Regional framework, structural and petroleum aspects of rift basins in Niger, Chad and the Central African Republic. Tectonophysics. 1992;213(1):169–85.

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Giedt NR. Unity field—Sudan, Muglad rift basin, Upper Nile province. In: Beaumont EA, Foster NH, editors. Structural traps III: tectonic fold and fault traps: AAPG treatise of petroleum geology atlas of oil- and gas fields. 1990. p. 177–97. Girdler RW, Fairhead JD, Searle RC, et al. Evolution of rifting in Africa. Nature. 1969;224(5225):1178–82. Girdler RW. Processes of planetary rifting as seen in the rifting and break up of Africa. Tectonophysics. 1983;94(1–4):241–52. GRAS. Geological map of the Sudan, scale 1: 2000,000. 2005. Gregory JW. Contributions to the physical geography of British East Africa. Geogr J. 1894;4(4):289– 315. Guiraud R, Binks RM, Fairhead JD. Chronology and geodynamic setting of Cretaceous-Cenozoic rifting in West and Central Africa. Tectonophysics. 1992;213(1–2):227–34. Guiraud R, Bosworth W, Thierry J, et al. Phanerozoic geological evolution of Northern and Central Africa: an overview. J Afr Earth Sc. 2005;43(1):83–143. Guiraud R, Bosworth W. Senonian basin inversion and rejuvenation of rifting in Africa and Arabia: synthesis and implications to plate-scale tectonics. Tectonophysics. 1997;282(1):39–82. Guiraud R, Maurin JC. Early Cretaceous rifts of Western and Central Africa: an overview. Tectonophysics. 1992;213(1–2):153–68. Ho K-S, et al. 40Ar–39Ar dating and geochemical characteristics of late Cenozoic basaltic rocks from the Zhejiang–Fujian region, SE China: eruption ages, magma evolution and petrogenesis. Chem Geol 2003;197(1–4): 287–318. Japsen P, Chalmers JA, Green PF, et al. Elevated, passive continental margins: not rift shoulders, but expressions of episodic, post-rift burial and exhumation. Glob Planet Change. 2012;90:73–86. Jia J, Liu Z, Miao C, Fang S et al. Depositional model and evolution for a deep-water sublacustrine fan system from the syn-rift Lower Cretaceous Nantun Formation of the Tanan Depression (Tamtsag Basin, Mongolia). Mar Pet Geol. 2014;57:264–282. ISSN 0264-8172. Jorgensen GJ, Bosworth W. Gravity modeling in the Central African rift system, Sudan: rift geometries and tectonic significance. J Afr Earth Sci (and the Middle East). 1989;8(2–4):283–306. Khain VY. The role of rifting in the evolution of the Earth’s crust. Tectonophysics. 1992;215(1– 2):1–7. Klemme HD. Petroleum basins—classifications and characteristics. J Pet Geol. 1980;3(2):187–207. Klitzsch E. Northwestern Sudan and bordering areas: geological development since Cambrian time. Berl Geowissenschaftliche Abhandlungen. 1984;50:23–45. Kogbe CA. The trans-Saharan seaway during the Cretaceous. In: The geology of Libya, vol 1. Academic Press London. 1980. p. 91–96. Landes KK. Petroleum resources in basement rock. AAPG, 1960;44(10):1682–1691. Le Bas MJ, Le Maitre RW, Streckeisen A, Zanettin B et al. Subcommission on the Systematics of Igneous Rocks, A Chemical Classification of Volcanic Rocks Based on the Total Alkali-Silica Diagram. J Petrol 1986;27(3):745–750. Lowell JD, Genik GJ. Sea floor spreading and structural evolution of southern Red Sea. AAPG Bull. 1972;56(2):247–59. Makris J, Rihm R. Shear-controlled evolution of the Red Sea: pull apart model. Tectonophysics. 1991;198(2–4):441–66. Mascle J, Blarez E, Martinbo M. The shallow structures of the Guinea and Ivory CoastGhana transform margins: their bearing on the Equatorial Atlantic evolution. Tectonophysics. 1988;155(1–4):193–209. McHargue TR, Heidrick TL, Livingston JK. Tectonostratigraphic development of the interior Sudan rifts, Central Africa. Tectonophysics. 1992;213(1–2):187–202. Mello MR, Katz BJ. Petroleum systems of South Atlantic Margins, vol. 73. AAPG Memoir. 1997. Millegan PS. Aspects of the interpretation of Mesozoic rift systems in northern Sudan using potential field data: gravity and magnetic case histories. Society of Exploration Geophysicists. 1990. Mohamed AY, Iliffe JE, Ashcroft WA, et al. Burial and maturation history of the Heglig field area, Muglad Basin, Sudan. J Pet Geol. 2000;23(1):107–28.

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Morley CK, Nelson RA, Patton TL, et al. Transfer zones in the East African rift system and their relevance to hydrocarbon exploration in rifts (1). AAPG Bull. 1990a;74(8):1234–53. Morley CK, Nelson RA, Patton TL, et al. Transfer zones in the East African rift system and their relevance to hydrocarbon exploration in rifts. AAPG Bull. 1990b;74(8):1234–53. Morley CK, et al. Tectonic evolution of the northern Kenyan Rift. J Geol Soc. (1992);149(3):333– 348. Morgan P, Baker BH. Introduction-processes of continental rifting. Tectonophysics. 1983;94:1–10. Moulin M, Aslanian D, Unternehr P. A new starting point for the South and Equatorial Atlantic Ocean, Earth-Science Reviews, 2010;98(1–2):1–37. ISSN 0012-8252. Nie CM, Chen FJ, Bai Y, et al. Geological characteristics of Fula oilfield in Muglad basin, Sudan. Oil Gas Geol. 2004;25(6):671–6. Oden MI, Umagu CI, Udinmwen E. The use of jointing to infer deformation episodes and relative ages of minor Cretaceous intrusives in the western part of Ikom—Mamfe basin, southeastern Nigeria. J Afr Earth Sc. 2016;121:316–29. Ogunmola JK, Ayolabi EA, Olobaniyi SB. Structural-depth analysis of the Yola Arm of the Upper Benue Trough of Nigeria using high resolution aeromagnetic data. J Afr Earth Sc. 2016;124:32– 43. Peterson JA. Assessment of undiscovered conventionally recoverable petroleum resources of Northwestern, Central, and Northeastern Africa (including Morocco, Northern and Western Algeria, Northwestern Tunisia, Mauritania, Mali, Niger, Eastern Nigeria, Chad, Central African Republic, Sudan, Ethiopia, Somalia, and Southeastern Egypt). In: Geological survey, Missoula, MT(USA). 1983. Petracca AN. Oil and gas development in central and southern Africa. AAPG Bull. 1986;70:1412– 57. Petters SW, Ekweozor CM. Petroleum geology of Benue trough and Southeastern Chad Basin, Nigeria: geologic notes. AAPG Bull. 1982. 66(8):1141–1149. Petters SW. Stratigraphic history of the south-central Sahara region. Geol Soc Am Bull. 1979;90(8):753–60. Robertson Research International. The Geology and petroleum potential of southern, central and Eastern Sudan, vol. 3. 1985. Schandelmeier H, Pudlo D. The Central African Fault Zone (CAFZ) in Sudan-a possible continental transform fault. Berl Geowiss Abh A. 1990;120(1):31–44. Schiefelbein CF, Zumberge JE, Cameron NR, et al. Petroleum systems in the South Atlantic margins. Geol Soc Lond Spec Publ. 1999;153(1):169–79. Schull TJ. Rift basins of interior Sudan: petroleum exploration and discovery. AAPG Bull. 1988;72(10):1128–42. Sengor AMC, Burke K. Relative timing of rifting and volcanism on Earth and its tectonic implications. Geophys Res Lett. 1978;5:419–421. Sun S-S, McDonough WF. Chemical and isotopic systematics of oceanic basalts: implications for mantle composition and processes. Geol Soc, London, Spec Pub 1989;42(1):313–345. Thomas D. Benue trough and the mid-African rift system. Oil Gas J. 1996;94(5):102–5. Tong XG, Dou LR, Tian ZJ, et al. Geological mode and hydrocarbon accumulating mode in Muglad passive rift basin, Sudan (in Chinese with English abstract). Acta Petrolei Sinica 2004;25(1):19– 24. Tong X, Xiao K, Dou L, et al. AAPG Annual Meeting, June 16-19, 2005, Calgary, Alberta: Great Palogue Field in Melut Basin, Sudan. Search & Discovery, 2005. Vail JR. Outline of the geology and mineral deposits of the Democratic Republic of the Sudan and adjacent areas: Overseas Geological & Mineralogical Resources. 1978. Vail JR. Pre-Nubian tectonic trends in Northeastern Sudan. J Geol Soc. 1972;128(1):21–31. Walters RF. Gorham oil field, Russell county, Kansas. Kansas Geol Surv Bull. 1991;228:112. Wilson M, Guiraud R. Magmatism and rifting in Western and Central Africa, from Late Jurassic to Recent times. Tectonophysics. 1992;213(1–2):203–25. Windley BF. The evolving continents. 2nd ed.: New York, Wiley, 1984. p. 399.

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Chapter 3

Tectonic Characteristics of Basins

The Bongor Basin is located in southwestern Chad, on the north side of the middle section of CASZ (Ziegler 1992). It is a Meso-Cenozoic intracontinental rift basin developed on Precambrian–basement and affected by the strike-slip of CASZ (Brown et al. 2014). It is WNW-trending, about 300 km long, 40–80 km wide, and covers an area of approximately 1.8 × 104 km2 . The basin has many similarities with other basins in CARS, such as basement age, regional structure, Lower Cretaceous strata, sedimentary characteristics, etc (Achauer et al. 1992). It also has unique features. Although without volcanic activity, the basin experienced intensive rifting during the Early Cretaceous (Guiraud et al. 1992). A set of coarse–fine-coarse lacustrine strata was deposited, typical in intra-continental passive rifts (Guiraud and Maurin 1992; Genik 1992, 1993). The sedimentary cycle of Late Cretaceous rift (Burk 1974) was completely eroded due to strong compression and uplift during the Late CretaceousPaleocene, with the eroded thickness reaching 1750 m (Bosworth 1992). This is a significant difference from other surrounding basins, indicating that the Bongor Basin is a strongly inverted rift basin (Chapman 2000). The Paleogene rift sequence is not well developed. It only appears in the hanging wall of the large boundary fault, where it is very thin, covering the Lower Cretaceous as a regional unconformity (Dai et al. 1998). The Paleogene diabase consisted of continental igneous rocks. It was drilled in the Lower Cretaceous lacustrine strata in wells Ronier-1 and Raphia SW-2, confirming that the basin has been transformed into an active rift basin. Structural features with many different styles, such as extension, strike-slip, compression, and inversion, are found in the basin (Glennie and Boegner 1981).

© Petroleum Industry Press 2023 L. Dou et al., Petroleum Geology and Exploration of the Bongor Basin, https://doi.org/10.1007/978-981-19-2673-0_3

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3.1 Basement Rock Characteristics Basement rock has been drilled in more than 130 wells in the Bongor Basin. Well Baobab C-2 in particular revealed basement rock nearly 1500 m thick. Laboratory analysis of multiple cores, cuttings, and sidewall coring samples from these wells reveals a complicated basement lithology. There are two major categories of rocks (magmatic rocks and metamorphic rocks), 14 subcategories, and more than 40 individual rock types (Xing 2006).

3.1.1 Rock Types Metamorphic Rock The basin contains regional metamorphic rocks, migmatite, and dynamic metamorphic rocks (Table 3.1). Migmatite is the most widely distributed metamorphic rocks, with regional metamorphic rocks being limited in distribution, generally in the form of relicts, and dynamic metamorphic rocks mainly being found near the fault zone. Regional Metamorphic Rocks Leptynite Leptynite is a generally dark gray biotite hornblende plagioclase granulite with fine-grained equigranular anhedral scaly granoblastic texture and massive structure (Fig. 3.1). The grain size is generally 0.15–0.50 mm. The rock alteration is severe. Chloritization occurs in most dark minerals, with carbonate metasomatism occurring locally. Quartz content is less than 10%, with anhedral granular shapes, smooth surfaces, and undulatory extinction. Plagioclase content is 55–60%, showing subhedral tabular-anhedral granularity with twin crystals developed, deep alteration, and sericitization. The content of granular, columnar, dark minerals is 25–35%, with the largest proportion being hornblende, followed by biotite (with some chloritization). If the dark minerals are biotite, they are metamorphosed into garnet biotite plagioclase metagranulitite. If the biotite content is greater than the hornblende content in the dark minerals, they are metamorphosed into hornblende biotite plagio-granulite. The total content of dark minerals in this type of rock is generally greater than 25%. Leptite Leptite is primarily light gray garnet monzo-leucogranulitite and biotite monzoleucogranulitite, with fine-grained equigranular anhedral granoblastic texture and

3.1 Basement Rock Characteristics

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Table 3.1 Statistics of rock types of metamorphic rocks Rock type

Subcategory

Main types

Main rock-forming mineral

Regional metamorphic rocks

Granulite

Garnet biotite plagioclase metagranulitite, biotite hornblende plagioclase granulite, hornblende biotite plagio-granulite, chlorite plagioclase leptynite, biotite hornblende plagioclase granulite

Dominated by plagioclase, hornblende, biotite, chlorite, followed by alkali feldspar, quartz

Leptite

Garnet monzo-leucogranulitite, Biotite monzo-leucogranulitite

Dominated by plagioclase, alkali feldspar, quartz, the content of biotite and other dark minerals is less than 10%

Gneiss

Mylonitized Biotite monzogneiss, hornblende-bearing biotite monzo-gneiss, chlorite plagioclase-gneiss, medium fine grained two-mica monzonitic gneiss

Dominated by plagioclase, hornblende, biotite, chlorite,wirh a small amount of alkali feldspar, quartz

Amphibolite

Fine grained biotite plagioclase amphibolite

Plagioclase, hornblende and biotite

Migmatized metamorphic rock

Migmatized granulite, granitic hornblende plagioclase gneiss agmatite

Dominated by plagioclase, hornblende, biotite, chlorite, followed by alkali feldspar, quartz

Migmatite

Injection migmatite Banded migmatite, augen Dominated by migmatite, leptite plagioclase, migmatite hornblende, biotite, chlorite, followed by alkali feldspar, quartz Migmatitic gneiss

Migmatitic gneiss

Plagioclase, hornblende, alkali feldspar, biotite, chlorite, quartz (continued)

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Table 3.1 (continued) Rock type

Dynamometamorphic rock

Subcategory

Main types

Main rock-forming mineral

Migmatitic granite

Monzonitic migmatitic granite, alkali feldspar migmatitic granite, plagioclase migmatitic granite

Dominated by quartz, plagioclase, alkali feldspar, with a small amount of biotite, hornblende, etc

Tectonic breccia

Granitic breccia

Dominated by quartz, plagioclase, alkali feldspar, with a small amount of Biotite and hornblende, etc

cataclasite

Cataclastic (alkali feldspar) migmatitic granite, cataclastic quartz monzonite, cataclastic leptite migmatite, (felsic) morbruk rock, felsic granulitic rock, cataclastic monzo (migmatitic) granite, cataclastic migmatitic gneiss, cataclastic migmatite, cataclastic hornblende-bearing biotite monzo-gneiss, cataclastic chlorite plagioclase leptynite, cataclastic syenite, cataclastic granitic chlorite plagioclase leptynite agmatite

Dominated by plagioclase, alkali feldspar, and quartz, followed by hornblende, biotite, etc

Mylonite

Mylonitic tolanite, mylonitic chlorite plagioclase-gneiss, mylonitic migmatitic gneiss

Dominated by plagioclase, alkali feldspar, followed by quartz, hornblende, biotite and chlorite

massive structure (Fig. 3.2). The grain size is 0.10–1.40 mm. Quartz content is 20– 40%, plagioclase content is 30–40%, alkali feldspar content is 20–40%, and the content of dark minerals is less than 5%. Gneissic Rock There are two subcategories of gneiss. The first is dark gray mingled with offwhite hornblende-bearing biotite monzo-gneiss, with scaly granuloblastic texture

3.1 Basement Rock Characteristics

73

Fig. 3.1 Biotite hornblende plagioclase granulite (well Baobab C-2, 1591 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light; PI—plagioclase, Hbl—hornblende

Fig. 3.2 Biotite monzo-leucogranulitite (well Mimosa E-2, depth: 1756.46 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light; Kfs—Kfeldspar, Qtz—quartz, PI—plagioclase

and gneissic structure (Fig. 3.3). The grain size is 0.20–5.40 mm overall. The quartz content is 10–12%, the plagioclase content is 53–65%, the hornblende content is 8–15%, and the biotite content is 16–20%. The total content of dark minerals in this kind of rock in this area is usually greater than 25%. The second subcategory is gray green, mixed with a small amount of pink chlorite plagioclase-gneiss, with scaly granoblastic texture and gneissic structure (Fig. 3.4). The crystal grain size is 0.30–2.80 mm, the quartz content is generally less than 5–10%, the plagioclase content is 65–75%, and the chlorite content is 23–26%. This type of rock is formed by retrograde metamorphism. The content of dark minerals is high, generally greater than 25%, and fractures are poorly developed, filled with chlorite, etc. Amphibolic Rock The area is dominated by fine-grained biotite plagioclase amphibolite, with particle sizes mostly less than 1.00 mm. The mineral composition is mainly plagioclase and hornblende, followed by biotite. The hornblende has undergone intense chloritization, followed by calcite metasomatism, and has a fine-grained column crystalloblastic texture and massive structure (Fig. 3.5). The grain size is 0.20–1.00 mm. The

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3 Tectonic Characteristics of Basins

Fig. 3.3 Hornblende-bearing biotite monzo-gneiss (well Mimosa-9, 1665 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light; Qtz—quartz, Bt—biotite, PI—plagioclase

Fig. 3.4 Chlorite plagioclase-gneiss (well Lanca SE-1, 808.98 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light; PI—plagioclase, Cal— calcite, Chl—chlorite,

hornblende content is 40–50%, plagioclase content is 40–50%, and biotite content is 10–15%. When this type of rock is at the top of a buried hill, some hornblende dissolution pores occur, but dissolution pores and fractures are not well developed when it is in the deep part of a buried hill (Chang et al. 2002).

Fig. 3.5 Diopside-bearing biotite plagioclase amphibolites (well Baobab C-2, 1828 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light

3.1 Basement Rock Characteristics

75

Fig. 3.6 Migmatized biotite hornblende plagioclase granulite (well Baobab C-2, 1596 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Kfs—K-feldspar, Qtz—quartz, Bt—biotite, PI—plagioclase, Hbl—hornblende

Migmatite Migmatite is the product of regional metamorphic rocks modified by migmatization. It is commonly composed of residual metamorphic matrix palaeosome and neogenic felsic (granitic, quartz) veins. According to the degree of migmatization (from weak to strong), migmatite can be divided into migmatized metamorphic rock, injection migmatite, migmatitic gneiss, and migmatitic granite. Migmatized Metamorphic Rock This type of rock is only slightly migmatized, and the content of neogenic vein material is normally less than 15%. The Bongor area, is mainly migmatized granulite, including migmatized biotite hornblende plagioclase granulite, migmatized biotite hornblende plagioclase granulite, etc. The rock is generally grayish-white/black, with equigranular anhedral granoblastic texture and parallel oriented or banded structure. The content of vein material is less than 10% (Fig. 3.6), and the grain size is generally 0.20–3.20 mm. Quartz content is 14% -24%, plagioclase content 40–50%, K-feldspar content 5–10%, hornblende content 13% -24%, and biotite content is mostly less than 10%. Injection Migmatite Injection migmatite is matrix palaeosome rocks, with a 15–50% content of neogenic felsic vein material. The boundary between the matrix palaeosome and the vein material is clear and is dominated by mechanical injection with local metasomatism. Metasomatism of minerals in matrix palaeosome is not strong, but metasomatic reactions, metasomatic recrystallization, and recrystallization also occur. The matrix palaeosome rocks in the area are predominantly dark gray granulite, with gray leptite and dark gray gneiss occurring locally, featuring granitic injected vein material. In the granulite, as the degree of migmatization deepens, the content of dark minerals decreases, beneficial for the formation of reservoirs. The rocks are mostly dark gray mixed with gray-white, tight and stiff, with banded structure, scaly granoblastic texture, and average grain size of 0.20–2.50 mm. The main mineral components

76

3 Tectonic Characteristics of Basins

are quartz, plagioclase, alkali feldspar, and biotite. When leptite is migmatized and injected into the rock as vein material with 15–50% content, it is called leptite migmatite, which can be further divided into granitic biotite plagiogneiss augen migmatite (Fig. 3.7), granitic garnet biotite plagioclase metagranulitite banded migmatite (Fig. 3.8) and leptite migmatite (Fig. 3.9). Migmatized Gneissic Rock In this rock type, migmatization is strong, and the content of residual matrix palaeosome is less than 50%. Due to strong metasomatism, there is no obvious difference or boundary between the matrix palaeosome of the residual metamorphic rock and the neogenic felsic vein material. Profound changes have occurred to the original regional metamorphic rocks, and only minerals resistant to change remain, often dark minerals. The primary migmatized gneissic rock type in the area is augen migmatitic gneiss (Fig. 3.10). The rock is primarily light pink, mixed with black/green and dark green. Only small amounts of residual dark oriented matrix migmatized palaeosome, have granoblastic texture and augen or gneissic structure. Quartz content is 25–30%,

Fig. 3.7 Granitic biotite plagiogneiss augen migmatite (well Mimosa-10, depth: 984.14 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Kfs—K-feldspar, Qtz—quartz, Bt—biotite, PI—plagioclase

Fig. 3.8 Granitic garnet biotite plagioclase metagranulitite banded migmatite (well Baobab C-2, depth: 1515 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Qtz—quartz, Bt—biotite, PI—plagioclase, Mc—microcline

3.1 Basement Rock Characteristics

77

Fig. 3.9 Leptite migmatite (well Baobab C-2, depth: 1472 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Qtz—quartz, Bt—biotite, PI—plagioclase, Mc—microcline

Fig. 3.10 Augen migmatitic gneiss (well Mimosa-10, depth: 1070.36 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Kfs—K-feldspar, Qtz—quartz, Bt—biotite

plagioclase content is 30–40%, K-feldspar content is 35–45%, and the content of biotite is 8–10%. Migmatitic Granite Migmatization is strongest in this rock type. The lithology is similar to granite with magmatic crystallization. The composition is equivalent to granite or granulodiorite. However, a certain number of unevenly distributed spots, streaks, or lumps with concentrated dark minerals can still be found, which generally represent residual matrix palaeosome following metasomatism. The dark minerals are mostly hornblende, followed by biotite, etc. Plagioclase and K-feldspar contents vary between samples. Some are largely composed of plagioclase or alkali feldspar, with no (or only very small amounts of) K-feldspar (plagioclase). However, some have almost the same contents as the two types of feldspar. Migmatitic granite can thus be divided into plagioclase migmatitic granite, monzonitic migmatitic granite (Fig. 3.11), and alkaline feldspar migmatitic granite (Fig. 3.12), although alkaline feldspar migmatitic granite predominates.

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3 Tectonic Characteristics of Basins

Fig. 3.11 Monzonitic migmatitic granite (well Mimosa-10, depth: 1070.36 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Kfs—Kfeldspar, PI—plagioclase, Cal—calcite

Fig. 3.12 Alkali feldspar migmatitic granite (well RaphiaS-11, depth: 1411.24 m). The left is a normal light photomicrograph of the core, and the right is a photomicrograph under cross-polarized light. Qtz—quartz, Pth—perthite

Dynamometamorphic Rock Dynamometamorphic rock is the product of dynamic metamorphism (cataclasis) of various types of rocks, including tectonic breccia (Fig. 3.13), crush rock (Fig. 3.14), and mylonite (Fig. 3.15). It is usually found in fault zones or the upper parts of buried hills (Hu et al. 1981). Magmatic Rock Intermediate rocks and acid rocks dominate the magmatic rocks in the Bongor Basin..The intermediate rocks include syenite, quartz syenite, monzonite, quartz monzonite, diorite, and tolanite (Table 3.2). The acid rocks include monzonitic granite, syenogranite, and alkali feldspar granite. A QAP triangular diagram of intrusive rocks shows the molecular abundance of standard minerals converted from the compositions of major elements in the rock. The magmatic rocks in this area are basically granite, syenite, quartz monzonite, monzonite, monzonitic diorite, diorite, etc. (Fig. 3.16).

3.1 Basement Rock Characteristics

79

Fig. 3.13 Granitic breccia (well Baobab C-2, depth: 615 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Qtz—quartz, Cal—calcite

Fig. 3.14 Granitic morbruk rock (well Baobab C-2, depth: 610 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Qtz—quartz

Fig. 3.15 Altered mylonitized tolanite (well Baobab C-2, depth: 931.5 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. PI—plagioclase, Cal—calcite, Chl—chlorite

Acid Rocks Acid rocks mainly include monzonitic granite (Fig. 3.17), syenogranite and alkalifeldspar granite, generally pink, light pink, light flesh gray, etc., with subhedral granular texture and massive structure. The main components are quartz, plagioclase,

80

3 Tectonic Characteristics of Basins

Table 3.2 Statistics of types of magmatic rocks Subclass Main types of intermediate rock Main rock-forming minerals Intermediate rock Diorite

Acid rock

Diorite, tolamite, diorite Mainly plagioclase, porphyrite, granodiorite, gabbro hornblende, a small amount of diorite quartz

Syenite

Quartzsyenite, syenite, monzonite, quartzmonzonite

Mainly plagioclase, alkali feldspar, followed by hornblende, a small amount of quartz, biotite

Granite

Syenogranite, monzonitic granite, alkali feldspar granite

Quartz, plagioclase, alkali feldspar

Q (Quartz) Baobab C- 2 Baobab C- 5 Cassia- 2 Mimosa- 10 Phoenix S- 3 65

35

rite

lite

odio

a Ton

Gran

Granite

Raphia SW- 2

20

80 Dio

Syenite

rite

Quartz Quartz diorite monzonite

5

95 Monzodiorite

Monzonite A (Alkali Na-K feldspar)

35

65

90

P (Plagioclase)

Fig. 3.16 Classification of plutonic rocks in the basement of six wells (template from Cuong and Warren 2009)

alkali feldspar, and a small amount of biotite or hornblende, etc. In the mineral composition, the content of quartz, plagioclase, and alkali feldspar is 20–30%, 10– 40%, and 40–70%, respectively. The content of two kinds of feldspars in diverse types of granites is nearly equal, or one of them is dominant. The plagioclase is mostly subhedral tabular and granular, and the alkali feldspar crystals are coarse and mostly late crystallization, usually distributed in the upper part of the buried hill.

3.1 Basement Rock Characteristics

81

Fig. 3.17 Monzonitic granite (well Baobab C-2, 975 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Kfs—K-feldspar, Qtz—quartz, PI—plagioclase

Intermediate rock Syenite (quartz syenite) Syenite is found in the Phoenix and Baobab buried hills. The coring interval of well Phoenix S-3 mainly consists of this type of rock. The difference between syenite and quartz syenite is that the quartz content of syenite is less than 5%, and that of quartz syenite is 5–20%. It is pink mixed with black. A slight gneissic structure of dark minerals, with subhedral granular structure and grain sizes of 0.30 to 4.40 mm, can be observed in cores (Fig. 3.18). The content of quartz is 3–8%, the content of plagioclase is 10–20%, the content of alkaline feldspar is 49–84%, and the content of hornblende is 4–8%, and the content of biotite is 3–15%. Monzonite (Quartz Monzonite) Monzonite is found in the areas of wells Raphia SW-2 and Baobab C-2. It is light pink and contains oil-bearing structural fractures revealed by sidewall coring and emit yellow fluorescence (Fig. 3.19). It has a subhedral-anhedral granular texture, a massive structure, and a grain size is 0.20–2.40 mm. The content of quartz is 6–13%,

Fig. 3.18 Syenite (well Phoenix S-3, depth: 1466.06 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Kfs—K-feldspar, Hbl—hornblende

82

3 Tectonic Characteristics of Basins

Fig. 3.19 Quartz monzonite (well Raphia SW-2, depth: 1113.4 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Qtz—quartz, Pth—perthite

the content of plagioclase is 30–40%, the content of alkaline feldspar is 40–65%, and the content of hornblende is 4–5%, with partial chloritization. The difference between this kind of rock and monzonite lies in the quartz content. Diorite and Tolanite Diorite and tolanite are found in the form of veins in well Baobab C-2. The difference between diorite and tolanite is the quartz content. If the content of quartz is less than 5%, it is diorite. If the content of quartz is 5–20%, it is tolanite. The rock is black/gray or dark gray, with a massive, subhedral granular structure (Fig. 3.20). The mineral grain size is 0.20–3.60 mm. The primary mineral components are plagioclase and hornblende. The content of quartz is 3–12%, the content of plagioclase is 50–65%, the content of hornblende is 25–28%, and there are traces of biotite and K-feldspar.

Fig. 3.20 Tolanite (well Baobab C-2, depth: 935.5 m). The left is a natural light photo of the core, and the right is a photomicrograph under cross-polarized light. Kfs—K-feldspar, Qtz—quartz, Bt—biotite, PI—plagioclase, Hbl—hornblende

3.2 Tectonic Characteristics of Basins

83

3.1.2 Determination of the Ages of Rocks Eighteen samples of basement rock from different depths in multiple wells in the basin were selected for trace element analysis and isotopic dating of individual zircon particles using laser probe plasma mass spectrometry (LAM-ICP-MS). Zircon Morphology and Characteristics of Internal Structure Cathodoluminescence imaging of zircon is the most effective way of revealing the morphology and internal structure and determining the genetic type of zircon. Zircon formed in diverse geological environments has a variety of structural types. For instance, magmatic zircon has a typical oscillatory zones or fan-shaped zoning structure. Metamorphic zircon has its characteristic internal structures, including nonzoning, weak zoning, cloud-like zoning, fan-shaped zoning, etc. (Wu et al. 2004). Because of this, the study of the microstructures of zircon is a reliable way to determine the age of zircon U–Pb. The cathodoluminescence images of the 18 samples can be divided into three types: (1) the typical oscillatory zone structure of magmatic zircon (Fig. 3.21a, b); (2) oscillatory zone structure with rims (Fig. 3.21c); (3) a core–edge structure (the core is zircon remnants from the protolith, and the edges are formed by crystallization (Fig. 3.21d)). Isotopic dating was carried out on more than 1000 zircons separated from the 18 samples. The results are favorable, with the measuring points forming a discordant line or age-related accumulation areas. The age corresponding to the upper intersection point on the concordia diagram should represent the formation age of the rock (Table 3.3). Combining this with known petrographic characteristics, it is found that the metamorphic rocks are mainly orthometamorphic rocks. The ages of protoliths are primarily concentrated in the range (616.0 ± 6.0) to (526.5 ± 2.7) Ma, and the metamorphic ages range from (553.0 ± 19.0) to (464.0 ± 5.0) Ma. The ages of magmatic rocks are mainly concentrated in the range (621.0 ± 16.0) to (525.3 ± 2.5) Ma. In terms of chronology, monzonitic granite and monzonite (syenite) were not formed by crystallization differentiation in the same period but were formed earlier. Monzonite and syenite were formed by crystal differentiation after the formation of monzonitic granite.

3.2 Tectonic Characteristics of Basins 3.2.1 Tectonic Characteristics of the Basement There is a large negative gravity anomaly zone in southern Chad, with an anomalous gravity value of -90mGal, covering an area of nearly 6 × 104 km2 . It is centered on the Doba Basin (Fig. 3.22) and encompasses the Doba, Bongor, Doseo, and Salamat Basins (Browne 1983). In the Bongor Basin, the low gravity anomaly is WNWtrending (Khain 1992). Its width is greatest in the middle of the basin, gradually

84

3 Tectonic Characteristics of Basins

Fig. 3.21 Cathodoluminescence image of zircon Zircon U–Pb isotopic dating

narrowing towards the east and west, with an overall fusiform shape. An area of basement rock uplift surrounds its periphery with a high gravity value (Li 1980). The low gravity area in the southeast of the basin is connected to the Doseo Basin— reflecting that the basin was connected to the rift basin in southern Chad in geological history—but its strata are significantly thinner than those of the Doseo Basin. Analysis of geophysical, geological, and drilling data indicates that the Bongor Basin has two groups of basement faults (Qiao et al. 1999); NE-SW-trending and WNW-ESEtrending (Fig. 3.23). The area with the greatest thickness of the Lower Cretaceous P + M formations corresponds to the low gravity area, indicating that the basement fault-controlled the deposition of the P + M Formations (Fig. 3.23) (Jorgensen 1989). The depocenters were successively deposited in the basin center in a WNW direction. The strata become thinner to the south and north, similar to the gravity anomaly in

Magmatic rock

816.70

1407.80

1410.60

1576.80

984.14

986.89

1304.41

1759.27

1756.10

1644.70

1653.60

538.90

540.50

543.10

1005.89

Raphia S-11

Raphia S-11

Raphia S-8A

Mimosa-10

Mimosa-10

Baohab C-2

Mimosa E-2

Mimosa E-2

Phoenix S-3

Phoenix S-3

Baohab C-2

Baohab C-2

Baohab C-2

Baohab C-2

815.20

Lanea SE-1

Lanea SE-1

800.87

Lanea SE-1

Metamorphic rocks

Depth (m)

Well number

Rock type

Monzonite

Monzonitic granite

Monzonitic granite

Monzonitic granite

Syenite

Quartz syenite

Alkali feldspar migmatitic granite

Alkali feldspar migmatitic graniteprotolith age

Alkali feldspar migmatitic granite

Biotite hornblende plagioclase granulite

Augen migmatite

Migmatitic granite

Pink migmatitic granite

Pink migmatitic granite

Garnet monzo-leucogranulitite

Migmatitic gneiss

Migmatized biotite hornblende plagioclase granulite

Lithology

Table 3.3 LAM-ICP-MS in-situ dating results of single-particle zircons in basement rock Neoproterozoic-Terreneuvian

597.0 ± 6.0

Neoproterozoic—Terreneuvian

525.3 ± 2.5

547.5 ± 3.1

621.0 ± 16.0

607.3 ± 11.0

(continued)

Neoproterozoic—Middle Ordovician

Formation age 557.1 ± 6.0 Age of metamorphic transformation 464.0 ± 5.0 600.0 ± 4.0

Protolith age- Mesoproterozoic, formation age- Neoproterozoic

Formation age 559.5 ± 9.0 Protolith age 1006.0 ± 12.0

946.0 ± 5.0

591.0 ± 4.0

526.5 ± 2.7

616.0 ± 6.0

601.7 ± 9.0

552.4 ± 2.2

597.6 ± 8.0

558.0 ± 5.0

553.0 ± 19.0

Agea

Ages (Ma)

3.2 Tectonic Characteristics of Basins 85

a

Depth (m)

991.12

Well number

Raphia SW-2

Monzonite

Lithology

According to the International Chronostratigraphic Chart (2015)

Rock type

Table 3.3 (continued) 544.4 ± 3.0

Ages (Ma)

Agea

86 3 Tectonic Characteristics of Basins

3.2 Tectonic Characteristics of Basins

87

Fig. 3.22 Bouguer gravity anomaly in the Southern Chad

D′ C′

2400

D

80

80 0

F2- 2

F1- 4 2400

F2- 7

28

00

20 00

0

F2- 4

24

00

20 0

20 00

12 00

2400

1600 3200

F1- 5

0

80

0

3200

C

B′

20 0

0

F1- 2

20km

E′

F2- 3

00

2400 2800 3200

0

F1- 1

2800

F2- 8

2 20 000 00

800

F2- 1

160 0

800 1200

32

160 0

F1- 6

E

F2- 6

A′

1200

1600 240

0

B

0 80 1200

F2- 5

400

200 0

F2- 9

F1- 3

200 0

2000

800

1200

160 0

0

Eroded line

Fault

A

0 12

800

400

Fig. 3.23 The Master faults in the basement of the Bongor Basin and the thickness trends of the Lower Cretaceous P and M Formations

the basin, indicating that the basement structure of the basin is the foundation for the development and evolution of the entire basin (Allen and Allen 1990).

3.2.2 Tectonic Units in the Basin Although the Southern Chad Basin has been under exploration and development for more than 40 years, the division has rarely been made between first- and second-order tectonic units in the basins, including the Bongor Basin (Genik 1992). Controlled by the opening of the Atlantic Ocean, the formation and evolution of the Bongor Basin were similar to the more intensively studied Recôncavo Basin in Brazil, so their tectonic units and divisions can be cross-referenced (Benkhelil et al. 1988). The interior of the Recôncavo Basin is cut by several NW–SE-trending transfer faults (Dou 2004). They divided the basin into three major sub-basins—in the northeast, middle, and south—each sub-basin further divided into platforms, Lows, and

88

3 Tectonic Characteristics of Basins

highs (Fairhead 1991). The crucial structural units are separated by faults (Figueiredo et al. 1994). The sedimentary cover in the Bongor Basin is composed of three vertically stacked structural sequences, with a maximum total thickness of 10 km. From bottom to top, the Precambrian crystalline basement, the Lower Cretaceous, and the Cenozoic (Binks and Fairhead 1992). There is an angular unconformity between the three structural sequences (Fig. 3.24). The Lower Cretaceous is the main exploration strata in the basin and contains a further sub-structural boundary (Klemme 1980). This boundary divides the Lower Cretaceous into two structural sequences; one formed during the early rapid stage (the P-M Formation) and the other formed during the late stable rifting stage (the K-B Formation) (Mann et al. 2003). These two substructural sequences are in contact by an overall parallel unconformity, with small angular unconformities occurring locally (Fairhead 1988a, 1988b). The Cenozoic is generally relatively thin, with a maximum thickness of 520 m, and contains an unconformity. The distribution of rifts in the basin is characterized by ‘south-north zonation and east–west block’. The depression has a half-graben structure, alternating between faults in the south and overlapping in the north in the west part of the depression and faults in the north and overlapping in the south in the east part, accommodated by a NE-trending fault (Fig. 3.23) (Sengor 1978). The dip angles of the WNW-trending boundary fault and the depression-controlling fault are between 30° and 50°, concentrated around 45° (Fairhead 1992). In contrast, the NE-trending fault is primarily an adjusting fault that controlled early deposition of the P Formation and experienced a certain amount of strike-slip during the late Late Cretaceous inversion. The dip angle of the fault is usually greater than 45°, with a maximum of 70° (Fig. 3.25). The Bongor Basin can be divided into three first-order tectonic units according to the characteristics of the Bouguer gravity anomaly in the basin, including factors such as basement structure, tectonic evolution, residual thickness of the strata, and distribution of boundary faults (Makris and Rihm 1991). The three tectonic units are the Northern Sub-basin, the Southern Uplift, and the Southern Sub-basin. The Northern Sub-basin is the main body of the basin (Fig. 3.26) (Lidmar-bergström 1999).

N 0

Neogene Paleogene

2000

3000

Lower Cretaceous

TWT (ms)

1000

4000 Precambrian

Fig. 3.24 Contact relationship between structural layers

3.2 Tectonic Characteristics of Basins

89

Fig. 3.25 Horizontal displacement-depth of the master faults in the Bongor Basin (For the fault number, see Fig. 3.23)

Ann

ona

Basin boundary

Dep

We ster

ress ion

Boundary line of sub-secondary tectonic unit

Basement fault

Fault

Uplift

Terrace

Depression

Slope zone

Ziziphus Terrace

nU

plif

t Del o Dep West ress ion Sou t

Cola Depression

Nor her

Norther

ther

n Su

Pera

nS

ubb

asi n

0

Boundary line of secondary tectonic unit

bba

sin

Depre ssion Delo E ast Dep ression

Man

n Slop

go D

e

epre s

sion

Moul

30km

Fig. 3.26 Division of tectonic units in the Bongor Basin

Depre

Pave tta N o

ssion

rth D

Pave tta So

uth D

epres

sion

epres

sion

90

3 Tectonic Characteristics of Basins

Northern Subbasin The northern sub-basin is about 260 km long, 40–60 km wide, and has an area of up to 1.527 × 104 km2 . From east to west, it can be further divided into five secondary tectonic units: the Pavetta North Depression, the Pavetta South Depression, the Moul Depression, the Mango Depression, the Pera Depression, the Cola Depression, the Ziziphus Terrace, and the Annona Depression, of which the Mango Depression is the largest. Moul Depression The Moul Depression is located at the easternmost end of the basin, with an area of 3822 km2 . It is composed of two subdepression—the Pavetta North subdepression and the Pavetta subdepression—which are controlled by two nearly WNW-ESEtrending north-dipping boundary faults. The current maximum thickness of the sedimentary strata of the two subdepression is about 4000 m, mainly Lower Cretaceous, with the thickness of the Neogene strata being less than 200 m. The subsidence centers and depocenters are located in the northern parts of the subdepression, transitioning to the southern outcrop area by the fault terraces to the south (Fig. 3.27a). Two oil-bearing structures—Moul-1 and Pavetta-1—have been discovered in the Pavetta subdepression. Mango Depression The Mango Depression is the largest rift in the northern sub-basin, covering an area of 6770 km2 . It can be further divided into the Pera subdepression and the northern slope (Fig. 3.27b). The area of the Pera subdepression is approximately 3686 km2 . Its east and west sides are separated from the Moul Depression and Cola Depression by basement adjusting faults. Structurally, the Mango Depression is faulted in the south part and overlapped in the north part, steep in the south, and gentle in the north. The depression-controlling fault is a major fault at the southern boundary. The maximum thickness of the current sedimentary strata is up to 10 km, mainly Lower Cretaceous, with the thickness of the Cenozoic strata being less than 600 m. The subdepression transitions northwards towards the Mimosa-Phoenix-Lanea structural belt on the northern slope. In the Pera subdepression, there is a regional angular unconformity between the Paleogene and the underlying Lower Cretaceous and a general parallel unconformity between the Neogene and the Paleogene. There is angular unconformity contact between the Neogene and the Paleogene on the northern slope, which gradually merges into a regional unconformity to the north. The Paleogene has been completely denuded. The northern slope is formed by inversion at the end of the Late Cretaceous, with an area of 3074 km2 . During the Early Cretaceous, small WNW-ESE-trending secondary rifts developed on the northern slope, including the Mimosa N subdepression, the Baobab N subdepression, and the Daniela subdepression. These subdepression were divided by basement fault horsts and subsequently inverted to form anticlinal structural zones, such as the Ronier anticline zone, the Mimosa-KublaPhoenix structural zone, the Baobab-Raphia structural zone, the Daniela anticline

3.2 Tectonic Characteristics of Basins

91 Pavetta North Depression

Pavetta South Depression

A

A′

0

TWT (ms)

B 1000

R

2000

M

Neogene

K Basement

P 3000 0

(a)

6km

B

Pera Depression

0

Neogene Palaeogene B

TWT (ms)

1000

R K

2000

M 3000

P

Basement

4000 0

(b)

6km

C

Cola Depression

0

Ziziphus Terrace

C′

Neogene B

1000 TWT (ms)

B′

Northern slope

R 2000

K M

3000

Basement

4000 0

P (c)

6km

D Southern Subbasin 0

Southern Uplift

Annona Depression

D′

Neogene B

1000 TWT (ms)

R K 2000 M 3000 P 4000 0

6km

Basement

(d)

Fig. 3.27 Regional seismic profiles of the Bongor basin (For location see Fig. 3.23)

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3 Tectonic Characteristics of Basins

0

18km

Basin boundary

Basement fault

Fault

Boundary line of sub-secondary tectonic unit

Boundary line of third-order tectonic unit

Northern slope zone

Sag

Positive tectonic belt

k

Mimosa Sag Baobab N Sag Cassia Sag Daniela S Sag Daniela Sag Lanea Sag Ronier structural belt Prosopis structural belt Mimosa-Phoenix structural belt Baohab-Raphia structural belt k Daniela structural belt l Lanea structural belt

l

Fig. 3.28 Division of structural units in the Northern Slope of the Mango Depression

zone, and the Lanea structural zone (Fig. 3.28). The basin’s oil and gas discoveries are mostly concentrated on the northern slope. Cola Depression The Cola Depression is located in the central and western part of the basin, with 1388 km2 . It is faulted in the north and overlapped in the south. The boundary fault is the northern Cola Fault. The current maximum thickness of the sedimentary strata is about 8000 m, mainly Lower Cretaceous, with the thickness of the Cenozoic strata being less than 500 m. The subsidence center and depocenter are in the northern part of the rift, transitioning as fault terraces towards the uplift to the south. The depression contacts the Ziziphus Terrace to the north, along the Cola Fault (Fig. 3.27c). Ziziphus Terrace The Ziziphus Terrace is situated in the northern-central part of the basin. It is a shallow-buried terrace at the basin margin. The overall shape is rhombic, with the four edges bounded by faults. The length is about 40 km, the width is 30–35 km, and the area is about 1208 km2 . The thickness of the overlying strata is less than 3000 m (Fig. 3.27c). Annona Depression The Annona Depression is located at the western end of the basin. It is a half-graben rift controlled by the northern boundary fault of the southern uplift. It has a northwest trend and is about 50 km in length, 35-45 km in width, with an area of about 2080 km2 . It is faulted in the south and overlapped in the north, steep in the south, and gentle in the north. The maximum thickness of sedimentary strata is about 5000 m. The subsidence center and depocenter are in the south of the rift, and there is a transition to the Soudio slope from the fault terrace towards the north (Fig. 3.27d).

3.2 Tectonic Characteristics of Basins

93

Southern Sub-Basin Located in the southwest of the basin, the Southern subbasin is about 90 km long, 15–25 km wide, and has an area of about 2115 km2 . It can be divided into three secondary tectonic units: the Delo East Depression, the Delo Depression, and the Delo West Depression (Fig. 3.29). The Delo West Depression is situated at the western end of the basin. The main body is a graben controlled by faults. It is NW-trending, about 25 km long, 15– 20 km wide, and covers an area of approximately 428 km2 . The western section of the Depression is faulted in the north and overlapped in the south; steep in the north and gentle in the south. The boundary fault is the Delo North Fault. The central section of the depression is a graben. The eastern section of the depression is faulted in the south and overlapped in the north; steep in the south and gentle in the north. The boundary fault is the Delo West Fault. The current maximum thickness of the sedimentary strata is about 1600 m, and the subsidence center and depocenter are in the middle of the rift, contacting the uplift by faults to the north and south (Fig. 3.29a, b). The Delo Depression is located southwest of the basin. It is a half-graben rift controlled by the Delo North Fault. It is NW-trending, about 35 km long, 20-25 km wide, and covers an area of about 762 km2 . It is faulted in the north and overlapped in the south; steep in the north and gentle in the south. The boundary fault is the Delo North Fault. The maximum thickness of the current sedimentary strata is about 4000 m. It is the deepest tectonic unit in the Southern Sub-basin. The subsidence center and depocenter are in the northern part of the rift and transition to the uplift area to the south through a fault terraces t zone. Its contacts with the western uplift to the north via faults. So far, one significant discovery has been made in the depression: the Delo-1 oil-bearing structure (Fig. 3.29a, c). Located in the basin’s southern part, the Delo East Depression is a half-graben rift controlled by the Delo South Fault. It is NW-trending, about 45 km in length, 22 km in width, and has an area of about 925 km2 . It is faulted in the south and overlapped in the north, steep in the south, and gentle in the north. The controlling fault is the Delo South Fault. The current maximum thickness of the sedimentary strata is about 1600 m. The subsidence center and depocenter are in the southern part of the rift. It is in contact with the northern sub-basin via faults (Fig. 3.29a, d). Western Uplift The Western Uplift is situated southwest of the basin. It is a long and narrow uplift, spreading in a northwest direction, with about 615 km2 . It dips into the basin to the east, dividing the basin into two sub-basins to the north and south (Fig. 3.26). The Western Uplift is mainly covered by thin Cenozoic, with a thickness of less than 500 m (Galbraith 1990).

94

3 Tectonic Characteristics of Basins

3km

N

C′

A′

B′ Southern Uplift

ess

on

epr

ssi

e epr

ion

D elo

Delo East

D

D est

Depression

W elo

D A

B

C

Neogene 0

a A′

A B

K

TWT

ms

R 1000

Basement 2000

2km

b Delo West Depression

Western Uplift Neogene

B

B′

0

1000

R

TWT

ms

B

K Basement

2000 M 2km

c Delo Uplift

0

Western Depression

Neogene

C

C′ B

K

TWT

ms

R 1000

Basement

2000 2km

d Delo East Depression

Fig. 3.29 Division of tectonic units in the Southern subbasin

Cola Depression

3.3 Tectonic Evolution of the Basin

95

3.3 Tectonic Evolution of the Basin The CARS rift basin experienced three stages of rift development, in the Early Cretaceous, Late Cretaceous, and Paleogene, with three corresponding sets of strata. The Lower Cretaceous is the best preserved in the Bongor Basin (Lowell 1985). However, the Upper Cretaceous is entirely absent, and the Cenozoic is eroded to very thin strata in regional angular unconformity contact with the underlying Lower Cretaceous. It is unclear whether this regional angular unconformity results from a hiatus in a stable environment or denudation of sedimentary strata in an unstable environment. Future study of this issue is crucial for restoring the tectonic evolution of the basin and oil and gas exploration.

3.3.1 Reconstruction of Burial History There are several methods to reconstruct the burial histories of sedimentary basins, including the comprehensive logging method, the interval transit time method, the vitrinite reflectance method, the seismic profile restoration method, and the apatite fission-track method. Combining and correlating results from several methods can more accurately restore the burial histories of the basin (Balestrieri et al. 2016). Comprehensive Logging Methods Mud logging is the most basic technique used in oil and gas exploration and development. It is the most convenient and direct method for the early discovery and evaluation of reservoirs. Its advantages include convenience, the diversity of underground information obtained, and the rapidity of analysis and interpretation. Gas logging records gaseous compounds with carbon numbers C1 to C5 as they are transported to the wellhead with returning drilling fluid during drilling. According to the gas composition, it can be roughly determined whether the strata currently being drilled have crossed the maturity threshold. In shallow layers, only C1 or C1 -C2 show is often obtained, with no heavy hydrocarbons. Once the drill has entered a mature oil-generating rock section, heavy hydrocarbons C4 -C5 begin to appear, and the total hydrocarbon content increases (Morley et al. 1990). The depth at which heavy hydrocarbons begin to appear continuously and the total hydrocarbon content increases significantly can be assumed to be the maturity threshold of the source rock. For example, in well Baobab SE-3, the total hydrocarbon content of the M Formation is less than 1% above 1510 m, with almost no heavy hydrocarbon components. Below 1510 m, the total hydrocarbon content rapidly increases to more than 5%, and the heavy hydrocarbons C4 -C5 appear continuously, with ratios of nC4 /iC4 and nC5 /iC5 greater than 1. This indicates that the dark mudstone in the well enters the mature hydrocarbon generation stage at 1510 m. The maturity threshold depth of the rift basin in the surrounding area is generally 3000 m, so the formation in well Baobab SE-3 must have been uplifted by about

96

3 Tectonic Characteristics of Basins

1500 m. The R Formation in well Ricinus-1 in the southern steep slope zone of the Mango Depression enters the maturity threshold at 1960 m, uplifted by about 1000 m in the late stage. Overall, the uplift amplitude of the steep slope zone of the basin is 1000–1500 m smaller than that of the northern slope. Acoustic Interval Transit Time Method The acoustic interval transit time method uses the relationship between interval transit times and the compaction degrees of clastic rocks to obtain the eroded thickness of mudstone strata (Guan 2001). There are two prerequisites. First, the compaction of the mudstones is not affected by time and is irreversible. Second, the thickness of redeposited strata is less than the thickness of the denuded strata. When these two prerequisites are met, the compaction trend line of the mudstone below the unconformity extends upward to ΔT0 (the propagation time of sound waves near the surface) and the paleosurface. The distance between the paleosurface and the unconformity is therefore the denudation thickness (Fig. 3.30). For this study, thirtyeight mudstone wells were selected for interval transit time analysis. The value of ΔT0 was calculated to be 633 μs/m based on the average ΔT0 of multiple wells in the basin, and the denudation thickness at the end of the Cretaceous at each well point was estimated to be 600–1600 m.

Fig. 3.30 Restoration of the Cretaceous denudation thickness of well Baobab N-1 (from Yu et al. 2013). The unit of interval transit time is μs/m, which is extrapolated to the surface according to the normal compaction curves of multiple wells. The interval transit time ΔT0 at the surface of the area is determined to be 633 μs/m, ln(ΔT0 ) = 6.45.

3.3 Tectonic Evolution of the Basin

97

Vitrinite Reflectance Method Vitrinite is a maceral, mainly composed of aromatic fused ring compounds. As the degree of coalification increases, the condensation degree of the aromatic structures also increases, resulting in an increase in vitrinite reflectance. Thermal cracking of kerogen is strongly associated with the evolution of vitrinite, so it is a good indicator of the maturity of organic matter. The deeper the thermal metamorphism of organic matter, the greater the vitrinite reflectance. Because vitrinite reflectance is irreversible, it can be used to calculate paleotemperatures. The hydrocarbon generation thresholds of weakly inverted rifts with the same regional geological background, similar geothermal gradients, and the same kerogen types can be used to infer the denudation thickness of strata (Gong et al. 2003). According to current data, the mature threshold depth of source rocks in the Bongor Basin is generally less than 2000 m. For instance, the mature threshold depths of wells Mimosa-1, Baobab-1, Calatropis-1, and Semegin-1 are 1225 m, 1500 m, 1660 m, and 1950 m, respectively (Fig. 3.31). The shallowest mature threshold depth in the Bongor Basin is only 890 m, while mature threshold depths in the adjacent Doba Basin are between 2700 and 3200 m. Therefore, it is inferred that the thickness of denudation is 1000–2000 m (Xiao et al. 2014). Seismic profile restoration method The major advantage of using seismic data to estimate the thickness of denudation by trend extension of stratum thickness is that it is not limited by well locations, so the thickness of stratum denudation in any one area can be continuously traced along seismic lines, revealing variations of the erosion thickness in the plane. The stratigraphic comparison method is a simple and traditional method for restoring the eroded thickness of strata. The principle is to use the thickness of strata in an uneroded area to determine the original deposition thickness, with the denudation thickness obtained by simply subtracting the current residual thickness of strata. This method has been enhanced by the wide use of seismic technology in oil and gas exploration in basins. Changes in formation thicknesses can be quite easily traced on a seismic profile, enabling calculation of the denudation thickness at any specific point. Figure 3.32 shows the principle and process of using the stratigraphic correlation method to estimate denudation thickness in wells BN4, BN8, and BN12 in the Baobab North subdepression in the Bongor Basin. The seismic profile shows that the seismic reflections of the Lower Cretaceous in the Baobab North subdepression are parallel (Fig. 3.32a), so the formation thickness is generally consistent. After the interval transit time method is used to restore the denudation thickness HN1 of well BN1, the denudation thicknesses of wells BN4, BN8, and BN12 can be calculated (Fig. 3.32b). HN4 , HN8, and HN12 are the denudation thicknesses of wells BN4, BN8 and BN12, respectively. Ht4 , Ht8, and Ht12 are the distances from the projection points of the three wells on the reference layer to the erosion surface, which can be obtained by time-depth conversion of the time differences of the seismic reflections.

98

3 Tectonic Characteristics of Basins

Fig. 3.31 Vitrinite reflectance method used to restore the thickness of stratum denudation (from Xiao et al. 2014) BN1 BN4

BN8

BN12 BN1

BN4

BN8

BN12

500 Eroded strata

ms TWT

Original top surface H N1

H N4

H N8

H N12

1000 E/K erosion surface H t4 Residual strata 1500

H t8

H t12 Referrence layer

S

a

Well-tie seismic profile

b Restoration model of erosion thickness

Fig. 3.32 Restoration of the Cretaceous denudation thickness of wells BN4, BN8 and BN12 (from Yu et al. 2013)

3.3 Tectonic Evolution of the Basin

99

Apatite Fission Track Method Apatite particles are common accessory minerals in sedimentary rocks, usually derived from crystalline basement rock, ancient sedimentary rocks, or recent volcanic activity. The first two of these three types contain apatite fission tracks, the characteristics of which reflect their origins. However, there are no apatite fission tracks when debris from contemporaneous volcanic activity is deposited. Fission of the radioactive element U238 in apatite forms a discernible radiation damage zone in the mineral lattice called a fission-track (Barbarand et al. 2003). In sedimentary rocks, when the temperature is lower than 50 °C, the length of authigenic fission tracks is 14–15 μm, with a standard deviation of ±1 μm. When the burial depth of the sedimentary rock increases and the temperature exceeds 50 °C, annealing will occur as the burial depth, and ground temperature increase, and the lengths of the fission tracks will become shorter. When the temperature is higher than 110–120 °C, the tracks will be completely annealed and become undetectable (Green et al. 1986; Laslett et al. 1987; Duddy et al. 1988; Green et al. 1989; Gleadow et al. 1986; Naeser et al. 1989). Later, when the sample has cooled to within the temperature range for partial annealing (110–60 °C), fission tracks begin to form again. Because the lengths of fission tracks within the partial annealing zone are consistent with the temperature, the combination of age and track length provides information on time, paleotemperature, age of uplifting and cooling, and the processes of tectothermal events. However, the lengths of apatite fission tracks are also affected by chlorine content; the higher the chlorine content, the longer the fission-track. Hence, the chlorine content of apatite must first be determined to obtain accurate age data. Cutting samples from various depths in four wells were selected from various locations in the Bongor Basin to determine the chlorine contents and the lengths of the apatite fission-tracks (Fig. 3.33). Testing was carried out in the Geotrack fission-track laboratory in Australia. Fission- track analysis adopts the external detector method (Gleadow and Duddy 1981) to calculate the age value (according to the ξ constant and the standard fission-track age equation recommended by the International Union of Geographical Sciences (IUGS) (Hurford and Green 1982, 1983). The median age of the apatite fission tracks was calibrated using the Zeta calibration method. The Zeta constant obtained in this experiment was 380.4 ± 5.7 a cm−2 . The closure temperature of apatite was set to be 110 ± 10 °C, and the temperature range of the partial annealing zone was (110 ± 10) °C–60 °C. Analysis of five samples at various depths from well Baobab SE-3, in the northern slope of the Mango Depression diverse two cooling events, at 95–45 Ma (Late Cretaceous-Eocene) and 14–0 Ma (Mid-Miocene-present). Analysis of three samples at various depths from well Raphia S-8A reveals two cooling events, at 75–45 Ma (Late Cretaceous-Eocene) and 20–5 Ma (Miocene). Analysis of six samples from well Semegin-1, in the southern steep slope zone of the Mango Depression, reveals only one cooling event, at 80–40 Ma (Late Cretaceous-Eocene). Analysis of six samples at variant depths in well DeloW-1, in the southern sub-basin indicated a single cooling event at 75–60 Ma (Late Cretaceous-Paleocene).A combined analysis of the four wells’ results indicates a general cooling event between 75–45 Ma, while

100

3 Tectonic Characteristics of Basins N

30

K1

40

0

80 2

90

50 60 70

km Depth

70

Stratigraphic age

40

1

60 Temperature

Depth

km

50 1

30

N E K1

80

2

90 100

100 200 Track length Ma a

400

km

30

K1

40 60

Stratigraphic age

70 80 0

100 200 Track length Ma b

300

120

Stratigraphic age 4

N

50 1

8 12 16 Mean length mm

Well Baohab SE-3

0

Depth

300

400

0

100

200 Track length

Temperature

0

2

110

3

3

Temperature

0

8 12 16 Mean length mm

Well Raohia S-8A

300

400

Ma

8 12 16 Mean length mm

d Well Semegin-1

Apatite fission-track age Increase in chlorinity Unconformity on the top of the Palaeogene Unconformity on the top of the Cretaceous Top of the Basement

30

K1

40

Depth

50 1

60 Stratigraphic age C1

2 0

100 200 Track length Ma

70 80 300

According to prediction results of corrected well temperature Temperature

N

km

0

8 12 16 Mean length mm

c Well Delo W-1

Fig. 3.33 Analysis parameters of apatite fission tracks of samples from four wells

the two wells on the northern slope experienced another cooling event between 14 and 5 Ma (Fig. 3.34). The average temperature of the basin’s present surface constant temperature zone is 29 °C, and the geothermal gradient is 30 °C/km. The paleogeothermal gradient estimated from vitrinite reflectance is also around 30 °C/km. Through simulation and combination with the results of apatite fission track analysis, it is inferred that the net uplift and erosion around well Baobab SE-3 is 1750 m. During the first stage of the cooling event, the well area was uplifted and eroded by 1450 m. Subsequently, 400 m strata were deposited by subsidence, followed by further uplift and erosion of 700 m during the second stage of the cooling event. Similarly, the area around well Raphia S-8A was uplifted and eroded by 1650 m overall. During the first stage of the cooling event, it was uplifted by 1450 m, followed by deposition of 400 m strata by subsidence, and then by uplift and erosion of 600 m during the second stage of the cooling event. The cooling event around well Semegin-1 resulted in net uplift and erosion of 1150 m and uplift and erosion of 1450 m around well Delo W-1. Combining the results of the four wells reveals that the basin was uplifted and eroded by 1150–1450 m at the end of the Cretaceous, with the northern slope experiencing further uplift and erosion of 600–700 m at the end of the Miocene. After the Miocene, the basin subsided, and strata about 300 m thick were deposited (Fig. 3.35). Based

3.3 Tectonic Evolution of the Basin

101

(c) Semegin-1

(a) BaobabSE-3

(b) RaphiaS-8A

(d) Delo-1

Fig. 3.34 Diagram of paleogeotemperature cooling events in four wells in the Bongor Basin, based on apatite fission tracks

on restoration and reconstruction using these methods, combined with the general regional seismic profile and other data, we could map the distribution trend of strata erosion throughout the entire basin from the late Late Cretaceous to the Eocene (Fig. 3.36). Analysis of this trend in conjunction with the overall regional seismic section (Fig. 3.27) indicates that the cooling event between the late Late Cretaceous and the Eocene caused uplift and erosion across the entire basin. It was an intense reversal event with great erosion thickness. The cooling event during the middle Miocene uplifted the northern part of the basin by as much as 1 km. In contrast, the southern part of the basin experienced a comparatively small uplift, with an amplitude below the analysis and detection range apatite fission track. This also explains the merging of the two shallow unconformities in the Pera subdepression of the Mango Depression into a regional unconformity on the northern slope (Fig. 3.24). It also confirms that the basin underwent stage sedimentation during rifting in the early Late Cretaceous but was subsequently uplifted and eroded. The regionally developed Paleogene rift sequence may not be developed in the Bongor Basin (Morgan P 1983).

102

3 Tectonic Characteristics of Basins E

O

Strata

M P

K

0

P

E

O

M

Strata

P

B

B

Cz

P

Cz

K

0

500

K M

1500

2000

2000 Pre-Є

Depth

1000

Pre-Є

1500 M

m

K

1000

Depth m

R

R

500

2500

2500

3000

3000

Delo W- 1 140

120

100

80

60

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Age Ma 3500 K

0

P

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Strata

P

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Baobab SE- 3 4000 140

120

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20

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K

P

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Strata

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1000 Cz

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Age Ma

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2500 K

Pre-Є

1500

Depth m

K P

m

M

1000

Depth

1500

R

500

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3500

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Semegin- 1 4500

3500 140

120

100

80

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40

20

0

140

120

100

80

Age Ma

60

40

20

0

Age Ma

Fig. 3.35 Reconstruction of the burial history of the four wells (For the locations, see Fig. 3.36) Bersay- 1

Fault

160

0 120

0 Ziziphu s- 1

Cassla- 1

00 Konier- 1

12

Prosopis- 1

1000

Mimosa- 1 Baobab- SE- 3120 0

0

Savonnier- 1

1200 0

120

1200

1800

Baobab- 1

Cailcedra- 1

0 12

Delo W- 1

Vitex- 1

Pera- 1

18001600 Raphia S- 8A

Kubla- 1

Delo- 1

00

1200

14

Scmcgin- 1

20

40km

1400

Daniela- 1

1000 Daniela- 2

Lanea E- 2

Bersay- 1

1000 Mango- 1

0

Dclo W- 1

Analysis of apatite fission track

Well site

00 16 0 0 14 Naramay- 1

Annona- 1

Pinch out

1000 1200

Fig. 3.36 Trend diagram of erosion thickness of strata caused by inversion events in the Bongor Basin

3.3 Tectonic Evolution of the Basin

103

3.3.2 Recovery of Extension-Compression History The Bongor Basin has experienced two stages of rift development. The Lower Cretaceous is preserved, but the Cenozoic is very thin, and deformation is weak (ChristieBlick and Biddle 1985). The main period of extension occurred in the Early Cretaceous. We selected ten large seismic sections, from east to west, to analyze the extent of extension and compression of the basin using the balanced section technique. Balanced profile analysis indicates that the extension amounts and extensional ratios of various areas in the Early Cretaceous basin are markedly different (Genik 1992). The extension amounts vary between 1150 and 1900 m, with an average of 1578.34 m, and the extensional ratio is between 2.08 and 3.90%, with an average of 2.87%. The extension amount of the central part of the depression is more than 1400 m, with an extensional ratio above 3%. Extension amount during deposition of the P-M Formations in early Cretaceous was the most intensive, accounting for 60– 70% of the total extension amount (Girdler et al. 1969). During this period, the basin experienced strong extensional rifting, intense activity along the boundary faults, and strong control over stratigraphic deposition (Liu et al. 2000). The thickness of the same formation on either side of the fault varies greatly. The growth index is between 1.2 and 1.9, with an average of 1.4. Similarly, the growth index of the master fault in the center of the depression is the largest, generally exceeding 1.5. Here, extension and rifting were at their most intense, and the subsidence amplitude (subsidence amount) was the greatest. Thus, the sedimentary thickness of the Lower Cretaceous reduced sharply from the deep sub-basin to the edge of the basin. Extension stress in the basin showed distinct differences during various geological periods and between individual parts of the basin. During deposition of the P-M Formations, the extension was more intense in the central part of the basin than on the east and west sides, with the extension amount being almost 8% greater. During deposition of the K-R Formations, the extension was weaker in the central part of the basin than on the east and west sides, with the extensional amount being 3–8% less. During deposition of the B Formation, the extension was weaker in the west of the basin, with the extensional amount being 5–7% less. It is a basin feature that different periods and locations have varying degrees of opening and control of sedimentation. North–south compression at the end of the Late Cretaceous resulted in compression and shortening of the basin (Fig. 3.24) (Fairhead 1986). Calculations based on the preserved Lower Cretaceous show that the horizontal shortening amount was between 315 and 800 m, with an average of 623.75 m and a shortening rate of 1.10. The shortening rate of the slope belt in the Mango Depression reached more than 1.3. Compression during this period caused a strong tectonic inversion of the depositional sequence in the basin deposited during the rifting phase, with extensive uplift and severe erosion (Cheng et al. 2003). As a result, the Upper Cretaceous in the basin was completely eroded, and the B Formation, and even the upper R Formation in some areas, were partially eroded. Cenozoic strata were generally oriented vertically, and the lateral compression and deformation were weak (Guiraud et al. 1992).

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3 Tectonic Characteristics of Basins

3.3.3 Evolution History of Basin Tectonic reconstruction, restoration of burial history, and extension-compression analysis allowed us to restore the evolution history of the basin fully. After the longterm weathering and denudation of the Precambrian crystalline basement rock from the Cambrian to Jurassic, the basin has experienced six distinct stages of evolution since the Cretaceous (Girdler 1983). Early Cretaceous Rift Period (145–100.5 Ma) The basin had prominent strike-slip pull-apart characteristics in the initial stage of its development, especially in the western part of the basin, where counter-Z-shaped faults developed (Liu et al. 2003). The NW–SE-trending faults were tearing faults with gentle fault surfaces, and the NE–SW-trending faults were strike-slip faults. A strong rifting happened during the deposition period of the P and M Formations in the Early Cretaceous. The crust was intensively extended and rifted, and the basement faults in the basin were reactivated or new faults generated (Daly et al. 1989). A series of WNW-ESE-trending, north- and south-dipping major faults, and NE-SWtrending adjusting faults with steep fault surfaces developed (Fig. 3.37). This created the basic pattern of faulting in the south and overlap in the north, alternating with faulting in the north and overlapping in the south, with multiple half-graben rifts in the basin (Maria et al. 2016). It also established the tectonic characteristics of the ‘east–west block’. Both sets of faults controlled the deposition of the P Formation. Coarse detrital sediments from the lower member of the P Formation were deposited at the bottom of the rift, which rapidly transitioned into semi-deep–deep lacustrine deposits in the upper members of the P and M Formations. They formed high-quality lacustrine source rocks and gradually overlapped the highs in the basement rock. During deposition of the K-R-B Formations in the late Early Cretaceous, the basin entered a stable rifting stage (Genik 1993). Extension gradually weakened, and although the boundary faults were successively active, the intensity and control of sedimentation were weakened. Sedimentation across the entire basin was relatively stable, but the property of half-graben rifting persisted. The sedimentary filling gradually changed from predominantly deep lacustrine mudstone to dominant sandstone, with the NE-SW-trending faults becaming weak. Late Cretaceous Rift Period (100.5–75 Ma) Basin comparison and reconstructions of burial histories suggest that the Bongor Basin should have developed a sedimentary sequence in the Late Cretaceous rift stage with a thickness between 1000 and 1200 m, similar to that of the Doba-Doseo Basin in the south (Burke et al. 1972). The Benue graben to the west of the basin and the Termit Basin to the north also developed this Late Cretaceous rift sequence, a set of marine strata (Liu et al. 2012).

3.3 Tectonic Evolution of the Basin

105

Fig. 3.37 Adjusting fault with a steep fault surface of the Cassia structural belt (for the location, see Fig. 3.23)

Late Cretaceous-Eocene Inversional Denudation Period (75–45 Ma) During this period, the basin experienced strong compression, uplift, inversion, and denudation, with a shortening rate of 1.1 in the short axis direction and erosion thickness reaching 1.2–1.5 km. The northern and western parts of the basin show large denudation thickness, with comparatively small denudation thickness in the southeastern part (Petters 1982). The Upper Cretaceous was completely eroded, and the Lower Cretaceous also eroded to varying degrees. The Lower Cretaceous sequence was compressed and reversed, especially at the Basin’s edge, with intense tectonic inversion (Wysick 1990). Several NE-SW-trending faults experienced transpressional reactivation, cutting the WNW-ESE-trending faults. This period was the main stage for compressive folds in the basin, and a series of compression anticlinal structural belts developed. The degree of inversion clearly shows ‘strong in the north and weak in the south, strong in the west and weak in the east’ (Fig. 3.38). Eocene-Early Miocene Weak Rifting Stage (45–14Ma) Comparative analysis of regional tectonic evolution and adjacent basins suggests that the Paleogene developed in the Bongor Basin. Weak rifting probably occurred in the Eocene–Oligocene, but there is little reliable evidence. Seismic sections of some areas in the basin show two obvious unconformities above the Lower Cretaceous, with some strata locally preserved between the two. These have been provisionally classified as Paleogene (Fig. 3.38). Inversional Denudation Period at the End of Miocene (14–5 Ma) At the end of the Miocene, the entire basin was uplifted and eroded again, with the degree of denudation being “strong in the west and weak in the east, strong in the

106

3 Tectonic Characteristics of Basins Naramay- 1

E 0

E

Neogene Palaeogene B

1000

TWT ms

R 2000

K

M 3000 P

Basement

Mango Depression

7km

Ziziphus terrace

Fig. 3.38 Regional seismic profile of the Mango Depression showing the inversion characteristics; for location see Fig. 3.23

north and weak in the south”. For example, in the Mango Depression, the uplift and erosion of the northern slope were intense, but the uplift in the south was small. The Lower Cretaceous was completely eroded in the basin’s north but not in the south. The Neogene was in direct unconformable contact with the underlying Lower Cretaceous. The two unconformities in the southern part of the basin merged into one on the northern slope of the Annona and Moul Depressions. Compression in this period was weak. Deformation of the Paleogene was also weak, only showing in the early compression uplift (high) zone, for example, in the Mimosa-Phoenix structural zone (Oden et al. 2016). Decline of the Basin in the Neogene (5 Ma to Present) More recently, the entire basin entered a stage of thermal subsidence, characterized by the formation of sub-basins. The subsidence rate of the basin was slow, with fault activity weakening or stopping altogether. The thickness of deposited strata was 100–300 m, with stable stratigraphic deposits and little horizontal change in the thickness. The depocenter moved to the center of the basin, and the secondary Depressions gradually disappeared, eventually becoming a unified sub-basin.

3.4 Structural Style The Bongor Basin is a Cretaceous rift basin formed in a background of strikeslip extension in the CASZ. It experienced complicated evolution stages of extension/strike-slip, compression, re-extension, and re-compression. Erosion intensity due to compression and uplift during the Late Cretaceous was great, so the

3.4 Structural Style

107

various inverted structures formed in the Upper Cretaceous have been completely denuded (Wang et al. 1989). The structural styles preserved in the basin are complex and diverse, featuring both extensional and compression inversional structures. According to their geneses, they can be divided into four styles: extensional, inverted, strike-slip, and diapir.

3.4.1 Extensional Structural Style Most of the extensional structural styles are of the basement-involved type, including rollover anticline, fault horst, consequent step-fault, antithetic step-fault, etc. However, they vary slightly in different parts of the depression (Windley 1984). Structural Styles in Steep Slope In eastern China, the structural styles of the steep slopes of every rift in the rift basins are complicated and diverse. Rollover anticlines related to listric faults and rampflat faults are common, and the occurrence of gentle boundary faults is a significant feature (Chen and Wang 1997; Lu et al. 1997; Qiao et al. 1999). The steep slope of the Bongor Basin varies. The boundary fault planes in the steep slope zones of primary rifts are steep, with dip angles around 70°. Rolling anticline structures are not well developed. The structural style is relatively simple; there are no ramp-flat faults or low-angle listric fault structures. Only small compression-reverse faulted anticlines and fault nose structures have developed (Fig. 3.27). Parallel fault terraces, tilted towards the deep part of the sub-basin, occur locally. Most of these fault terraces were established during the initial stages of later structural development and deformation (the late deposition of P Formation). Only master boundary faults have remained successively active, which has had a strong influence on the structural style of the upper caprock. The structures can be divided into three categories (Fig. 3.39) (Turcotte 1983): 1. Anticline-type steep slope: The anticline-type steep slope of the Bongor Basin is different from those contemporaneous steep slopes in eastern China. It is composed of steep boundary faults and compressional inversion anticlines in

Fig. 3.39 Structural styles of steep slope zone

108

2.

3.

4. 5.

6. 7. 8.

3 Tectonic Characteristics of Basins

hanging walls, such as the Cola anticline. This structural style is not well developed in the basin (Fig. 3.39a). Fault nose-type steep slope: The planes of boundary faults are steep, and dragtype or inversion-type fault noses develop on the hanging walls. This structural style is typical in the steep slope of the basin, for instance, in the southern steep slope of the Mango Depression (Fig. 3.39b). Fault terrace-type steep slope: The fault planes of the boundary faults are steep, with more than two parallel synsedimentary faults descending to the basin to form a stepped shape. These faults extend to the basement, forming fault terracetype steep slopes. Only basement-involved type fault terraces have developed in the basin. Caprock-slipping-type terraces did not develop (Fig. 3.39c). Structural styles in deep subbasin The deep subbasin zone has the thickest sedimentary caprock in the rift. It lies between the gentle slope zone and the steep slope. It has two main characteristics: the formation of the sub-basin zone is closely related to the structural style of basement involvement; the other is the poor inheritance of basement and cap structures. Styles associated with the basement-involved structure in deep sub-basin Normal fault combination opposite to the boundary fault Large-scale, simultaneously developed faults with opposite dips to the boundary normal faults form large grabens, and the common hanging wall forms the subsidence center and depocenter of the depression. Examples are the deep sub-basin zones of the Mango and Moul Depressions (Fig. 3.40a).

Normal Fault Combinations Parallel to the Boundary Fault The hanging walls of large, simultaneously developed faults with the same dip as the boundary normal faults form the subsidence center and depocenter of the depression. Examples are the deep sub-basin zones of the Cola and Annona Depressions (Fig. 3.40b).

a

Normal fault opposite to the boundary fault

Fig. 3.40 Structure styles of deep subdepressions

b Normal fault parallel to the boundary fault

3.5 Graben-Horst Integrated Slope

109

Fig. 3.41 Seismic profile showing a horst-graben combination

Structural Styles Related to the Cover’s Deformation Before the basin formed, the basement tilted or formed a low-amplitude graben-horst combination. While the basin was forming, this structure was covered by huge, thick sedimentary deposits and was dominated by tectonic activity in the sedimentary layer, with the basement becoming inactive. An example is the Ronier North subdepression (Fig. 3.41). Structural Styles in the Gentle Slope The gentle slope represents a considerable portion of the rift, accounting for about half the basin’s total area. Exploration practice has proved that gentle slope is often the orienting regions for hydrocarbon migration in basins and vital locations for oil and gas accumulation. The structural and depositional evolution of the gentle slope in the Bongor Basin reveals complexity and diversity quite different from the other two principal tectonic units. Even within a single part of the gentle slope, the structural style varies greatly if the rifts are distinct. These differences are closely related to the extension and alteration of the basin basement. According to the evolution of sedimentation and structure, gentle slope have three types of genesis: sedimentary slope, structural-sedimentary slope, and structural slope. The gentle slope zone of the Bongor Basin belongs to the structural-sedimentary type, which can be further divided into three subtypes and is developed separately in four individual rifts.

3.5 Graben-Horst Integrated Slope The gentle slope is composed of alternate large graben or horst structures related to faults with opposite or the same dip. Horst is the structural basis of the ancient high on the gentle slope; graben is the structural foundation of the sedimentary trough

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on the gentle slope (Abubakar 2014). The ancient uplift became proven for the deep P Formation, laying a good structural foundation for hydrocarbon accumulation. Exploration has shown that most of the oil fields discovered, particularly high-yield fields, are located on this type of slope. This graben-horst combination is typical, forming the most promising structures for oil and gas discovery. An example is the Great Baobab Oil Field. Superimposed Combination of Horst Structure in Basement and Inversion Anticline in Cover In this style, the basement has a horst structure, on which anticline or faulted anticline structures are superimposed. This is because the faults that controlled the generation of the horst structures ceased to be active in the later period, while other faults continued to be active. During later compressional inversion, the upper cover was compressed and inversed along the fault, forming reverse folds and thus superimposing the deep basement horst structure. The fault anticline structure superimposed on basement horst have two distinct structural styles. One is formed by compression and inversion along large-scale master faults that cut to the basement. Compensation faults with opposite dip to the main fault form on the anticline combine to form a “Y"-shaped structure style, such as the Ronier S structure (Fig. 3.42a). The other structural style is where anticlines are formed by compression and inversion along large-scale master faults that cut to the basement. Multi-level normal faults segment the anticlines The Mimosa structure is an example of this style (Fig. 3.42b). The common feature of the two structural styles is the presence of old faults that cut to the basement. Continuous activity in these faults plays a restrictive role when traps are forming, and the faults also connect young and old strata, acting as channels for oil and gas migration. Because the basement fault horst structures are distributed zonally, anticline structures in the upper parts of the steep fault horsts are distributed along this structural belt. The Mimosa, Ronier South, and Baobab structures are examples of this type. Inherited Superimposed Graben-Horst Structure in the Basement and GrabenHorst Structure in the Cover This is another significant petroliferous structural style in the basin. In this style, the dips of normal faults are opposed, and the hanging wall of the faults gradually descends step by step on both sides, forming a complex horst structure. The upper superimposed covers are impacted by early faults and form complicated horst structures, with large-scale anticline structural backgrounds in the plane. Also, due to the zonal distribution of this style, anticline structures, and fault nose structure zones are formed. The Raphia and Phoenix Oil Fields are examples of this type of structure (Fig. 3.43). Structural Style of Compression and Inversion Anticlines Associated With Basement Fractures This structural style is common in the paleo-fault hanging wall of the inherited P Formation, a small anticline or fault nose structure related to paleo-faults formed by

3.5 Graben-Horst Integrated Slope

111

Fig. 3.42 Combination profile of graben-horst structure in the basement and inversion anticline in the sedimentary sequence

Fig. 3.43 Inherited superimposed graben-horst structure in the basement and sedimentary sequence

early compression and inversion (Fig. 3.44). The scale of structural traps is small. However, because the structure is in oil-rich strata, these small traps are rich in oil and gas and are generally well filled, so they are the principal target for deep oil and gas exploration (Belaidi et al. 2016).

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3 Tectonic Characteristics of Basins Cenozoic R K

M

P

Basement

Fig. 3.44 Structural style of compressional and inverted anticlines associated with basement faults in the southern of the Moul Depression

Antithetic Terraces Slope Antithetic terraces slopes are formed by faults with the same dip as the boundary faults and the opposite dip to the strata. The Savonnier located in the Cola Depression in the western part of the basin (Fig. 3.8c) is an example. Although in profile, the style is similar to antithetic fault terrace, with the same dip, antithetic fault terraces were formed in the later period (the end of the Cretaceous). The primary function of the faults is to segregate the strata of the slope and complicate the slope structure. This type of slope has no small secondary depressions, and the anticlines and fault noses are absent, while the fault block structure is more developed. There have been no oil and gas discoveries on this type of slope. Consequent Terraces Slope The fault dip in this slope is opposite to that of the boundary faults and the same as the formation dip. The slopes can be divided into two types according to fault type. The first is the Moul-type slope, found in the Moul rift east of the basin (Fig. 3.8a). The characteristic of this type is that early-formed faults on the slope continue to move to control strata deposition after the basement extension and even have a degree of influence on the deposition of the middle and shallow strata. These early faults are essential to controlling deposition and connecting oil sources. Hydrocarbons have been found in this type of slope. The second is the Soudio slope-type, found in the Annona Depression in the western part of the basin (Fig. 3.8d). This type is similar to the Moul-type slope in profile, but the formation mechanism is completely different. The series of faults on the slope formed in the later period. The primary function of the faults is to segment the strata of the slope and complicate the structure. Anticlines and fault noses are not developed, but a fault block structure is formed. No oil and gas discoveries have been made in this type of slope.

3.5 Graben-Horst Integrated Slope

113

3.5.1 Inversion Structural Style Glennie and Boegner (1981) first used the term “inversion” in descriptions of sedimentary basins, proposing the concept of “inverted structures”. Harding (1985) believed that “tectonic inversion means that the changes of structural relief in polarity”. When referring to a specific structure, this refers to the transformation from the original structural low to a structural high (Schandelmeier 1990). It can be called a “basin-scale inverted structure”if the scale is large. The terms ‘inverted structure’, ‘tectonic inversion’, and ‘basin inversion’ refer to different degrees of inversion on various scales. Hayward and Graham (1989) divided inverted structures into local inversions and regional inversions according to the deformation scale. Local inversion refers to the inversion of a single structure caused by an antithetic slip of an early fault. Regional inversion refers to the inversion of an entire basin by the antithetic action of an entire connected fault system. Local Inverted Structure Local tectonic inversion is common in the Bongor Basin, mainly manifested as fault-related fold-type negative inverted structures. Tectonic inversion results from the high-angle normal faults formed during the early syn-rift period, with large fault displacements and various levels. Uplift and denudation at the end of the Late Cretaceous exceeded 1000 m. The preserved strata in the basin are Lower Cretaceous, and a large number of shallow thrust, fault-bend, and fault-propagation folds may have also been eroded. In the remaining strata, fault thrusting is not obvious. There are no fault-related inverted structures of ‘lower normal fault and upper reverse fault’ or ‘lower and upper reverse fault’ types, and the thrusting fault throw cannot be easily restored. However, in the preserved strata, faults of the ‘lower normal fault and upper reverse fault’ type have been found in the hanging walls of some faults (Fig. 3.44), and the thrust throw of these is known to have reached thousands of meters. According to folds’ causes and morphological characteristics, local inversion patterns are divided into three categories. Isopach Fold-Type Inverted Structure Isopach fold-type inverted structures develop most frequently in the centers of depressions and subdepressions. These are fold-inverted structures formed by the shortening of sedimentary strata under horizontal compression (Fig. 3.45). This type of fold is also called a parallel fold. Every rock stratum is bent in parallel, and the formation thickness of each rock stratum is essentially the same in every part of the fold when it is measured perpendicular to its bedding plane. In section, ‘two faults and one high’ characteristics are apparent. The upper and lower parts of the folds are convex, and the structure is generally wide and gentle, with the structural highs of the upper and lower structures vertically plumb. This type of fold is sometimes the result of the inversion of grabens between synthetic faults (Fig. 3.45). They may be

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3 Tectonic Characteristics of Basins

anticlines formed by direct stratigraphic inversion, often developing on the hanging wall syn-sedimentary faults (Fig. 3.46). Valley in Front and Peak in Post Type Inverted Structures In this type of structure, an asymmetrical anticline or nose structure is on the hanging wall of a large fault with a syncline near the anticline. The axes of the anticline and syncline are vertically plumb and not parallel to the main fault line. The amplitude of the anticline is ‘large in lower and small in upper’, and the area is ‘small in lower and large in upper’. The Prosopis structure (Fig. 3.46) is an example. These anticlines are often distributed in a moniliform shape on the hanging walls of faults. Suppose the hanging wall develops rollover anticlines during the synsedimentary period. In that case, the amplitude of the anticline further increases after inversion, with the anticline axis almost parallel to the syndepositional fault plane. The inverted anticline structure on the north side of the Cola Depression (Fig. 3.39a) is an example. Peak in Front and Valley in Post Type Inverted Structure This inverted structure has precisely the reverse shape from the valley in front and peak the in post-type inverted structure. The post valley is formed by increasing compression deformation amplitude caused by downward flexure of the pre-existing normal drag syncline on the hanging wall of the early fault. At the same time, a new anticline forms in front of the syncline with increasing amplitude to form the peak. The amplitude of the anticline is “ small in lower and large in upper “, and the axes of both anticline and syncline are vertically plumb (Fig. 3.47). These anticlines are often distributed in moniliform shapes on the hanging walls of faults.

Fig. 3.45 Isopach fold-type inverted structure formed by inversion

3.5 Graben-Horst Integrated Slope

115

Fig. 3.46 Front valley and post peak-type inverted structure

Fig. 3.47 Front peak and post valley-type inverted structure

Tectonic Zone-Scale Inverted Structure Tectonic zone-scale inverted structures are a contraction structural deformation belt superimposed on an extension structure. This structure type is found throughout the basin in the plane. It is particularly prevalent in zonal distributions in the western and eastern parts of the basin. Four types of tectonic zone-scale inverted structure can be distinguished: inverted structure belt with a steep slope background, inverted structure belt with a depression background, inverted structure belt with a gentle slope background, and inverted structure belt with a basement high background (Fig. 3.48).

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3 Tectonic Characteristics of Basins

Fig. 3.48 Plane distribution of different types of inverted structure belts in the Bongor Basin

Inverted Structure Belt with a Steep Slope Background The steep slope zones of the depressions and subdepressions in the basin have generally been inverted, forming a series of inversion anticlines that are distributed zonally. These are predominantly peak in front and valley in post type and valley in front and peak in post type folds. Examples are the Mango oil-bearing structural belt in the steep slope zone of the Mango Depression and the Prosopis inversion anticline structural belt on the east side of the Ronier subdepression. (Fig. 3.46). Inverted Structure Belt with a Depression Background The centers of the depressions and subdepression in the basin were also inverted, forming large isopach folds with zonal distributions. The central inversion anticline structural belt of the Ronier subdepression (Fig. 3.49) and the inversion anticline structural belt in the center of the Pera subdepression of the Mango Depression (Fig. 3.38) are examples.

Fig. 3.49 Inverted faulted anticline structural belt in the center of the Ronier subdepression

3.5 Graben-Horst Integrated Slope

117 Delo W- 1 Neogene

K

M

P Basement

Fig. 3.50 Regional seismic profile of the Delo West Depression showing the inverted anticline

Inverted Structure Belt with a Gentle Slope Background The slopes of various depressions in the basin have also undergone inversion, tilting, truncation, etc., forming a series of inversion anticline structures with complicated faults distributed zonally. Examples are the southern slope of the Moul Depression (Fig. 3.44), the Soudio anticline structural belt in the northern part of the Annona Depression (Figs. 3.27 and 3.38), and the inversion anticline structural zone of the slope in the Delo West Depression (Fig. 3.50). Inverted Structure Belt with a Basement High Background Inverted structures with a basement high backgrounds are mainly found on the northern slope of the Mango Depression. The basement high is sandwiched by a series of Early Cretaceous secondary rifts in these structures. The highs were draped and deposited by the Lower Cretaceous. During later compression, the faults on one or both sides of the high were inverted, forming a series of peaks in front and valleys in post type or valleys in front and peak in post type anticlines. The anticlines combine with the basement high to form large structural zones. The oil supply from sources on one or both sides makes this structural type the richest in oil. Examples include the Big Bongor structural zone and the Kubla structural zone (Fig. 3.51). Basin Inverted Structure Basin inversion is the process of contraction and deformation under compression of basins previously controlled by extensional structures. The normal fault-controlled basins or half-grabens, grabens, and other extensional structures have undergone compressional uplift. The polarity of the structural relief changes, and the structure shifts from a relatively structural low to a relatively high. MacGregor (1995) divided

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3 Tectonic Characteristics of Basins Kubla -1

Precambrian basement high

Fig. 3.51 Inverted anticline structural zone on the Kubla basement high

rift basins into simple rifts, local inversion rifts, and regional inversion rifts according to the scope and influence of inversion. There is no apparent inversion effect in simple rifts. In local inversion rifts, the local structural belt is uplifted, the original extensional landform is changed or destroyed, and a series of new open anticline structures form in the lower position of the original structure. Regional inversion rifts are products of intensive compression and uplift, with subsequent denudation of most of the original basin in the later period. The center of the original basin usually experiences a large uplift with the disappearance of the extensional landform at the center of the basin. Based on three major factors, research has confirmed that the Bongor Basin can be defined as a strongly inverted basin. The first factor is that the basin has experienced uplift and denudation of 1000–1750 m. The second factor is that the basin has undergone strong compression, The deep part of the subbasin has been compressed and uplifted and then inverted, forming a wide and gentle large anticline structure (Fig. 3.38). Inversion has also occurred in the deep subdepressions of some depressions, such as the Ronier subdepression (Fig. 3.49). The third factor is that inversion anticline structural belts have developed in the basin. The boundary faults of every rift in the basin are generally steep, planar faults. There are no fault-bend folds or other phenomena in the remaining strata, but the hanging walls of steep faults generally feature closed compressive folds. The gentle slopes of the basin have generally undergone tilting and truncation, indicating that the gentle slopes have experienced a greater range of uplift (Fig. 3.27).

3.5 Graben-Horst Integrated Slope

119

Fig. 3.52 Vitex flower structure

3.5.2 Strike-Slip Structural Style Alternating extensional and compressive stress fields characterize the Bongor Basin. The impact of strike-slip is much smaller than that of extension. However, controlled by the dextral strike-slip of CASZ during the early Cretaceous, strike-slip structures still occur locally in the basin, typically represented by negative ‘flower’ structures and usually associated with NE-trending faults. In section, the structures appear steeply dipping strike-slip faults that penetrate directly into the basement. Associated normal faults are scattered upwards in semi-flower- and flower shapes. These structures are most common in the Tamarind and Vitex areas in the western part of the basin (Fig. 3.52).

3.5.3 Mud Diapir Structural Style It is inferred from seismic data that mudstone diapirs existed in the eastern area of the Pera subdepression in the Mango Depression. Their development horizon is the K-R Formations. The mudstone diapirs appear as upward highs on seismic profiles, locally piercing the overlying strata, and are represented by blank or chaotic reflections. Anticline traps form between the diapiric bodies, and drape fault nose structures form around them (Fig. 3.53). The oil-bearing properties of these structures have yet to be confirmed by drilling.

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Fig. 3.53 Mud diapir structure of the Pera subdepression

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Harding TP. Seismic characteristics and identification of negative flower structures, positive flower structures, and positive structural inversion. AAPG bulletin. 1985;69(4):582–600. Hayward AB, and Graham RH. Some geometrical characteristics of inversion. Geol Soc, London, Spec Publ. 1989;44(1):17–39. Hu JY, Tong XG, Xu SB. Regional distribution of buried hill oil reservoirs in Bohai Bay Basin. Pet Explor Dev. 1981;05:1–9. Hurford AJ, Green PF. A user’s guide to fission track dating calibration. Earth Planet Sci Lett 1982;59:343–354. Jorgensen GJ, Bosworth W. Gravity modeling in the Central African Rift System, Sudan: Rift geometries and tectonic significance. J Afr Earth Sci Middle East. 1989;8(2–4):283–306. Khain VY. The role of rifting in the evolution of the earth’s crust. Tectonophysics. 1992;215(1– 2):1–7. Klemme HD. Petroleum basins—classifications and characteristics. J Pet Geol. 1980;3(2):187–207. Laslett GM, Kendall WS, Gleadow AJW and Duddy IR. Bias in measurement of fission track length distributions. Nucl Tracks 1982;6:79-85. Ledru P et al. Markers of the last stages of the Palaeoproterozoic collision: evidence for a 2 Ga continent involving circum-South Atlantic provinces. Precambr Res 1994;69(1–4):169–191. Li DS. Geological and structural characteristics of Bohai Bay petroliferous basin. Acta Petrolei Sinica. 1980;01:6–20. Lidmar-Bergström K. Uplift histories revealed by landforms of the Scandinavian domes. Geol Soc Lond Spec Publ. 1999;162(1):85–91. Liu B, Pan XH, Wan LK, et al. Structural evolution and main controlling factors of the Paleogene hydrocarbon accumulation in Termit Basin, eastern Niger. Acta Petrolei Sinica. 2012;03:394–403. Liu HF, Liang HS, Li XQ, et al. The coupling mechanisms of mesozoic—cenozoic rift basins and extensional mountain system in eastern china. Earth Sci Front. 2000;04:477–86. Liu HF, Liu XJ, Liu LQ. Integrated analysis of geodynamic scenarios, basin sequences and petroleum system. Geoscience. 2003;01:80–6. Lowell JD. Structural styles in petroleum exploration. Pennwell Corporation; 1985. Lu KZ, Qi JF, Dai JS. Tectonic model of Cenozoic petroliferous Basin in Bohai Bay. Beijing: Geological Publishing House; 1997. Macgregor DS. Hydrocarbon habitat and classification of inverted rift basins. Geol Soc Lond Spec Publ. 1995;88(1):83–93. Makris J, Rihm R. Shear-controlled evolution of the Red Sea: pull apart model. Tectonophysics. 1991;198(2–4):441–66. Mann P, Gahagan L, Gordon MB. Tectonic setting of the world’s giant oil and gas fields. AAPG Mem. 2003;78:15–105. Maria LB, Marco B, Giacomo C, et al. A refinement of the chronology of rift-related faulting in the Broadly Rifted Zone, southern Ethiopia, through apatite fission- track analysis. Tectonophysics. 2016;671:42–55. Morgan P, Baker BH. Introduction—processes of continental rifting. Tectonophysics. 1983;94(1):1– 10. Morley CK, Nelson RA, Patton TL, et al. Transfer zones in the East African rift system and their relevance to hydrocarbon exploration in rifts. AAPG Bull. 1990;74(8):1234–53. Oden MI, Umagu CI, Udinmwen E. The use of jointing to infer deformation episodes and relative ages of minor Cretaceous intrusives in the western part of Ikom—Mamfe basin, southeastern Nigeria. J Afr Earth Sc. 2016;121:316–29. Petters SW, Ekweozor CM. Petroleum geology of Benue trough and Southeastern Chad Basin, Nigeria: geologic notes. AAPG Bull. 1982;66(8):1141–9. Qiao HS, Ji YL, Jiang ZX. Continental rift and oil and gas in eastern China. Beijing: Petroleum Industry Press; 1999. Schandelmeier H, Pudlo D. The Central African Fault Zone (CAFZ) in Sudan-a possible continental transform fault. Berl Geowiss Abh A. 1990;120(1):31–44.

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Chapter 4

Characteristics of Lower Cretaceous Strata, Reservoirs, and Seals

The Bongor Basin is a Cretaceous-Cenozoic continental rift basin formed on Precambrian crystalline basement rock (Kaska 1989). Sedimentation and filling of the rifts in the Early Cretaceous basin were controlled and influenced by multiple diverse factors, including long-term weathering, planation and denudation, high-angle boundary faults, and a strike-slip tectonic setting, large basement faults, and the activity of newly formed faults (Deng et al. 2001). A complete coarse–fine-coarse sedimentary cycle was deposited, with typical Lower Cretaceous lacustrine stratigraphic characteristics, similar to other rift basins in CARS (Lambiase 1990). Regional structural inversion during the Late Late Cretaceous-Paleocene fundamentally reformed the basin, resulting in severe denudation and the almost complete erosion of the Upper Cretaceous strata (Fairhead 1992). The Lower Cretaceous is, however, generally preserved in the basin, forming a regional unconformity with overlying Cenozoic loose clastic rock strata. This tectonic-sedimentary structure is significantly different from other rift basins in CARS, giving the basin a unique source-reservoir-cap combination (Fairhead 1988b).

4.1 Stratigraphic Characteristics The maximum thickness of the Lower Cretaceous in the Bongor Basin is 10 km. The presence or absence of the Upper Cretaceous in the basin has always been a contentious issue. The rift basins surrounding the Bongor Basin, such as the DobaDoseo Basin and the Benue Trough, all have thick Upper Cretaceous strata (Petters and Ekweozor 1982). In the Muglad Basin in Sudan, the Melut Basin in South Sudan, and other basins in the region, thick Upper Cretaceous strata directly cover the Lower Cretaceous, with parallel unconformities between them and angular unconformities on the rift edges (Fairhead 1988a).

© Petroleum Industry Press 2023 L. Dou et al., Petroleum Geology and Exploration of the Bongor Basin, https://doi.org/10.1007/978-981-19-2673-0_4

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The Cretaceous and the Lower Cretaceous have undergone relatively uniform deformation, with faults often terminating at the top of the Cretaceous. The inference from the general characteristics of the region is, therefore, that the Bongor Basin must also have had Upper Cretaceous deposits during its geological history (Lu et al. 2009). The seismic profile of the basin, particularly the three-dimensional seismic profile, shows (in addition to the regional unconformity at the top of the basement) two large regional unconformities in the shallow sedimentary strata in the basin referred to as the lower unconformity and the upper unconformity. The stratum beneath the lower unconformity has been confirmed as Lower Cretaceous (Klemme 1980). The stratum between the upper and lower unconformities is in angular unconformity contact with the underlying stratum. The upper and lower unconformities merge into a single large regional unconformity in the northern part of the Northern Slope of the basin (Fig. 4.1). This set of strata is well preserved within the depression, with a maximum thickness of 500 m (Fig. 4.2), and is considered either Late Cretaceous or Paleogene. Precisely determining the age of this set of strata is crucial to understanding the tectonic evolution, depositional history, thermal history, and accumulation history of the basin. According to shallow logging and seismic calibration in wells Semegin-1 and Naramay-1 (and others), the formation between the two regional unconformities was never deeply buried and did not undergo the strong inversion deformation experienced by the Lower Cretaceous. The stratum above the upper unconformity is characterized by high gamma-ray, low sonic interval transit times, low resistance, and low formation velocity (Li 2017). The gamma-ray is between 15 and 90—generally above 50—and shows a dentate-shaped curve with abrupt changes. The sonic interval transit time is between 140 and 170 µs/ft, resistance is between 2.0 and 2.05 Ω m, and the formation velocity is between 1600 and 2200 m/s, reflecting the looseness of the formation and its possible Neogene origin.

Fig. 4.1 Seismic profile showing two unconformities in the sedimentary cover

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127

Fig. 4.2 Thickness map of the Cenozoic residual strata

The stratum between the two unconformities is gentle overall, without strong deformation and no faulting. It is characterized by low gamma-ray, a slightly higher sonic interval transit time, low resistance, and slightly higher formation velocity (Scherbaum et al. 1982). The gamma-ray jumps between 15 and 60 (generally less than 50), the sonic interval transit time is between 120 and 150 µs/ft, resistance is between 2.05 and 2.15 Ω m, and the formation velocity is between 2200 and 3000 m/s. This set of formations is thin, consisting primarily of weakly consolidated loose sand intercalated with a soft clay layer. The sand is generally coarse and sometimes gravelly. The mineral composition is quartz, occasional feldspar, kaolinite, and biotite, but no calcium. Drilling speeds reach 30–50 m/h occasionally up to 100–120 m/h. This suggests that the stratum between the two unconformities in the shallow layer is sedimentation from the middle and late Paleogene. The stratum above the upper unconformity is Neogene. The two sets of strata are very thin: less than 500 m in total. Regional distribution is stable, and deformation is very weak, indicating that the structure is relatively stable. The Miocene event further uplifted the northern part of the basin, exposing the underlying Paleogene and even the Lower Cretaceous. We will focus on the stratigraphic characteristics of the Lower Cretaceous.

4.1.1 Lithostratigraphy P Formation The northern part of the basin is relatively shallow, with a number of wells drilled through, while other areas have great burial depths but no wells drilled through. On the basis of seismic interpretation, the maximum thickness of the P Formation in the Mango Depression in the central-southern part of the basin is 3500 m, while drilling reveals that it is relatively thin in the Northern Slope (5000

Meso-fracture

5000–1000

Fine fracture

1000–100

Microfracture

100–1

Microscopic fracture

10–0.1

Submicroscopic fracture

≤0.1

Fig. 5.24 Feldspar crystal structural-dissolution fractures in granitic breccia: well Baobab C-2, 561.3 m, casting thin section, plane-polarized light

is 10.67–84.34 μm, and the fracture area ratio is 0.13–1.64%, with an average of 0.5%. The plane porosity is 0.18–8.18%, averaging 1.76%. The average pore diameter is 37.84–628.2 μm. Pore-throat ratios are 0.93–7.28, averaging 2.54. Throat widths are 6.92–47.51 μm, averaging 20.22 μm. The plane porosity of the samples is greater than the fracture area frequency, with only a few exceptions. The lithology is mainly granite and syenite, as reflected in the predominance of fractures over pores. In addition to forming a particular type of throat that can effectively link pore spaces, microfractures are also crucial reservoir spaces. Pore-Type There are no isolated fractures in the reservoir space in this type, only combinations of broken intergranular pores/dissolution pores, dissolution pores/cleavage fractures, etc. (Fig. 5.33). The plane porosity is 0.38–15.76%, averaging 2.83%.

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Fig. 5.25 Structural dissolution fractures in quartz diorite: well Baobab C-5, 1447 m, casting thin section, plane-polarized light

Fig. 5.26 Dissolved fractures in migmatitic granite: well Baobab C-2, 1107.15 m, casting thin section, plane-polarized light

The average pore diameter is 44.29–956.26 μm. Pore-throat ratios are 0.22–5.34, averaging 1.9. Throat widths are 3.68–43.02 μm, averaging 18.05 μm. Broken intergranular pores and dissolution pores primarily develop in dynamometamorphic rocks that are uniformly broken and highly fragmented. Dissolution pores and cleavage

5.1 Reservoir Properties of Basement Rock Reservoirs

195

Fig. 5.27 Filler dissolution of fractures in monzonitic granite: well Mimosa-10, 1070.01 m, casting thin section, plane-polarized light

Fig. 5.28 Cleavage fractures in diorite hornblende: well Cassia-2, 1389.5 m, casting thin section, plane-polarized light

fractures are common in feldspar minerals in felsic rocks. Among mafic rocks with high dark mineral content, they often occur in hornblende and biotite. Fracture Type This type of reservoir space is composed of structural and dissolution fractures (Fig. 5.34). The observed number of fractures is usually 1–4, the average fracture width is 2.5–42.68 μm, and the fracture area ratio is 0.23–2.05%, averaging 1%. Fracture-type pore structures occur in rocks with high felsic content, such as

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Fig. 5.29 Cleavage fractures and dissolved pores in cataclastic alkali-feldspar migmatitic granite feldspar: well Baobab C-2, 1301.31 m, casting thin section, plane-polarized light

Fig. 5.30 Dissolution of cataclastic migmatitic granite feldspar along cleavage fractures: well Raphia S-11, 1411.7 m, casting thin section, plane-polarized light

migmatitic granite, syenite, granite, crush rock, and tectonic breccia, reflecting their brittle properties and ease of fracturing. No Pore-No Fracture Type For this type, image analysis of casting thin sections shows dense rock structures with no pores or fractures. This is because the original structure consisted of metamorphic or magmatic rocks that had not been affected by tectonic stress or formation fluids once formed (Fig. 5.35). Statistical analysis of rock subtypes indicates that the no

5.1 Reservoir Properties of Basement Rock Reservoirs

197

Fig. 5.31 Cleavage fractures in migmatitic granite: well Raphia S-8A, 1574.5 m, SEM, 2265×

Fig. 5.32 Pore-fracture combination in migmatitic granite, well Baobab C-2, 534.5 m

pore-no fracture type is most prominent in diadysite, gneiss, granulite, and magmatic rocks (Lirong et al. 2014). The dark mineral content of these metamorphic rocks is relatively high, and they do not fracture easily. Magmatic rocks are usually formed by the anatexis granitization of metamorphic rocks. The rock itself is dense, formed comparatively late, and is relatively unaffected by later reformation.

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Fig. 5.33 Pore-type monzonitic granite, well Raphia SW-2, 993.24 m

Fig. 5.34 Fracture-type cataclastic migmatitic granite, well Raphia S-8A, 1575.5 m

Fig. 5.35 No pore-no fracture type

5.1 Reservoir Properties of Basement Rock Reservoirs

199

Particles of this type still occur in dynamometamorphic rocks, but only in very small quantities, suggesting that they are fragments or pieces of unreformed rubble. Characteristics of Capillary Pressure Curve We used the mercury intrusion method to measure capillary pressure curves, conduct qualitative and semi-quantitative research on the pore structures of reservoirs, and obtain parameters for pore throat sizes, sorting, connectivity, and seepage capacity. Reservoirs with different lithologies have varying types of reservoir spaces and diverse reservoir space combinations that alter the characteristics of the capillary pressure curves. Based on analysis of mercury saturation maxima, displacement pressures, maximum pore throat radii, and other parameters, four types of measured capillary pressure curves can be distinguished as Types A, B, C and D. Further, according to mercury withdrawal efficiency, pore throat distribution, sorting coefficients, etc., the four types are subdivided into seven sub-categories: A1 , A2 , B1 , B2 , C1 , C2 , and D. Each sub-category reflects specific differences in pore structures. Type A Capillary Pressure Curve Type A is characterized by high maximum mercury intrusion saturation and medium and low displacement pressure and representing optimal reservoir properties. The maximum pore throat radius is 0.359–51.542 μm, the displacement pressure is 0.014– 2.051 MPa, and the average pore throat radius is 0.045–7.406 μm, the maximum mercury saturation is 42.08–83.88%, and the mercury withdrawal efficiency is 7.25– 58.27%. This type of curve indicates crush rock, tectonic breccia, and small quantities of granite. According to mercury withdrawal efficiency and pore throat distribution characteristics etc., the type can be further divided into two subcategories: A1 and A2 (Fig. 5.36). Subcategory A1 : The mercury withdrawal efficiency is high, usually greater than 35%. The mercury saturation contribution is greatest in pore spaces with larger pore throat radii. The sorting coefficient is relatively large, and pore throats are uneven, which may reflect a mixture of pore throat structures, including microfractures, broken intergranular pores, and dissolved pores. Subcategory A2 : The mercury withdrawal efficiency is low, usually less than 35%. Pores with smaller throat radii contribute most to mercury saturation, and the sorting coefficient is relatively small, which may reflect intense crushing of rock particles and small, uniform, broken intergranular pores. Type B Capillary Pressure Curve Type B is characterized by extremely low displacement pressures and large mean pore throat radii. The pore throat distribution shows an isolated bimodal shape, suggesting that fractures dominate the pore structure of the reservoir. The maximum pore throat radius is 8.429–224.238 μm, the displacement pressure is 0.003–0.087 MPa, the average pore throat radius ranges from 1.534–75.252 μm, the maximum mercury saturation is 17.68–52.53%, and the mercury withdrawal efficiency is 10.66–61.68%. Based on displacement pressure, pore throat distribution, and other characteristics, the type can be further divided into two subcategories: B1 and B2 (Fig. 5.37).

0.100 0.010 0.001 100 90

80 70 60 50 40 30 20 10 0 Mercury saturation Capillary pressure curve of mercury intrusion method

Subcategory A1 capillary pressure curve well Baobab C 2,560.50m, granitic breccia

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0

Mercury saturation Capillary pressure curve of mercury intrusion method b

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10.00

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Frequency of mercury saturation

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a

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1.000

0.00 0.01 0.02 0.03 0.04 0.05 0.10 0.15 0.25 0.40 0.65 1.00 1.50 2.50 4.00 6.30 10.00 16.00 25.00 40.00 63.00 100.00

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5 Characteristics of Basement Rock Reservoirs

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200

Pore throat radius mm Histogram of mercury saturation and accumulation curve of permeability contribution

Subcategory A2 capillary pressure curve(well Mimosa E-2,1759.45m,cataclastic alkali migmatitic granite)

Fig. 5.36 Type-A capillary pressure curves

Subcategory B1 : The skewness is relatively small, the pore throat radii are relatively large, and the displacement pressure is relatively low, which indicates reservoir spaces with only either microfractures or macrofractures. Subcategory B2 : The skewness is relatively large, the pore throat radii are relatively small, and the displacement pressure is relatively high, suggesting reservoir spaces with a mixture of microfractures and microscopic fractures, with few intercrystalline or dissolved pores. Type-C Capillary Pressure Curve Type C is the most common, characterized by medium–high displacement pressure and low maximum mercury saturation. The reservoir space is less developed than Type A, with maximum mercury saturation mostly between 20 and 40%, and weak connectivity. The maximum pore throat radius of this type is 0.147–4.803 μm, the displacement pressure is 0.153–4.992 MPa, and the average range of pore throat radii is 0.041–1.148 μm, the maximum mercury saturation is 8.25–56.56%, and the mercury withdrawal efficiency is 13.89–81.94%. Based on these characteristics, the type can be further divided into two sub-categories: C1 and C2 (Fig. 5.38). Subcategory C1 : The mercury withdrawal efficiency is high, usually greater than 50%. Pore spaces with larger pore throat radii contribute most to mercury saturation,

0.010 0.001 100 90 80 70

60 50 40 30 20 10

0

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201

0.00 0.01 0.02 0.03 0.04 0.05 0.10 0.15 0.25 0.40 0.65 1.00 1.50 2.50 4.00 6.30 10.00 16.00 25.00 40.00 63.00 100.00

Capillary pressure MPa

5.1 Reservoir Properties of Basement Rock Reservoirs

Mercury saturation Capillary pressure curve of mercury intrusion method

Pore throat radius mm Histogram of mercury saturation and accumulation curve of permeability contribution

1.000 0.100 0.010 0.001 100 90 80 70

60 50 40 30 20 10

0

Frequency of mercury saturation

10.000

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Mercury saturation Capillary pressure curve of mercury intrusion method

b

Subcategory B2 capillary pressure curve

0.00 0.01 0.02 0.03 0.04 0.05 0.10 0.15 0.25 0.40 0.65 1.00 1.50 2.50 4.00 6.30 10.00 16.00 25.00 40.00 63.00 100.00

Capillary pressure MPa

a Subcategory B2 capillary pressure curve well Baohab C-2, 1032.4m,

Pore throat radius mm Histogram of mercury saturation and accumulation curve of permeability contribution

well Baohab C-2, 1107.15m, migmatitic granite

Fig. 5.37 Type-B capillary pressure curves

which suggests that the pore throats are microscopic fractures or dissolved pores in dark minerals. Subcategory C2 : The mercury withdrawal efficiency is low, usually less than 50%. Pore spaces with smaller pore throat radii contribute most to mercury saturation, which suggests that the pore throats are intercrystalline pores, with few dissolution pores or cleavage fractures. Type-D Capillary Pressure Curve Type D is characterized by extremely high displacement pressure and extremely low maximum mercury saturation (Fig. 5.39). This type’s maximum pore throat radius is 0.037–0.091 μm, the displacement pressure is 8.067–20.023 MPa, and the average pore throat radius ranges from 0.025 to 0.041 μm, the maximum mercury saturation is 2.45–46.21%, and the mercury withdrawal efficiency is 20.18–97.79%. This curve reflects a tight rock structure and extremely underdeveloped reservoir space. There are few pores with very small radii suggesting isolated intercrystalline pores or cleavage fractures.

1 0.1 0.01

80

70

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50 40

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0 0.01 0.02 0.03 0.04 0.05 0.10 0.15 0.25 0.40 0.65 1.00 1.50 2.50 4.00 6.30 10.00 16.00 25.00 40.00 63.00 100.00

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Capillary pressure curve of mercury intrusion method

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1322.5m, Migmatitic gneiss

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110 100 90 80 70 60 50 40 30 20 10 0 0 0.01 0.02 0.03 0.04 0.05 0.10 0.15 0.25 0.40 0.65 1.00 1.50 2.50 4.00 6.30 10.00 16.00 25.00 40.00 63.00 100.00

Frequency of mercury saturation

Capillary pressure MPa

a Subcategory C1 capillary pressure curve well Cassia 2

10

mm

Histogram of mercury saturation and accumulation curve of permeability contribution

Mercury saturation Pore throat radius Capillary pressure curve of mercury intrusion method b

mm

Histogram of mercury saturation and accumulation curve of permeability contribution

Subcategory C2 capillary pressure curve ( well Mimosa-10, 1069.71m, migmatitic granite )

Fig. 5.38 Type-C capillary pressure curves

Fig. 5.39 Type-D capillary pressure curves (well Baobab C-2, 1432 m, gneiss)

Accumulation of permeability ontribution

10

110 100 90 80 70 60 50 40 30 20 10 0

Accumulation of permeability contribution

5 Characteristics of Basement Rock Reservoirs

Frequency of mercury saturation

Capillary pressure MPa

202

5.1 Reservoir Properties of Basement Rock Reservoirs

203

5.1.3 Classification of Basement Rock Reservoirs Based on systematic core observation, lithology analysis, characteristics of capillary pressure curves, conventional logging, and FMI data research, the buried hill reservoirs are divided into two types: pore type and fracture type (Hu 1986) (Fig. 5.40). Pore-Type Reservoirs This reservoir type is characterized by broken rocks, strong structural heterogeneity (Fig. 5.40a), and obvious weathering. Reservoirs of this type are generally found on the tops of buried hills. The reservoir spaces are primarily broken intergranular pores, with mud filling in fractures. Intercrystalline pores formed by dissolution also contribute significantly to reservoir space. In this type of reservoir, diameter expansion generally occurs during drilling, and drilling fluid leakage is a severe problem. Fracture-Type Reservoirs The rock structure of this type of reservoir is complete, and natural fractures are developed. The fractures occur in open networks or high-angle swarms (Fig. 5.40b). They are sometimes filled with calcite, chlorite, and iron material. Dissolution of minerals (mainly hornblende and feldspar) occurs along the peripheries of fractures. Observation of cores and thin sections shows that the pores coexist with the fractures as strings of beads. The reservoir spaces include fracture and dissolution cavities. Some diameter expansion and drilling fluid leakage occur during drilling.

Fig. 5.40 Cores and FMI images of two types of granite buried hill reservoirs in well Baobab C-2

204

5 Characteristics of Basement Rock Reservoirs

5.1.4 General Evaluation of the Reservoir Quality of Basement Rock Combining all of the above findings, the basement rock can be divided into four major sequences (Table 5.4). In sequence I, the lithology is formed by dynamic metamorphism or physical weathering, with well-developed reservoir spaces, making it the most favorable type of reservoir rock. Sequence II is dominated by felsic minerals, with lower dark mineral content. This type of rock fractures easily and has relatively well-developed reservoirs. It is broadly favorable. The reservoir properties of sequence III rocks are less advantageous than those of sequence II, but viable reservoir spaces can still form. Sequence IV rocks have the highest dark mineral content, and reservoir spaces are not developed. This sequence tends to form barriers in basement rock, controlling migration and accumulation in reservoirs in the inner basement rock (Ginfder and Fielding 2005). Table 5.4 Comprehensive evaluation of reservoir properties of basement rock Sequence

I

Lithology

Pore type

II

III

IV

Tectonic Granitoids, breccias, migmatitic cataclastic rocks, granites, leptites mylonitic rock

Syenitoid, migmatitic gneiss, injection migmatite, gneissic rocks

Dioritoid, amphibolic rock, leptynites, migmatized metamorphic rocks

Structural fracture, broken intergranular pore, dissolved pore

Structural fracture, dissolution fracture, dissolved pore, cleavage crack

Microfracture, dissolved pores in dark minerals

Intercrystal pore, cleavage crack

Pore structure Fracture-pore combination

Fracture-pore combination-type, fracture-type, pore-type

Fracture-type, pore-type

No pore-no fracture -type

Capillary curve

A1 , A2

B1 , C1 , C2

B2 , C1 , C2

D

Porosity (%)

>5

1–5

1–5

293.90/36.70

> 503.50/58.60

>1145.70/53.70

>343.70/45.80

K Fm

Mango-1

Vitex-1

Pera Subdepression

359.10/55.40

CassiaW-1

350.50/49.40

331.50/40.00 377.00/55.00

426.00/54.62

436.00/53.17

178.30/40.20

482.10/59.50

R Fm

Ziziphus-1

Cola-1

Tamarind-1

477.80/53.30

B Fm

>380.3072.60

391.00/85.90

148.80/87.50

328.00/66.70

633.30/75.40

322.00/64.40

>66.00/89.30

1211.00/50.00

938.00/50.00

>19.80/59.90

M Fm

>728.00/41.70

>486.80/54.10

234.00/78.50

218.12/82.00

123.50/71.40

P Fm

>208.70/65.20

>233.20/56.90

>42.20/49.65

Note The data in the table are minima–maxima/average. Fm-Formation, B-Baobab Fm, R-Ronier Fm, K-Kubla Fm, M-Mimosa Fm, P-Prosopis Fm

Southern subbasin

Mango Depression

Mango Depression

Cola Depression

Annona-1

Annona Depression

Combretum-1

Well name

Structural unit

Table 6.1 Statistics of thickness of dark mudstone and percentage in formation thickness of some exploration wells

6.1 Source Rock Evaluation 235

236

6 Geochemical Characteristics of Source Rocks and Petroleum

Table 6.2 Statistics of organic matter abundance of dark mudstone in each formation of lower cretaceous Fm

TOC(%)

S1 + S2 (mg/g)

Chloroform bitumen “A” content(μg/g)

B

0.02–5.22/1.05

0.21–30.96/4.50

375–13,317/4200

R

1.36–12.21/2.03

4.99–57.41/9.42

247–10,533/3286

K

0.84–6.67/1.63

2.82–19.24/5.74

140–8217/1821

M

0.69–5.99/1.84

2.71–33.79/8.83

402–1900/984

P

0.92–12.62/2.20

1.99–82.02/10.20

559–6827/2141

Note The data in the table are minima–maxima/average

Kerogen Identification Kerogen identification (Table 6.4) shows that the macerals of the organic matter in diverse formations in the study area are mostly sapropelinite and exinite, suggesting high hydrocarbon potential. The total content of the two exceeds 65%, and the organic matter type is generally reasonable. The Kerogen Type Index (Ti ) is between 8.6 and 81.3, representing generally Type II1 organic matter. The Ti values of individual samples are high. For example, the Ti values of kerogen in well Delo-1 at 1465– 1515 m and 1830–1885 m are 80.8 and 81.3, respectively, meeting the standard for Type I organic matter (Ti ≥ 80). Hydrogen Index of Pyrolysis of Source Rocks Figure 6.1 shows a correlogram between the pyrolysis hydrogen index (HI) and the maximum pyrolysis peak temperature (T max ) of the source rocks, indicating that the organic matter in the Bongor Basin is mainly Types I–II1 with comparatively little Types II2 –III. The organic matter in the P and M Formations is optimal, mainly Type I and Type II1 , with the proportion of Type II2 and Type III organic matter gradually increasing upwards in the K, R, and B Formations.

6.1.4 Thermal Evolution Characteristics of Organic Matter The tectonic evolution and paleo-heat flow history of the basin determine the thermal evolution of the source rock, and the type and evolution stage of organic matter decide the oil–gas phase (Andrews-Speed et al. 1984). Restoration and reconstruction of the thermal history of the basin, and determination of the critical moment of the petroleum system combined with the formation period of the traps, help guide oil and gas exploration (Bray et al. 1992). Paleogeothermal Restoration There are two major active rift basins in eastern China, with high geothermal gradients caused by mantle plume. The geothermal gradient in the center of the Songliao

6.1 Source Rock Evaluation

237

Table 6.3 Statistics of kerogen carbon isotopes in source rocks at each formation of lower cretaceous Well

Well depth(m)

Fm

Sample

δ13 C(‰, PDB)

Type

Vitex-1

2570–2630

K

Kerogen

-25.9

Type II2

Vitex-1

2680–2760

K

Kerogen

-27.0

Type II1

Annona-1

2685–2760

K

Kerogen

-27.5

Type II1

Tamarind-1

2780–2835

K

Kerogen

-26.9

Type II1

Delo-1

1830–1885

R

Kerogen

-29.4

Type I

Delo-1

2005–2045

R

Kerogen

-28.8

Type I

Delo-1

2315–2350

K

Kerogen

-28.4

Type I

Delo-1

2510–2540

K

Kerogen

-28.1

Type I

Ronier D-1

970–1020

R

Kerogen

-28.2

Type I

Ronier D-1

1070–1120

R

Kerogen

-28.4

Type I

Ronier D-1

1300–1350

K

Kerogen

-28.3

Type I

Ronier D-1

1410–1460

K

Kerogen

-28.7

Type I

Ronier D-1

1560–1610

K

Kerogen

-28.9

Type I

Ronier D-1

1670–1720

K

Kerogen

-28.2

Type I

Ronier D-1

1730–1780

M

Kerogen

-29.0

Type I

Ronier D-1

1980–2030

M

Kerogen

-28.8

Type I

Ronier D-1

2170–2220

P

Kerogen

-29.2

Type I

Ronier D-1

2400–2450

P

Kerogen

-28.2

Type I

Prosopis-3

1730–1805

K

Kerogen

-28.3

Type I

Prosopis-3

1810–1878

K

Kerogen

-28.8

Type I

Ronier 4–1

1800–1850

K

Kerogen

-28.6

Type I

Cassia E-1

1980–2120

K

Kerogen

-27.5

Type II1

Cassia E-1

2375–2480

K

Kerogen

-28.1

Type I

Tamarind-1

2780–2835

K

Kerogen

-26.9

Type II1

Prosopis C-1

1815–1870

M

Kerogen

-29.1

Type I

Baobab S-1

1300–1380

M

Kerogen

-30.2

Type I

Baobab S-1

1510–1550

P

Kerogen

-30.0

Type I

Baobab S-1

1695–1775

P

Kerogen

-28.8

Type I

Basin reaches 50 °C/km, decreasing to 20 °C/km towards the Basin’s edge (Green and Duddy 2012). The terrestrial heat flow value is 20–90 mW/m2 , with an average of 70 mW/m2 (Liu et al. 2016). Geothermal fields also occur in the subbasins of the Bohai Bay, with the average heat flow value of the Bohai Sea being 65.8 mW/m2 (Wang et al. 2002). Depression-high structures control ground temperatures and geothermal fields, high in highs and low in structural lows. The geothermal gradient of low areas is 25–35 °C/km and of high areas 30–45 °C/km, with an average of 33 °C/km (Gong et al. 2003). The geothermal gradient is higher in shallow layers.

238

6 Geochemical Characteristics of Source Rocks and Petroleum

Table 6.4 Statistics of maceral composition of kerogen in source rocks in each formation of lower cretaceous Well

Depth(m)

Vitex-1

2570–2630 K

72.0

—

28.0

—

51.0

Type II1

2680–2760 K

67.0

—

32.7

0.3

42.2

Type II1

2685–2760 K

75.7

—

24.0

0.3

57.4

Type II1

Tamarind-1 2780–2835 K

70.0

0.3

29.0

0.7

47.7

Type II1

Delo-1

1465–1515 B

89.0

—

11.0

—

80.8

Type I

1830–1885 R

89.3

—

10.7

—

81.3

Type I

2005–2045 R

86.7

—

16.3

—

74.5

Type II1

2250–2295 R

82.3

—

17.7

—

69.0

Type II1

2315–2350 K

81.0

—

19.0

—

66.8

Type II1

2510–2540 K

75.3

—

24.7

—

56.8

Type II1

2750–2790 K

71.3

—

28.3

0.3

49.8

Type II1

970–1020

R

52.2

—

35.3

12.5

13.0

Type II2

1300–1350 K

50.0

—

46.0

3.8

12.0

Type II2

1670–1720 K

48.3

—

48.0

3.7

8.6

Type II2

1730–1780 M

55.6

—

41.0

3.4

21.5

Type II2

2400–2450 P

70.5

—

20.5

9

46.1

Type II1

1730–1805 K

79.7

0

20.3

0

64.5

Type II1

1810–1875 K

77.7

0

22.3

0

61.0

Type II1

1815–1870 M

66.3

0.3

32.7

0.7

41.2

Type II1

Baobab S-1 1300–1380 M

76.7

0.3

23.0

0

59.6

Type II1

Annona-1

Ronier D-1

Prosopis -3

Prosopis C-1

Fm Maceral content(%)

Kerogen Type Sapropelinite Exinite Vitrinite Inertinite type index Ti

(continued)

6.1 Source Rock Evaluation

239

Table 6.4 (continued) Well

Depth(m)

Fm Maceral content(%)

Kerogen Type Sapropelinite Exinite Vitrinite Inertinite type index Ti

1510–1550 P

73.0

0.7

26.3

0

53.6

Type II1

1695–1775 P

71.0

0

29.0

0

49.3

Type II1

Ronier 4–1

1800–1850 K

68.7

0

31.3

0

45.2

Type II1

Cassia E-1

1980–2120 K

70.7

0

29.0

0.3

48.7

Type II1

2375–2480 K

66.7

0.3

32.7

0.3

42.0

Type II1

Fm Formation, B Baobab Fm, R Ronier Fm, K Kubla Fm, M Mimosa Fm, P Prosopis Fm

The geothermal gradient gradually decreases with an increasing depth and tends to become and remain stable at around 33 °C/km at depths greater than 2500– 3000 m (Xiao et al. 2001). The average geothermal gradient in the rift basins in eastern China is significantly higher than the general global geothermal gradient of 30 °C/km (Duddy et al. 1988, 1998). The geothermal gradients of the rift basins in Central Africa are substantially lower (Fairhead 1992). The measured surface temperature in the Bongor Basin is 29 °C. According to 360 measured geothermal oil test data from 48 wells, the current geothermal gradient in the basin is 26.2 °C/km on average (Fig. 6.2). With increasing depth, the temperature points tend to become scattered (Bouaziz etal. 2015). At burial depths of less than 3000 m, the geothermal gradient of the basement increases with decreasing depth. For example, the temperature of well Baobab N-1 is 60.7 °C at a depth of 860 m, and the calculated geothermal gradient reaches 68 °C/km. At burial depths greater than 3000 m, the geothermal gradient of the basement decreases significantly (Green et al. 2003, 2005). For instance, in well Semegin-1, the temperature at a depth of 3048 m is only 103.3 °C, and the calculated geothermal gradient is 24 °C/km. This is similar to the influence of basement burial depth on the geothermal gradient in the Bohai Bay Basin. To calculate the geothermal gradient in the Bongor Basin, single-well oil test and temperature measurement data were selected from 19 wells drilled into the basement, as well as single-well temperature measurement data from 4 wells that have not drilled the basement but have obtained putative basement reflections on seismic imaging. The data indicate that the geothermal gradient gradually decreases with an increase in the burial depth of the basement and remains steady at about 29 °C/km once the depth exceeds 3000 m (Fig. 6.3). This may be because the inversion of the basin occurred late, with the uplift leading to denudation of strata and a consequent rise in surface temperature (Turner et al. 2008). The result is that the final temperature equilibrium point has not yet been reached. However,

240

6 Geochemical Characteristics of Source Rocks and Petroleum 900

900 R K

750

450

1

300

450

1

300 2

2

150

150

0 400

420

440

460

480

0 400

500

420

440

a

460

480

500

T max

T max

b

Annona Depression

900

Northern slope of Mango Depression

900 R

K

M

P

B

750

R

K

750

HI mg/g

600 HI mg/g

K

600 HI mg/g

HI mg/g

600

450

R

B 750

1

300

600 450

1

300 2 2

150 0 400

150

420

440

460

480

0 400

500

420

440

T max

460

480

500

T max

c Pera sag of Mango Depression

d

Southern Depression

900 R K

750

1050 M

900

P 750 1

450

HI mg/g

HI mg/g

600

300 2

600 450

1

300

150

2

150 0 400

420

440

460

480

500

0 400

420

440

e Cola Depression

460

480

500

T max

T max

f

Moul Depression

Fig. 6.1 Correlation diagram of HI versus Tmax of source rocks in different formations of individual structural units

6.1 Source Rock Evaluation

241 Temperature

Fig. 6.2 Relationship between tested formation temperature and depth

0

30

50

70

90

110

130

Above source rocks

500

Below source rocks Semegin 1

1000

Depth m

1500 2000 2500 3000 3500 4000

30 °C/km is used as the basis for thermal history calculation in basin simulation. This is consistent with the apatite fission track analysis results, and the paleo geothermal gradient is also 30 °C/km (Crowley 1993). Vitrinite Reflectance (Ro ) Analysis of the relationships between Ro values and depth in the Mango Depression (wells Semegin-1, Vitex-1, and Bersay-1) (Fig. 6.4a) and the Southern subbasin (well Delo-1) (Fig. 6.4b) shows that the depth threshold for mature source rock in the Pera Subdepression in the Mango Depression is about 1800 m, entering the peak of hydrocarbon generation at 2400 m (Green et al. 2002). The source rocks in the Southern subbasin have generally reached maturity, with the maturity threshold (Ro 0.5%) occurring at about 1500 m and the peak zone for hydrocarbon generation beginning at 2300 m (Sweeney and Burnham 1990). The depth of mature source rocks in the Northern Slope (well Calatropis-1) is shallower, at about 1400 m (Fig. 6.4c). However, analysis data for the Annona Depression is limited, with only one Ro value available (0.73% for well Annona-1 in the K Formation at 2685–2760 m). Pyrolysis Parameters of Source Rocks (Tmax ) Figure 6.5 indicates that the depth of mature source rocks in the Pera Subdepression in the Mango Depression is about 1800 m (Tmax > 435 °C), entering the peak of hydrocarbon generation at about 2400 m (Tmax > 445 °C). The depth of mature source rocks in the Annona Depression is about 1750 m, entering the peak of hydrocarbon

242

6 Geochemical Characteristics of Source Rocks and Petroleum

Fig. 6.3 Relationship between burial depth of top basement rock and geothermal gradient from individual wells

generation at about 2300 m. The depth of mature source rocks in the Southern subbasin is about 1500 m, entering the peak of hydrocarbon generation at about 2300 m. The depth of mature source rocks in the Northern Slope is comparatively shallow, at about 1250 m, with the peak of hydrocarbon generation at about 2250 m. The depth of mature source rocks in the Moul Depression is about 1200 m, with the peak of hydrocarbon generation at about 2250 m. Compared with other structural belts, the maturity threshold and peak of hydrocarbon generation in the northern slope and the Moul Depression are relatively shallow, which reflects the overall inversion characteristics of the basin, with the strongest inversion having occurred in the northeast.

6.1 Source Rock Evaluation

243

Ro 0

0.2

0.4

0.6

0.8

1

1.2

0

0.2

Ro 0.4

0.6

0.8

1

0.4

0.5

Ro 0.6

0.7

0.8

0.9

800 1000

500 500

1200

1000

1400

1000 Depth m

m Depth

Depth

m

1500 2000 2500

1500

2000

1600 1800 2000

3000

2200 2500 2400

3500

2600

3000

4000

a Pera Depression

b Southern Subbasin

c

Northern slope of Mango Depression

Fig. 6.4 Ro versus depth of source rocks in different structural units

6.1.5 Identification of Depositional Environments of Source Rocks In comparing biomarker parameters of the source rocks in various formations (Table 6.5), most of the parameters overlap, making it difficult to distinguish the source rocks from diverse formations. This is because there has been little change in either the sedimentary or the water environment of the source rocks between variant periods (Fig. 6.6). The source rocks in several formations have high gammacerane contents, with gammacerane indices generally greater than 0.25, indicating saline water in the sedimentary environment. C27 –C28 –C29 regular steranes are distributed in an asymmetric “V” shape, with C29 regular steranes predominating. There is a high abundance of C30 4-methylsterane. The tricyclic terpanes are mostly C23 tricyclic terpanes, with a high ratio of (C20 + C21 )/(C23 + C24 ) tricyclic terpanes. In fine comparison, the ratios (pregnane + homopregnane)/C27-29 R, C27 diasterane/C27 regular sterane, and C30 diahopane/C29 Ts can be used to differentiate between the source rocks of the P + M and K Formations as there are some differences in organic matter input and sedimentary environment between the formations (Figs. 6.7 and 6.8). The source rocks of the K Formation have relatively high ratios of C27 diasterane/C27 regular steranes, (pregnane + homopregnane)/C27-29 R, and C30 diahopane/C29 Ts compared with the source rocks of the M and P Formations, suggesting that the K Formation was deposited in a continental lacustrine sedimentary environment, rich in clay and with slightly higher salinity lake water.

244

6 Geochemical Characteristics of Source Rocks and Petroleum T max 420

430

T max

440

450

460

470

T max 420

400 410 420 430 440 450 460 470 480 490

0

430

440

450

460

470

0

0 500

500

500 1000

1000 1000 1500

2000

m

2000

1500

Depth

m Depth

Depth

m

1500

2500

2000 2500 3000 2500

3000

3500

R Fm. K Fm.

R Fm. K Fm.

4000

3500

a

Annona Depression

430

b

Pera Depression

c

Northern slope of Mango Depression

T max 440

450

460

420

430

T max 440

450

460

420 0

500

500

500

1000

1000

1000

Depth

1500

Depth m

m

m

0

1500

B Fm. R Fm. K Fm.

Southern Subbasin

450

460

1500

M Fm.

R Fm. K Fm.

P Fm. 3000

3000

3000

440

2500

2500

2500

430

2000

2000

2000

d

M Fm. P Fm.

3000

T max 420 0

Depth

K Fm.

B Fm. R Fm.

e

Moul Depression

f

Cola Depression

Fig. 6.5 Tmax -depth relationship of source rock of individual structural units

6.1.6 Comprehensive Evaluation of Source Rocks A comparison of the quality parameters of source rocks in the Lower Cretaceous formations in the individual tectonic units of the basin indicates good–excellent source rocks in several tectonic units (Table 6.6). However, due to the differences between formations exposed by drilling and variations in preservation degree caused by tectonic evolution, there are obvious discrepancies in source rocks from the same formation between the various depressions (Pan et al. 2014). Nevertheless, the major

K

2375–2480

K

K

K

M

M

M

M

P

P

1486–1409

1509–1514

1800–1850

1815–1870

1300–1380

1765–1795

2315–2340

1510–1550

1695–1775

Prosopis C-1

Baobab S-1

Mimosa NE-1

Cassia W-1

Baobab S-1

Ronier 4–1

K

1980–2120

Cassia E-1

K

2780–2835

Tamarind-1

K

K

K

2570–2630

2680–2760

2685–2760

K

1810–1875

K

K

2750–2790

1730–1805

Annona-1

Vitex-1

Prosopis-3

R

R

1830–1885

B

1465–1515

Delo-1

2250–2295

Fm

Depth(m)

Well

0.10

0.05

0.07

0.11

0.12

0.07

0.07

0.13

0.24

0.04

0.15

0.07

0.07

0.09

0.08

0.06

0.06

0.07

0.06

0.06

0.05

K1

0.05

0.07

0.11

0.05

0.06

0.07

0.03

0.03

0.08

0.05

0.07

0.12

0.06

0.14

0.08

0.04

0.03

0.11

0.06

0.04

0.08

K2

1.94

1.87

2.56

2.54

1.83

2.27

2.21

2.88

5.54

2.34

2.34

2.33

2.35

2.63

2.59

2.16

2.17

1.82

2.19

2.07

1.87

K3

0.69

0.82

1.04

1.11

0.73

1.04

0.68

0.46

0.65

1.04

0.87

1.11

0.64

1.31

0.90

0.74

0.68

0.51

1.10

0.65

1.22

K4

0.38

0.28

0.30

0.35

0.32

0.33

0.47

0.50

0.53

0.31

0.45

0.43

0.43

0.42

0.45

0.48

0.42

0.25

0.39

0.51

0.35

K5

0.36

0.28

0.32

0.44

0.34

0.33

0.27

0.43

0.53

0.36

0.37

0.43

0.38

0.39

0.44

0.25

0.19

0.33

0.31

0.24

0.30

K6

0.20

0.11

0.39

0.37

0.17

0.33

0.43

0.53

1.03

0.27

0.63

0.60

0.51

0.59

0.54

0.23

0.18

0.33

0.31

0.38

0.22

K7

Table 6.5 Statistics of biomarker parameters of saturated hydrocarbons of source rocks in the Bongor Basin

0.09

0.08

0.21

0.33

0.10

0.15

0.22

0.24

0.75

0.35

0.98

0.96

0.44

1.37

0.84

0.13

0.06

0.17

0.24

0.07

0.07

K8

1.31

0.46

1.27

1.98

0.86

1.25

1.51

1.22

3.01

0.73

2.04

1.33

2.09

1.82

1.64

1.03

0.56

0.77

0.88

1.29

0.50

K9

0.39

0.19

0.76

0.54

0.36

0.49

0.46

0.61

1.07

0.24

0.93

0.76

0.89

0.55

0.56

0.33

0.25

0.69

0.60

0.66

0.27

K10

0.30

0.41

0.50

0.61

0.50

0.33

0.25

0.38

0.98

0.22

0.26

0.29

0.18

0.44

0.23

0.27

0.19

0.41

0.37

0.39

0.47

K11

(continued)

0.17

0.11

0.24

0.26

0.24

0.14

0.13

0.21

0.42

0.07

0.35

0.27

0.17

0.50

0.26

0.12

0.10

0.14

0.12

0.12

0.07

K12

6.1 Source Rock Evaluation 245

P

P

1590–1625

P

1815–1835

1720–1800

P

P

1625–1645

1715–1740

P

1515–1540

P

P

2105–2125

2155–2175

0.10

0.11

0.04

0.04

0.04

0.05

0.18

0.18

0.16

0.18

0.11

K1

0.04

0.04

0.13

0.12

0.15

0.14

0.07

0.06

0.06

0.06

0.06

K2

3.77

4.10

2.36

2.28

2.30

2.27

2.47

2.17

2.46

2.82

2.55

K3

0.67

0.92

0.82

0.98

1.18

1.15

1.33

1.07

1.39

1.54

1.29

K4

0.31

0.30

0.27

0.27

0.28

0.27

0.33

0.41

0.39

0.35

0.38

K5

0.51

0.46

0.16

0.17

0.15

0.16

0.33

0.46

0.40

0.35

0.40

K6

0.35

0.24

0.09

0.10

0.09

0.10

0.28

0.38

0.28

0.26

0.24

K7

0.17

0.14

0.03

0.07

0.05

0.05

0.21

0.31

0.18

0.19

0.25

K8

2.57

2.32

0.52

0.45

2.12

0.39

1.46

2.47

1.84

1.75

1.91

K9

0.38

0.40

0.23

0.26

0.23

0.26

0.66

0.78

0.65

0.66

0.63

K10

0.34

0.35

0.46

0.46

0.48

0.63

0.40

0.54

0.57

0.54

0.57

K11

0.25

0.26

0.08

0.10

0.08

0.09

0.34

0.37

0.41

0.40

0.28

K12

Note K1 -tricyclic terpanes/hopanes; K2 -steranes/hopanes; K3 -5α(H),14(β)(H)-pregnane/homopregnane;K4 -5α (H),14(β)(H)-20R-C27 /C29 sterane; K5 -5α (H), 14(β)(H)20S/20(S + R)-C29 sterane; K6 -ββ/(αα + ββ)-C29 sterane;K7 -C27 diasterane/C27 regular sterane;K8 -(pregnane + homopregnane)/C27-29 R; K9 Ts/Tm;K10 -C30 diahopane/C29 Ts;K11 -gammacerane/C30 hopane; K12 -C23 tricyclic terpanes/C30 hopane. Fm-Formation, B-Baobab Fm, R-Ronier Fm, K-Kubla Fm, M-Mimosa Fm, P-Prosopis Fm

Phoenix-1

Baobab NE-1

P

P

1955–1980

P

1840–1865

Mimosa NE-1

2030–2050

Fm

Depth(m)

Well

Table 6.5 (continued)

246 6 Geochemical Characteristics of Source Rocks and Petroleum

6.1 Source Rock Evaluation

247 1.2

0.8 0.7

C30 diahopane / C29 Ts

C23 TT/C30 hopane

0.9

0.6 0.5 0.4 0.3 0.2

1 0.8 0.6 0.4 0.2

0.1 0

0.1

0.2

0.3

0.4

0.5

0

0.6

0.5

1

1.5

3

3.5

2 1.5 1 0.5

0

0.5

1

1.5

2

0

2.5

0.1

C26 TT/C25 TT

0.2

0.3

0.4

0.5

0.6

2

2.5

C23 TT/C30 hopane 1.2

1.2 C27 diahopane/C27 regular hopane

C27 diahopane /C27 regular hopane

2.5

2.5

0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1

1 0.8 0.6 0.4 0.2 0

2 Ts/Tm

C26 TT/C25 TT

C23 TT/C30 hopane

C28 29 TT/C30 hopane

0.5

1

1.5

2

2.5

3

1 0.8 0.6 0.4 0.2

3.5

0

0.5

1

1.5

C26 TT/C25 TT

Ts/Tm P Fm.

M Fm.

K Fm.

R Fm.

B Fm.

Fig. 6.6 Correlation diagrams of biomarker parameters in source rocks in the lower cretaceous formations. B Baobab formation, R Ronier formation, K Kubla formation, M Mimosa formation, P Prosopis formation, TT tricyclic terpanes

source rocks are in the M and P Formations, with the K Formation also possibly containing reasonable quality source rocks (Figs. 6.9 and 6.10). In laboratory geochemical evaluation of single well source rocks, the best available shale cuttings are always selected, with no systematic vertical differentiation. Therefore, source rock evaluation using logging offers a more scientific and comprehensive understanding of the vertical distribution of source rocks. It is also more conducive to a macro evaluation of the quantity and quality of source rocks (Passey et al. 1990). The study of source rocks by logging is based on their residual concentrations of generated hydrocarbons (Li et al. 2017). The oil and gas saturation of source rocks increases with burial depth, is directly proportional to the abundance of organic matter is directly related to organic matter’s type and maturity. The source rocks’ oil and gas saturation Sog directly reflects their hydrocarbon potential and is therefore

6 Geochemical Characteristics of Source Rocks and Petroleum

C27 diasterane/ C27 regular sterane

248 1.2 1.0 0.8 0.6 0.4

K Fm. M Fm.

0.2

P Fm. 0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

(Pregnane + homopregnane) / C27 29 sterane (20R) Fig. 6.7 Correlation diagram between (pregnane + homopregnane)/C27-29 sterane (20R) and C27 diasterane/C27 regular sterane in source rocks of different formations 1.6

K Fm. M Fm. P Fm.

C30 diahopane/C29 Ts

1.4 1.2 1.0 0.8 0.6 0.4 0.2 0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

(pregnane + homopregnane) / C27 29 sterane (20R) Fig. 6.8 Correlation diagram between (pregnane + homopregnane)/C27-29 sterane (20R) and C30 diahopane/C29 Ts ratios in source rocks of diverse formations

used as the basis for logging evaluation ƒ. Calibrated using cuttings and core data, logging data can be used to calculate the physical parameters of source rocks, their residual hydrocarbon content, total organic carbon content, hydrocarbon yield, and other parameters, in addition to facilitating the study of organic matter abundance, hydrocarbon yields, and the hydrocarbon expulsion capabilities of the rocks. Overall, it is an excellent means for evaluating effective source rocks (Crowhurst et al. 2002). Source rock evaluation in 13 wells in various depressions using logging, combined with readily available and plentiful drilling gas logging data, shows that the source rocks in the lower member of the B Formation are mainly in the Southern subbasin and the Pera subdepression in the Mango Depression, although generally in an immaturelow mature stage. The organic matter is mainly Types II and III and probably produces mostly low-mature biogas. The primary source rocks of the R Formation are the

6.1 Source Rock Evaluation

249

Table 6.6 Statistics of organic carbon content of each horizon in different structural units (unit: %) B Fm.

R Fm.

K Fm.

Annona Depression

0.16–2.70 0.72

0.14–12.8 1.08

Cola Depression

0.03–6.85 2.21

0.28–2.47 1.19

Structural unit

M Fm.

P Fm.

0.01–11.97 0.27–13.08 0.18–10.53 Moul Pera Depression Subdepression 1.63 1.69 1.63 North slope

0.41–9.46 2.10

0.36–12 1.79

0.50–11.83 0.31–4.71 1.22 1.60

0.1–5.09 1.0

Southern subbasin

0.32–13.28 0.44–9.56 2.14 1.53

Moul Depression

2.16–12.62 2.72–3.53 6.14 3.1

Note The values in the table are the distribution range/average value of organic carbon. B-Baobab Formation, R-Ronier Formation, K-Kubla Formation, M-Mimosa Formation, P-Prosopis Formation 0 0 60

80

Palmier 1

Cassia N-1 Combretum1

Cassia 1 12 180 20 0 40 Ronier 5 40 20 100 14 Prosopis C 2 0 12 0 120 Cassia E 1 0 Baobab 1 Tectona 1 20 140 20 Ronier S 1 0 Phoenix 1 Savonnier 1 120 Raphia S 1 Daniela 1 180 Vitex 1 1 6080 0 20 140 40 Pera 1 10 60 120 Doca 1 Lanea 1 220 0 40 8 16 240 22 0 20 0 260 200 0 20 260 100 20 80 40 80 14 16 14 1600 20 180 0 0 26 140 100 0 240 0 8 60 100 Mango 1 40 Moul 1 20 0

20

80

40 20 0

80

0

20

80

80 40

20

Annona 1

60

20

4 00

0

60

10

40

0 26

240

140

60

40

20

0

Well site

(a) Thickness trend of source rocks of the P Fm.

0.7

0. 8

0.8

1.0 0.8 1.

0 .7

0

1.4

0.7

0.8 0.7

Cassia N 1 0.

7

Cassia 1

1.

0

Palmier 01 .8 Tamarind 1

1.0

1. 5

Annona 1

0

2.

0

0 .5 0.6 Baobab 1 Raphia 1

6

1.

Ronier 5 Cassia E 1

0.

1 .5

1 .0 Cailcedra 1

7

2 .0

2 .0

1.1

0.9 0.

1.0

1.0

Savonnier 1

Pera 1

Calatropis 1

2 .0

2.5

3.5 3.0

3.

0

2 .5 0 2.

Semegin 1 Bersay 1 3 .0 3 .5

0 .7

0 . 6 0.5 Daniela 1

Mimosa SE 1 1.0

1 .5

Vitex 1

Mango 1

1 .5 1.6 1 .0 0 .6

Lanea E 2 1.0 1. 8

Moul 1 0.5

0.6

0 .6

Well site

(b) Current Ro contour map of the top P Fm.

Fig. 6.9 Thickness (a) and Ro contour map (b) of high-quality source rocks in the P Formation

250

6 Geochemical Characteristics of Source Rocks and Petroleum

0

20

0 20 40 60

240 0 60

20 Cassia N 1 80 0Combretum1 Ziziphus 1 0 Cassia W 1 Tamarind 1 20 160 60 Cola 1 40 Ronier 5 Annona 1 140 Prosopis C 2 20 Cassia 6E0 1 Baobab 40 NE 1 20 100 20 4 Baobab SE 1Raphia 1 0 Cailcedra 1 Ronier S 1 60 Mimosa 8 80 Delo W 1 Kubla 1 0 0 80 16 Daniela 1 20 Vitex 1 10 80 0 60 10 160 0 0 0 0 Delo 120 2 180 Doca 1 Lanea 1 12 40 0 20 Bersay 1 40 60 220 220240 200 20 80 4 120 6080 1000 100 120 40 2 20 0 10012140 40 Mango60180 0 20 Moul 1 40 6080 20

100 60

180

140

0 12

140

120

40

80

20

0 12

0 12 100 800 6

20

12

40

20

0

40

0

0

80

80 100

100

60

20

0

22

100

200

18600 1 40 1

20

18600 1140 120

0 104 16

120

0 18

40

80

0

60

0

80 40

Well site

(a) Thickness trend of source rocks of the KFm. 0.4

0 .5

4

4

0.5

0.

0.

0 .4

0. 4

0.4

0.4 0.

5

0. 5 Combretum1

Ziziphus 1

Tamarind 1 Cola 1

0. 5

0.

5

0 .6

0 .6

Cassia 1

Cailcedra 1 Savonnier 1

0.

Delo W 1 0.4

4

5

0.7

Delo E 1 0 .4 0 .9

Semegin 1

0.9

0 . 91.0 0.8 Mango 1

1.1

0.5

Ricinus 1

Doca 1 0 .6

Bersay 1 0.70.8

0 .9

0. 8

0.7

6

0.

7

4

6

0.

0.

0.

0 .5 0 .5 0 .6 Raphia S 1 Daniela 1

8 0 .Pera 1

0.

Delo 1

Baobab NE 1

0 .5 Mimosa SE 1

7

5

Ronier S 1

0.

0 .4

0.

0. 6

0.7

Vitex 1

0 .4

0 .5

Ronier 5 Cassia S 1 Prosopis C 2 Cassia E 1

Lanea 1 Lanea SE 1 0 .70.8 0. 4 0 .5

0 .6 0 .5

Moul 1

Well site

(b) Current Ro contour map of the middle K Fm.

Fig. 6.10 Thickness (a) and Ro contour map (b) of high-quality source rocks in the K Formation

Pera subdepression in the Mango Depression and the Cola Depression. They are immature or low-mature, with mainly Type II organic matter. The lower member of the K Formation, the M Formation, and the upper member of the P Formation are all inherited deposits with a high abundance of good quality organic matter, mainly Types I and II1 . In the Northern Slope, the K Formation is partially mature, and the M and P Formations are generally mature (Figs. 6.9 and 6.10). The source rocks in the depression are high-mature and form the major source rocks of the Bongor Basin. Moul Depression The Moul Depression experienced strong, late uplift, with the source rocks of the K, M, and P Formations developing and the maturity threshold occurring at about 2200 m. Most of the K Formation is immature-low mature, with only some mature source rocks. The M and P Formations source rocks are overall mature and locally high-mature. The organic matter is mostly of Types I and II1 . This is a proven petroliferous depression.

6.1 Source Rock Evaluation Depth m 0 350

251

TOC 1

2

S1 S2 mg/g 3

4

5

6

0

3

6

9

12

HI mg/g 15

18

0 100 200 300 400 500 600 700 800

550

II 2

750 950

B

Excellent

I

1150

Excellent

II 1

1350 1550

R

1750 1950 2150

K 2350 m

Fig. 6.11 Geochemical profile of well Bersay-1

Mango Depression The Mango Depression is deeply buried, and drilling in the Pera Subdepression has not yet encountered the P–M Formations. However, it is predicted that the formations are probably high- or even over-mature. There are high-quality source rocks in the B, R, and K Formations, mostly in the middle of the B Formation. Oil shale is locally developed (Fig. 6.11). The source rocks in the B Formation are immature, lowmature in the R Formation, and mature in the K Formation. This is another proven petroliferous depression. The Northern Slope of the Bongor Basin has great overall hydrocarbon potential. Rich geochemical data show that the distribution of active, high-quality source rocks is controlled by structural location and that the M and P Formations are generally mature. The K Formation is less deeply buried due to extensive late uplift and is usually immature-low mature (Fig. 6.12). The R and B Formations are immature and do not contain effective source rocks. This zone has been proven to be an oil–gas enrichment zone. Cola Depression High-quality source rocks have been drilled in the K Formation in wells Combretum1, Vitex-1, VitexN-1, and Ziziphus-1. Nevertheless, the K and R Formations in wells Cola-1 and Savonnier-1 do not contain effective source rocks. The organic matter is Type II1 , low-mature or mature, and the maturity threshold is at about 2000 m. Highquality mature source rocks in the M Formation were also drilled in well CassiaW-1

252 Depth m 0 500

6 Geochemical Characteristics of Source Rocks and Petroleum TOC 1

2

3

4

5

6

0

3

6

S1 S2 mg/g 9 12

15

18

0

HI mg/g 100 200 300 400 500 600 700 800

600

II 2

700

III

800

K

900

Excellent

II 1

Excellent

1000

M

1100 1200

I

1300 1400 P 1500 1600 1700 1800 1900

Fig. 6.12 Geochemical profile of well Baobab NE-1

in this depression, with Type II1 organic matter, but no source rock has been drilled in the P Formation. This depression is, again, a proven petroliferous depression. Annona Depression Comparatively few wells have been drilled in the Annona Depression, and only wells Annona-1 and Tamarind-1 have encountered the K Formation. The K and R Formations encountered in this depression contain only poor-medium source rocks. The organic matter type is mainly Type II2 , and the hydrocarbon potential is limited. This is an unconfirmed petroliferous depression. Southern Subbasin Four exploration wells have been completed in this depression. Petroleum geochemical analysis of the source rocks has only been carried out in well Delo-1 (Fig. 6.13). This well encountered the lower Cretaceous K, R, and B Formations. The abundance of organic matter in the R Formation is relatively high, and good source rocks have been identified. The K Formation is slightly inferior. The type of organic matter in the R Formation is mainly Type II1 and in the K Formation, mainly Type II2 . Overall, the degree of the thermal evolution of organic matter is not high. The R Formation is low-mature, and the K Formation is mature. The entire area experienced structural inversion and uplift. Currently, the maturity threshold is relatively shallow, at about 1500 m. This subbasin is a proven petroliferous area.

6.2 Geochemical Characteristics of Crude Oil Depth m 0 630

1.0

2.0

TOC 3.0

4.0

5.0

6.0

0

3

253 S1 S2 mg/g 6 9 12

15

18

HI mg/g 0 100 200 300 400 500 600 700 800

730

III

830 930 1030 1130

B 1230

Good

1330 1430 1530

Excellent

1630 1730 1830

R

1930

Excellent

2030 2130

II 1

2230 2330 2430

K

2530 2630

II 2

2730 2830

Fig. 6.13 Geochemical profile of well Delo-1

6.2 Geochemical Characteristics of Crude Oil 6.2.1 Physicochemical Characteristics of Crude Oil In the Bongor Basin, significant hydrocarbon accumulations exist in the lower Cretaceous P, M, K, R, B Formations and the Precambrian basement. The P Formation and the basement are the main pay zones. Bongor Basin crude oil has an API gravity of 11.7–66.82° and contains heavy oil (API gravity < 20°), medium oil (20° < API gravity < 34°), and light oil/condensate (API gravity > 34°). The basin’s oil is mostly medium, although heavy oil occurs in every stratum and is concentrated in shallow reservoirs such as the B, R, and K Formations (Schutter 2003). The gravity of the crude oil is not related to its oil layer but has a roughly linear positive correlation with its depth (Fig. 6.14). The B Formation contains only heavy oil, while the P Formation and the basement have a wide range of crude oil densities due to multi-stage migration and accumulation and later transformation. The Bongor Basin features typical continental crude oil with a high freezing point (>30 °C), high wax content (>8%), low sulfur ( δ13 C2 . Carbon isotope ratios can be applied to distinguish natural gases originating from different parent materials and in diverse stages of evolution. The carbon isotope ratios of methane in natural gas samples from the Bongor Basin (Table 6.15) suggest δ13 C1 values of between −38.5 and −52.7‰. The carbon isotopes in natural gas components in the Bongor Basin are in the normal carbon isotope sequence of δ13 C1 < δ13 C2 < δ13 C3 < δ13 C4 (Table 6.15), indicative of an organic origin. Hydrogen Isotopic Composition The natural gas in the Bongor Basin has methane hydrogen isotope values of −142 to −238‰, ethane hydrogen isotope values of −141 to −248‰, and propane hydrogen isotope values of −123 to −187‰ (Table 6.15). The isotopic hydrogen compositions vary between individual natural gas samples. Overall, the isotopic hydrogen compositions of organic natural gas tend to increase with the maturity of source rocks. At the same time methane and homologue δD values often become greater with the increasing molecular carbon number of the hydrocarbon gas, i.e., δDCH4 < δDC2H6 < δDC3H8 . Hydrogen isotope sequence reversals often occur, exemplified by natural gas samples from wells Delo-1 (at depths of 1666.90–1669.20 m and 1527.30–1530.70 m) and Mango-1 (at a depth of 2033.60–2038.31 m) which are in the order δD CH4 > δD C2H6 . This phenomenon may be related to the multi-stage charging of reservoirs.

6.3.2 Genetic Types of Natural Gas Genetic types of natural gas can be distinguished according to their various components and carbon isotopes. Scientific genetic identification of natural gas should differentiate the geneses of every component in the gas, or at least those of the main components, to determine the gas’s origin (Xu et al. 1996).

1146–1156

1297–1304

Delo-1

Mango-1

Mango-1

Daniela W-1

Daniela-2

RahiaS-5

2

3

4

5

6

7

780–783

2034–2038

1843–1849

1667–1669

1527–1531

Delo-1

1

Depth(m)

Well

Sequence bumber

Oil and gas layer

Gas layer

Oil and gas layer

Phase state

P

M

K

R

R

B

B

Stratum

−33.3 −33.1 −38.8 −37.1 −36.0

−39.4 −38.5 −52.7 −48.8 −44.1

−32.3

−33.8

−35.2

−31.3

−30.9

−31.8

−31.8

−31.3

−32.8

−32.9

−29.6

−29.8

−30.6

−29.5

2.5

−5.1

−5.9

—

−6.0

—

−166

−204

−222

−142

−142

−237

−238

−38.3

—

−38.5

−161

−202

−205

−146

−141

−248

−248

−130

−150

−187

−125

−123

−171

−168

Propane

−49.5

Ethane

−49.5

CO2

Methane

Butane

Ethane

Methane

Propane

Hydrogen isotope valueδD(‰, SMOW)

Carbon isotope valueδ13 C(‰, PDB)

Table 6.15 Carbon and hydrogen isotopic composition of natural gas in the Bongor Basin

282 6 Geochemical Characteristics of Source Rocks and Petroleum

6.3 Geochemical Characteristics of Natural Gas

283

Fig. 6.26 Carbon isotope distribution of methane series in natural gas

Genesis of Hydrocarbon Gas Organic Gas and Inorganic Gas The carbon isotopes in organic hydrocarbon gases are in the positive carbon sequence, i.e., δ13 C1 < δ13 C2 < δ13 C3 < δ13 C4 . The carbon isotopes of inorganic hydrocarbon gases are in the reversed sequence, δ13 C1 > δ13 C2 > δ13 C3 > δ13 C4 . The carbon isotopes of the alkane series in natural gases found in the Bongor Basin follow the positive sequence (Table 6.15 and Fig. 6.26), indicative of organic hydrocarbon gas. Identification of Oil-Type Gas and Coal-Type Gas Dai et al. (1992) gathered and analyzed more than 1500 δ13 C1-3 data worldwide to compile an identification chart to distinguish the carbon isotope origins of methane, ethane, and propane. The chart is divided into six areas, corresponding to six types of natural gas. Natural gas in the Bongor Basin falls within area II, which corresponds to oil-type gas (Fig. 6.27). Figure 6.28 shows the relationship between the carbon and hydrogen isotopic compositions of methane in natural gas in the Bongor Basin. With increasing evolution, the carbon and hydrogen isotopes of methane become heavier. Natural gas can be categorized into three types: biological-thermo-catalytic transitional gas (wells Delo-1, Daniela W-1, and Daniela-2), crude oil-associated gas (well Raphia S-5), and condensate-associated gas (well Mango-1). The nC7 -MCC6 -DMCC5 ternary diagram of C7 light hydrocarbons distinguishes coal-type gas (II) and oil-type gas (I) (Fig. 6.29). Natural gas in the Bongor Basin falls within the Type I area, again indicating oil-type gas.

284

6 Geochemical Characteristics of Source Rocks and Petroleum

Fig. 6.27 Genetic identification δ13 C1 -δ13 C2 -δ13 C3 diagram of natural gas (template from Dai et al. 1992). Note The legend refers to well numbers and depths, which correspond to the serial numbers in Table 6.14

Genesis of Non-hydrocarbon Components Dai (1993b, a) compiled a δ13 CCO2 -CO2 diagram to distinguish between carbon dioxide of organic and inorganic origin (Fig. 6.30). The carbon isotope ratio of carbon dioxide in the natural gas in the Bongor Basin is greater than −10‰, indicative of an inorganic origin. This is consistent with the inorganic origin of CO2 in the gas accumulations of the Melutand Muglad Basins in the CARS, which might be attributed to Paleogene magmatic activity and deep and large faults connecting the crust and mantle.

6.3 Geochemical Characteristics of Natural Gas

285

Fig. 6.28 δ13 CCH4 -δ13 DCH4 diagram of methane in natural gas (template from Dai 1993a, b). Note The legend refers to well numbers and depths, which correspond to the serial numbers in Table 6.14

Fig. 6.29 Genetic identification of C7 light hydrocarbons in natural gas (template from Wang et al. 2007)

n C7

I Oil type gas area II Coal type gas area 80

20

60

40 I

40

60

II

20

DMCC5

80

60

40

80

20

MCC6

6.3.3 Analysis of Natural Gas Maturity Evidence from Carbon Isotopes of Methane The basic principle of carbon isotope fractionation of organic matter is that the carbon isotopes of natural gas become heavier with increasing thermal evolution, particularly the thermal maturity of methane carbon isotopes. Current research generally attempts to describe the δ13 C1 -Ro relationship by using the thermal pressure simulation method

286

6 Geochemical Characteristics of Source Rocks and Petroleum

Fig. 6.30 Genetic identification of CO2 (template from Dai 1993b, a). Note The legend refers to well numbers and depths, which correspond to the serial numbers in Table 6.14

to simulate variations in the molecular weights of methane carbon isotopes with temperature. Nevertheless, there are wide variations in the obtained results, which might be explained by variations in experimental conditions or individual research targets (Table 6.16). Table 6.17 shows the calculated natural gas maturity of the Bongor Basin based on the δ13 C1 -Ro relationship. Well Delo-1 has very similar levels of natural gas maturity at two varying depths, ranging between 0.34 and 0.65% and averaging Table 6.16 δ13 C1 -Ro relationship of natural gas established in previous studies

Researcher (time)

δ13 C1 —Ro relationship Oil-type gas

Coal-type gas

Stahl(1975)

δ13 C

Martinn(1982)

δ13 C1 = 14.8lgRo -41

Schoell(1979)

δ13 C1 = 15lgRo -41 δ13 C1 = 15lnRo -35

Dai (1985)

δ13 C1 = 15.80lgRo -42.20

δ13 C1 = 14.12lgRo -34.39

Shen (1991)

δ13 C1 = 21.72lgRo -43.31

δ13 C1 = 40.49lgRo -34

Feng (1991)

δ13 C1 = 14.18lnRo -43.5

δ13 C1 = 5.41lnRo -33.25

1

= 17lgRo -42 δ13 C1 = 8.6lgRo -28 δ13 C1 = 8.6lnRo -28

6.4 Oil (Gas)-Source Correlation

287

0.47%. Well Daniela-2 has a maturity range of 0.38–0.69%, averaging 0.51%. These low maturities indicate a biological-thermocatalytic transitional origin. The maturity of the natural gas in well Raphia S-5 is between 0.75 and 0.96%, with an average value of 0.85%, indicating crude oil-associated gas. Well Mango-1 has two high-maturity values, indicating condensate-associated gas. Evidence from Paraffin Indices and Heptane Value Paraffin indices and heptane values are commonly used to determine the maturity of organic matter (Thompson 1983). The Bongor Basin is dominated by mature gas, with some high-mature gas, exemplified by wells Mango-1 and Raphia S-5 (Fig. 6.31).

6.4 Oil (Gas)-Source Correlation 6.4.1 Oil-Oil Correlation Comparison of Biomarker Parameters of Saturated Hydrocarbons Numerous complex factors combine to control the compositions of biomarkers in crude oils and gas, with the result that every classification index has limitations. Genetically related crude oils share significant similarities in parent sources and sedimentary environments. A comparison of biomarkers in the Bongor Basin reveals that all the crude oils sampled have similar parent material sources (Table 6.10). Carbon Isotope Characteristics of Individual Saturated Hydrocarbon in Crude Oils In the Bongor Basin, the carbon isotopes of individual saturated hydrocarbon in crude oil in the northern slope, the Cola Depression, the Southern subbasin, and the Moul Depression display similar distribution patterns (Fig. 6.32), suggesting similar parent material. Only three crude oils from wells Mango-1 and Pera-1 in the Mango Depression have heavier carbon isotopes of individual saturated hydrocarbon than those from other tectonic belts. This is in line with the understanding that well Mango-1 contains predominantly highly mature condensate gas: the oil and gas in the well are both derived from highly mature source rocks.

B

1666.90–1669.20

1843.01–1848.70

2033.60–2038.31

1146.00–1156.00

1297.40–1303.70

Delo-1

Mango-1

Mango-1

Daniela-2

Raphia S-5

P

M

R

R

B

1527.30–1530.70

Delo-1

Formation

Depth (m)

Well

Table 6.17 Calculated natural gas maturity

0.75

0.40

1.61

1.42

0.36

0.36

Stahl

0.76

0.38

1.71

1.50

0.34

0.35

Dai

Natural gas Ro (%)

0.92

0.56

1.67

1.51

0.52

0.52

Shen

0.96

0.69

1.42

1.33

0.65

0.65

Feng

0.85

0.51

1.60

1.44

0.47

0.47

Average

Crude oil-associated gas

Biological-thermocatalytic transitional gas

Condensate-associated gas

Biological-thermocatalytic transitional gas

Natural gas type

288 6 Geochemical Characteristics of Source Rocks and Petroleum

6.4 Oil (Gas)-Source Correlation

289

Fig. 6.31 Correlation diagram between the paraffin indices and heptane values of natural gas. Note The legend refers to well numbers and depths corresponding to the serial numbers in Table 6.14

Fig. 6.32 Carbon isotope distribution patterns of individual hydrocarbons in crude oil

6.4.2 Gas–Gas Correlation Comparison of Natural Gas Components Natural gas component parameters in the Bongor Basin all show similar distribution patterns (Fig. 6.33), which strongly suggests that the gases share similar parent materials.

290

6 Geochemical Characteristics of Source Rocks and Petroleum

Fig. 6.33 Comparison of component parameters of natural gas. Note The legend refers to well numbers corresponding to the serial numbers in Table 6.14

Comparison of Light Hydrocarbon Parameters Light hydrocarbon geochemical parameters provide a basis for determining the sources of natural gas and condensate and, in particular, act as direct evidence for gassource rock correlation without adequate other information (Mango 1990). Moreover, light hydrocarbon parameters make oil-source rock correlation possible, particularly for crude oils containing hydrocarbons with relatively low molecular weights (Zhang et al. 1991). In the study area, the light hydrocarbon parameters all exhibit similar distribution patterns (Fig. 6.34), which indicates that the gases may have similar parent materials and come from the same set of source rocks. Comparison of Carbon and Hydrogen Isotopes of Natural Gas Methane and Its Homologues A comparison of the hydrogen and carbon isotopes of natural gas components in the Bongor Basin shows a wide range of hydrogen isotopes, but all with similar distribution patterns (Table 6.15). The natural gas is therefore inferred to originate from the same horizon, but from different hydrocarbon kitchens, i.e., the gases are hydrocarbon generation products from diverse source rocks in various stages of maturity within the same horizon.

6.4 Oil (Gas)-Source Correlation

291

Fig. 6.34 Comparison diagram of light hydrocarbon parameters. Note The legend refers to well numbers corresponding to the serial numbers in Table 6.14

6.4.3 Oil–Gas Correlation Carbon Isotope Correlation The natural gas-oil-condensate-kerogen series shows enriched 13 C successively. The natural gas in the study area has a smaller δ13 C1 value of methane than the crude oil. This is also the same for natural gas and crude oil at the same depths (Table 6.18), suggesting that the same source rock may produce the crude oil and natural gas at diverse evolutionary stages.

Table 6.18 Comparison of carbon isotopes between natural gas and crude oil Well

Depth (m)

Formation

Natural gasδ13 C1 (‰, PDB)

Crude oilδ13 C(‰, PDB)

Delo-1

1527.30–1530.70

B

-49.5

-31.4

Mango-1

1843.01–1848.70

R

-39.4

-30.0

Mango-1

2033.60–2038.31

R

-38.5

-29.6

Daniela-2

1146.00–1156.00

M

-48.8

-32.7

Raphia S-5

1297.40–1303.70

P

-44.1

-32.1

292

6 Geochemical Characteristics of Source Rocks and Petroleum

Maturity Comparison Table 6.19 shows that the maturity of the natural gas in wells Delo-1 and Daniela-2 is lower than that of crude oils at the same depths. The gas comes from lower mature source rocks, and the crude oil comes from relatively mature source rocks. This may result from hydrocarbon expulsion from the same set of source rocks at various stages of thermal evolution or from two sets of source rocks of individual maturities simultaneously. Two natural gas samples from well Mango-1 have higher maturity than the crude oil at the same depth, indicating that the gas and oil came separately from the same source rocks at varying times. In well Raphia S-5, the maturities of natural gas samples are similar to those of crude oil at the same depth, implying that the natural gas and crude oil were generated by the same set of source rocks in the mature stage, and that the gas is, therefore, crude oil-associated gas.

6.4.4 Oil-Source Correlation (1) Comparison of biomarker parameters Biomarker analyses of source rocks reveal that the K Formation source rock is unique and quite distinct from the M–P Formation source rock in terms of its contents of pregnane and homopregnane. Pregnane occurs widely in the K Formation source rock but only within a narrow distribution range in the M–P Formation and with lower content. Pregnane (C21 and C22 ) has a unique geochemical significance among steroid biomarkers. It is primarily derived from the biological hormones progesterol and progesterone, as well as from the side-chain rupture of regular steranes during thermal evolution. Pregnane from original sedimentation accounts for only 10–20%, while 80–90% is from thermal degradation. Due to migration, the content of pregnane in crude oil is higher than in extracts from the source rocks themselves and is much more mature. Thermal degradation of mature pregnane may conceal its origin (Huang et al. 1989). The pregnane contents of all discovered crude oils in the Bongor Basin are less than 0.3, which indicates that they all originate from the M–P Formations (Turner et al. 2008). Figure 6.35 shows that most of the crude oils in the study area are plotted to the left of the K Formation source rock, within the range of the P and M Formation source rocks, which strongly suggests that they all originate from these rocks. However, comparatively few P and M Formation source rocks have been drilled, except on the northern slope, so the possibility of hydrocarbon sources in deep mature K Formation source rocks can not be completely disregarded. Geological and Geochemical Evidence Analysis of source rocks indicates that the Bongor Basin has vertically five sets of lacustrine shales: the B, R, K, M, and P Formations, with a cumulative thickness of more than 2000 m. The source rocks of the Lower Cretaceous B and R Formations

R

1843.01–1848.70

Mango-1

B

R

M

P

2033.60–2038.31

1146.00–1156.00

1297.40–1303.70

Mango-1

Daniela-2

Raphia S-5

B

1527.30–1530.70

1666.90–1669.20

Delo-1

Formation

Delo-1

Well section (m)

Well

0.85

0.51

1.60

1.44

0.47

0.47

Natural gas Ro (%)

0.91

0.81

1.00

0.97

0.78

0.78

RC = 0.55MPI1 + 0.44(Ro ≤ 1.35%)

0.91

0.80

1.01

0.98

0.77

0.77

RC = 0.6MPI1 + 0.40(Ro ≤ 1.35%)

Equivalent maturity of crude oil RC (%)

Table 6.19 Maturity comparison of natural gas and crude oil at the same depth

0.95

0.78

1.03

0.97

0.65

0.66

RC = 0.5946ln(MPR) + 0.9728(Ro < 1.8%)

6.4 Oil (Gas)-Source Correlation 293

294

6 Geochemical Characteristics of Source Rocks and Petroleum

C27 rearranged sterane/C27 regular sterane

1.50

1.20

K Fm. source rock

M Fm. source rock

P Fm. source rock

R Fm. crude oil

K Fm. crude oil

M Fm. crude oil

P Fm. crude oil

Buried hill crude oil

0.90

0.60

0.30

0

0

0.30

0.60

0.90

(Pregnane+homopregnane)/C27 29 sterane

1.20

1.50

20R

Fig. 6.35 Correlation diagram of typical biomarker parameters used in oil-source correlation

are mostly within the depression and are generally in an immature to the low-mature stage. The K Formation has comparatively high maturity in the depression, although often still in the low-mature to mature stage, and has low maturity in the northern slope. The M and P Formations have been drilled in the northern slope and the Moul Depression and are low to high-mature. Within the same horizon of source rocks, the Mango Depression has the highest maturity overall, followed by the Annona and Cola Depressions, while the northern slope has relatively low maturity. The mud shales of the upper P and M Formations act as both high-quality source rocks and effective regional caprocks, suggesting that the oil and gas in the P Formation and basement rocks may come from the P and M Formation source rocks (Green et al. 2011). Research into the maturity of normal oil and natural gas in different tectonic belts has shown that the normal oil in the basin is the product of mature to highmature source rocks but that the natural gas comes from both low mature and maturehigh-mature source rocks. A comparison of source rock maturities highlights the possibility that the mature to high-mature regular oil and natural gas come from the high-mature P and M Formations, not the low-mature K Formation. Some natural gas samples have low maturity, which might mean that they originated from P and M Formations source rocks when they were at a lower maturity stage. However, the possibility of generation in the K Formation or an altogether shallower horizon cannot be excluded.

6.4 Oil (Gas)-Source Correlation

295

6.4.5 Gas-Source Rock Correlation Carbon Isotope Comparison Carbon isotopes of kerogen in the source rocks of the Bongor Basin are shown in Table 6.3. Interpreted in conjunction with Tables 6.12 and 6.15, this shows that the natural gas has less δ13 C1 than the crude oil, the P and M Formations kerogens and some of the K Formation kerogen. It is considered that the natural gas in the Bongor Basin probably comes primarily from the P and M Formation source rocks. However, this does not entirely exclude the possibility of contribution from the K Formation source rocks. Maturity Comparison Analysis of natural gas maturity indicates that the natural gas in well Mango-1 is the product of high-mature source rocks. It is therefore unlikely to be derived from the relatively low-mature K Formation source rocks but is much more likely to originate from the M Formation. Other natural gases have relatively low maturity and are likely to be derived from the relatively low-mature P and M Formations, without excluding the possibility of contribution from the K Formation. The crude oils in the northern slope and Moul Depression and the natural gas in well Raphia S-5 come from the M and P Formation source rocks. The natural gas in the biological-thermocatalytic transition zone in wells Daniela W-1 and Daniela-2 is also likely to have originated from the M and P Formations during a lower maturity stage. The oil and gas in the Mango Depression are products of high-mature source rocks, very probably those of the M and P Formations. Oil and gas maturities vary greatly in the Southern subbasin. Oil/gas-source rock correlation reveals that the crude oil may be derived from the M Formation, while the natural gas may be from the K Formation or even from the R Formation during a low maturity stage. In the Cola Depression, only well Cassia W-1 has penetrated high-quality mature M Formation source rock, although the oil and gas in well Vitex-1 might come from M and P Formations source rocks. No oil or gas has yet been discovered in the Annona Depression, and no high-quality mature source rock has been drilled there. In summary, the main source rocks in the Bongor Basin are the upper members of the M and P Formations, which have contributed most of the crude oil discovered to date. The K Formation may contribute to hydrocarbon generation in the deep depressions, a possibility that requires further investigation. The B and R Formations are the main sources of low-mature biological-thermocatalytic natural gas, with the accumulation of natural gas depending largely on the effectiveness of local traps (Magoon and Dow 1991).

296

6 Geochemical Characteristics of Source Rocks and Petroleum

References Andrews-Speed CP, Oxburgh ER, Cooper BA. Temperatures and depth-dependent heat flow in western North Sea. AAPG Bull. 1984;68(11):1764–81. Bouaziz A, El Asmi AM, Skanji A, et al. A new borehole temperature adjustment in the Jeffara Basin (southeast Tunisia): inferred source rock maturation and hydrocarbon generation via onedimensional modeling. AAPG Bull. 2015;99(9):1649–69. Bray RJ, Green PF, Duddy IR. Thermal history reconstruction using apatite fission track analysis and vitrinite reflectance: a case study from the UK East Midlands and Southern North Sea. Geol Soc Lond Spec Publ. 1992;67(1):3–25. Burnham AK, Sweeney JJ. A chemical kinetic model of vitrinite maturation and reflectance. Geochim Cosmochim Acta. 1989;53(10):2649–57. Cheng DS, Dou LR, Wan LK, et al. Formation mechanism analysis of Sudan high acidity oils by electrospray ionization fourier transform ion cyclotron resonance mass spectrometry. Acta Petrologica Sinica. 2010;26(4):303–1312. Cheng DS, Dou LR, Xiao KY, et al. Origin of high acidity oils in the intensively inversively inversed rift basin, Bongor Basin. Acta Petrologica Sinica. 2014;30(3):789–800. Crowhurst PV, Green PF, Kamp PJJ. Appraisal of (U-Th)/He apatite thermochronology as a thermal history tool for hydrocarbon exploration: an example from the Taranaki Basin, New Zealand. AAPG Bull. 2002;86(10):1801–19. Crowley KD. Mechanisms and kinetics of apatite fission-track annealing: discussion. Am Miner. 1993;78(1–2):210–2. Dai J, Yan S, Wu C, et al. Carbon isotope characteristics of organic alkane gases in China’s petroliferous basins. J Pet Sci Eng. 1992;7(3-4):329–338. Dai JX. Identification of coal formed gas and oil type gas by light hydrocarbons. Petrol Explor Dev. 1993a;29(5):26–32. Dai JX. Hydrocarbon isotope characteristics of natural gas and identification of various natural gases. Nat Gas Geosci. 1993b;2–3:1–40. Dou L, Cheng D, Li Z, et al. Petroleum geology of the fula sub-basin, muglad basin, sudan. J Pet Geol. 2013, 36(1). Dou L, Xiao KY, Hu Y. Petroleum geology and a model of hydrocarbon accumulations in the Bongor Basin, the Repubilc of Chad. ACTA petroleisinica. 2011;32(3). Dou LR, Cheng DS, Zhang ZW, et al. Division of petroleum systems by using integrated geological and geochemical analyses. Chin J Geol. 2002;04:495–501. Dou LR, Cheng DS, Li Z. The recognition and their genesis of tar mats of FN oilfield, Muglad Basin, Sudan. Geochimica. 2004;03:309–16. Dou LR, Hou DJ, Cheng DS, et al. Origin and distribution of high-acidity oils. Acta Petrolei Sinica. 2007;28(1):8–13. Duddy IR, Green PF, Laslett GM. Thermal annealing of fission tracks in apatite 3. Variable temperature behaviour. Chem Geol Isotope Geosci Sect. 1988;73(1):25–38. Duddy IR, Green PF, Hegarty KA, et al. Dating and duration of hot fluid flow events determined using AFTA and vitrinite reflectance-based thermal history reconstruction. Geol Soc Lond Spec Publ. 1998;144(1):41–51. Fairhead JD. The west and central African rift system: forward. Tectonophysics. 1992;213(1– 2):139–40. Genik GJ. Petroleum geology of Cretaceous-Tertiary rift basins in Niger, Chad, and Central African Republic. AAPG Bull. 1993;77(8):1405–34. Gong YL, Wang LS, Liu SW. Distribution characteristics of geothermal field in Jiyang depression. Chin J Geophys. 2003;46(5):653–8. Green PF, Duddy IR, Hegarty KA. Quantifying exhumation from apatite fission-track analysis and vitrinite reflectance data: precision, accuracy and latest results from the Atlantic margin of NW Europe. Geol Soc Lond Spec Publ. 2002;196(1):331–54.

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Green PF, Duddy IR, Hegarty KA. Comment on “Compositional and structural control of fission track annealing in apatite” by J. Barbarand, A. Carter, I. Wood and AJ Hurford. Chem Geol. 2003; 198:107–137. Chem Geol. 2005; 214(3):351–58. Green PF, Duddy IR, Bray JR. Resolution of early Cenozoic regional exhumation and midcretaceous basin inversion in the southern North Sea, using AFTA. AAPG Meeting, Paris, 2005, Abstract 2005. Green PF, Duddy IR, Malan J. AFTA data show that the southern margin of Africa was buried by early Cretaceous sediments prior to the onset of regional exhumation. PESGB/HGS Africa Meeting, extended abstract, 2011. Green PF, Duddy IR. Thermal history reconstruction in sedimentary basins using apatite fissiontrack analysis and related techniques. Anal Therm Hist Sedimen Basins: Method Case Stud: SEPM Spec Publ. 2012;103:65–104. Green PF, Duddy IR, Japsen P, et al. The tectonic development of Africa’s elevated passive continental margins and implications for exploration. PESGB/HGS Africa Meeting, extended abstract, 2013. Hu JY. Theoretical basis of continental petroleum geology in China. Beijing: Petroleum Industry Press; 1991. Hwang RJ, Ahmed AS, Moldowan JM. Oil composition variation and reservoir continuity: unity field, Sudan. Org Geochem. 1994;21(2):171–88. Japsen P, Bonow JM, Green PF, et al. Episodic burial and exhumation in NE Brazil after opening of the South Atlantic. Geol Soc Am Bull. 2012;124(5–6):800–16. Klusman RW, Saeed MA. Comparison of light hydrocarbon microseepage mechanisms. In: Schumacher D, Abrams MA, editors. Hydrocarbon migration and its near surface expression. AAPG Memoir; 1996. p. 157–168. Levorsen AI, Berry FAF. Geology of petroleum. San Francisco: WH Freeman; 1967. Li W, Dou LR, Wen ZG, et al. Buried-hill hydrocarbon genesis and accumulation process in Bongor Basin, Chad. Acta Petrolei Sinica. 2017;38(11):1253–62. Liu CP, Zhong X, Zhu HL. Research on the formation mechanism for the medium-low geothermal field in the north of Songliao basin. Geol Surv Res. 2016;04:316–20. Lu HZ, Fan HR, Ni P. Fluid inclusion. Beijing: Science Press; 2004. p. 1–450. Lu YL, Liu JQ, Dou LR, et al. Geochemistry and petrogenesis of volcanic rocks from Chad basins, Africa. Acta Petrologica Sinica. 2009;25(1):109–23. Macgregor DS. Hydrocarbon habitat and classification of inverted rift basins. In: Buchanan JG, Buchanan PG, editors. Basin inversion. Geological Society Special Publication No. 88, 1995. p. 88–93. Magoon LB, Dow WG. The petroleum system-from source to trap. AAPG Bull. 1991;121– 140+189–200+211–218. Mango FD. The origin of light hydrocarbons in petroleum: a kinetic test of the steady-state catalytic hypothesis. Geochim Cosmochim Acta. 1990;54(5):1315–23. Mchargue TR, Heidrick TL, Livingston JE. Tectonostratigraphic development of the Interior Sudan rifts, Central Africa. Tectonophysics. 1992;213:18 McMillan PF, Hofmeister AM. Infrared and Raman spectroscopy. Rev Mineral Geochem. 1988;18(1):99–159. Mohamed AY, Ashcroft WA, Iliffe JE, et al. Burial and maturation history of the Heglig field area, Muglad Basin, Sudan. J Pet Geol. 2000;23(1):107–128. Mohamed AY, Pearson MJ, Ashcroft WA, et al. Modeling petroleum generation in the southern Muglad Rift Basin, Sudan. AAPG Bull. 1999;83(12):1943–64. Pan J, Wen ZG, Wang D, et al. Geochemical characteristics and genetic analysis of light oil in the northern slope of Bongor Basin. J Yangtze Univ (nat Sci Ed). 2014;11(8):27–33. Schull TJ. Rift basins of interior Sudan, petroleum exploration and discovery: AAPG Bulletin. 1988;72:1128–1142. Schutter SR. Hydrocarbon occurrence and exploration in and around igneous rocks. Geol Soc Lond Spec Publ. 2003;214(1):7–33.

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Sweeney JJ, Burnham AK. Evaluation of a simple model of vitrinite reflectance based on chemical kinetics. AAPG Bull. 1990;74(10):1559–70. Talbot MR. The origins of lacustrine oil source rocks: evidence from the lakes of tropical Africa. Geol Soc Lond Spec Publ. 1988;40(1):29–43. Thompson KFM. Classification and thermal history of petroleum based on light hydrocarbons. Geochim Cosmochim Acta. 1983;47(2):303–316. Tong XG, TIAN, PAN, et al. Geological mode and hydrocarbon accumulation mode in Muglad passive rift basin of Sudan. Acta Petrolei Sinica. 2004. Tong X, Xiao K, Dou L, et al. AAPG Annual Meeting, June 16-19, 2005, Calgary, Alberta: Great Palogue Field in Melut Basin, Sudan. Search & Discovery. 2005. Turner JP, Green PF, Holford SP, et al. Thermal history of the Rio Muni (West Africa)-NE Brazil margins during continental breakup. Earth Planet Sci Lett. 2008;270(3):354–67. Wang LS, Liu SY, Xiao WY, et al. Distribution characteristics of terrestrial heat flow in Bohai Basin. Chin Sci Bull. 2002;02:151–5. Wopenka B, Pasteris JD, Freeman JJ. Analysis of individual fluid inclusions by Fourier transform infrared and Raman microspectroscopy. Geochim Cosmochim Acta. 1990;54(3):519–33. Wright JB. Review of the origin and evolution of the Benue Trough in Nigeria. Earth Evolut Scenes. 1981;1:98–104. Xiao WY, Wang LS, Li H, et al. Geotemperature field in Bohai sea. China Offshore Oil Gas (Geol), 2001;2:18–23. Xu PC, Li RB, Wang YQ. Raman spectroscopy in geosciences. Xian: Shaanxi Science and Technology Press 1996:1–86. Zhang LH, Zhu BY, Zhao GX. Mixed insoluble monolayers of fluorocarbon and hydrocarbon surfactants. J Colloid Interface Sci 1991;144(2):483–490.

Chapter 7

Geological Features of Hydrocarbon Reservoirs

Oil and gas accumulations are the smallest and most basic units in petroleum exploration and development, and for calculating oil and gas reserves (Dou 2001). There are numerous types of trapped reservoirs, so their classification must reflect their origins and those of the formations that host them. More importantly, classification must also reflect the structure and depositional environment in which the traps were formed, setting out clear distribution laws for fields to guarantee an acceptable success rate in drilling (Hu 1986). Before 1950, traps were classified based on their shapes (North 1990). Later (1950–1990), the basic characteristic for classification was the geological cause of traps. Since 1990, trapped reservoirs’ genetic dynamics have become the basis for classification (Hu 1991). After more than half a century of exploration, almost all of the reservoirs discovered in the rift basins of CASZ are sandstone reservoirs (Song 1997). In the Muglad Basin, the main types of trapped reservoirs are Cretaceous anticlines and reverse fault blocks (Tong et al. 2004; Dou et al. 2006). Examples include the Unity Oilfield (Giedt 1990) and the Fula Oilfield (Dou et al. 2006; Lirong et al. 2013). Large drape anticlines with complex faults in the Paleogene form the leading trap type in the Melut Basin (Dou 2005). The Palogue Oilfield, which has geological reserves of more than 5 × 108 t, is an example of this type (Dou et al. 2006). The largest Oilfield in the Doba Basin, the Kome Oilfield, is a large compresso-shear anticline trap (Genik 1992).

7.1 Hydrocarbon Reservoir Types The Bongor Basin is a continental rift basin formed against a background of strikeslip extension in the Early Cretaceous. Strong inversion during the Late CretaceousPaleocene was crucial for forming and reforming traps in the basin. The characteristics of trapped reservoirs are generally relatively consistent. There are many vertical oil-bearing formations, long well sections, rapid changes in reservoir facies, strong © Petroleum Industry Press 2023 L. Dou et al., Petroleum Geology and Exploration of the Bongor Basin, https://doi.org/10.1007/978-981-19-2673-0_7

299

300

7 Geological Features of Hydrocarbon Reservoirs

heterogeneity, complex physical properties of crude oil, Etc. However, this variety of features is a challenge to clarity in classifying hydrocarbon reservoirs. For the sake of simplicity, the hydrocarbon reservoirs are first divided into three basic types: sandstone reservoirs, basement rock buried hill reservoirs, and combination reservoirs formed by the superimposition of sandstone strata on buried hills (Hu et al. 1994). These basic types are then subdivided according to the genetic types of the traps. The accuracy and clarity of this classification will be vital to oil and gas exploration and development in Central Africa.

7.1.1 Sandstone Reservoirs Since 2007, twelve Oilfields and four petroliferous structures have been discovered in the Bongor Basin. Sandstone reservoirs are mainly in the Lower Cretaceous. The main pay zones are the sandstones in the P and K Formations, followed by the M, R, and B Formations. Nearly south-north regional compression in the late Late Cretaceous caused uplift and denudation of the entire basin, producing a large number of compression inversion anticlines and increasing the amplitude of early anticlines and fault blocks. This activity cycle created favorable locations and conditions for oil and gas accumulations. According to their geneses, the resulting reservoirs can be divided into compression inversion anticline reservoirs, fault-block reservoirs, and structurallithological reservoirs (Li 1980). Compression inversion anticline reservoirs are the most common. Compression Inversion Anticline Reservoirs Compression inversion anticline structures are formed under horizontal tectonic compression stress. Faults often complicate them. Some anticlines have early paleouplift backgrounds. The inversion anticline structures typically developed in the Bongor Basin have several notable features: First, the trap shape is controlled by the duration and intensity of inversion. The anticlines are often concentric, and their axes are not parallel to the main controlling faults, but are vertical. Closure amplitudes are large in the lower part and small in the upper part. Second, the traps were formed at various times. The final period was the intense tectonic inversion event at the end of the Late Cretaceous. Earlier inversion anticlines, formed during oil and gas migration, are the most favorable for the accumulation of oil and gas. Third, oil and gas occur in multiple layers. The P, M, and K Formations are all frequently petroliferous. Oil and gas are interbedded, dominated by layered edge water reservoirs. Ronier Oilfield The Ronier Oilfield was the first discovered in the Bongor Basin. It is located near Koudalwa Village in southern Chad. The first exploration well, Ronier-1, obtained commercial oil flow in the K Formation (in a test interval at 1057.00–1070.80 m) in April 2007. The Ronier structure is an inversion anticline developed on a basement

7.1 Hydrocarbon Reservoir Types

301

uplift background, complicated by multiple nearly EW- and NW-trending faults (Fig. 7.1). A large fault in the central part divides the anticline structure into two faulted anticlines, to the south and north. The northern anticline is itself divided by two nearly EW-trending faults. It contains two local fault blocks: the Ronier-1 block and the Ronier-3 block, with NW and nearly SN axial orientations, respectively. The stratigraphic dip is relatively gentle, the closure is 100–120 m, and the trap area is 9.9 km2 (Figs. 7.2 and 7.3). The southern structure is a faulted anticline structure clamped by a nearly EW-trending fault and a NE-trending fault. It is divided into a southern fault block, and a northern faulted anticline trap by the EW-trending fault and contains the Ronier-4 and Ronier C-4 blocks. The axial direction is nearly NS, the stratigraphic dip is relatively gentle, the closure is 45–80 m, and the trap area is 11.2 km2 .

0

-8

50

2km

-8 00

-7 50

-8

50 -800

Ronier- 2 Ronier- 1

-7

00

00 -8

0

- 900

-80

Ronier- 3

-85

0

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Fig. 7.1 Top structural map of the K Formation, the Ronier Oilfield

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7 Geological Features of Hydrocarbon Reservoirs 0 50 A

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Fig. 7.2 Top structural map of the KI Formation, the Ronier-1 Oilfield A

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Fig. 7.3 Cross-section through the Ronier Oilfield (for location see Fig. 7.2)

The main oil-bearing strata in the Ronier Oilfield are the Lower Cretaceous K Formation sandstones, followed by the P Formation, M Formation, R Formation, and B Formation sandstones. The porosity of the P Formation sandstone reservoir ranges from 14.6 to 21.2%, with an average of 18.4%, and its permeability is between 50 and 318 mD, with an average of 162 mD. It is, therefore a medium-porosity, medium–low permeability reservoir. The M Formation sandstone is mainly white, fine- to coarse-grained feldspathic quartz sandstone, with reservoir porosity ranging from 15.7 to 22.5%, averaging 18.9%, and permeability between 67 and 460 mD, averaging 200 mD. It is a medium-porosity, medium-permeability reservoir. The K

7.1 Hydrocarbon Reservoir Types

303

Formation is the main reservoir of the Ronier Oilfield and is divided into the KI and KII members. The sandstone is primarily white and light-gray heterogranular feldspar sandstone. The porosity of the reservoir in KI ranges from 14.7 to 26.8%, with an average of 21.0%, and permeability ranges from 13.3 to 1509 mD, with an average of 577 mD. The porosity of the reservoir in KII ranges from 20.8 to 27.7%, with an average of 23.2%, and permeability ranges from 20 to 1653 mD, with an average of 789 mD. The K Formation reservoir is thus a medium porosity, medium–high permeability reservoir. The R Formation sandstone is mainly white, light yellowolive green fine sandstone-gritstone, with some conglomerate. Reservoir porosity ranges from 21.8 to 27.2%, with an average of 25.1%, and permeability ranges from 378 to 1741 mD, with an average of 826 mD. This is a medium-porosity, medium– high permeability reservoir. The B Formation is relatively shallow, with a lithology of mainly fine sandstone-gritstone. Reservoir porosity ranges from 25.2 to 27.7%, with an average of 26.6%, and permeability ranges from 727 to 2043 mD, with an average of 1187 mD. This reservoir has medium–high porosity and high permeability. The Ronier reservoir has a large vertical distribution, with the density of crude oil changing with depth. It generally has high density, high viscosity, high wax content, low pour point, and low sulfur content (Song et al. 2009). Light oil or condensate gas reservoirs occur in the deep P-M Formation, with the relative density of crude oil being 0.812 g/cm3 , the gas-oil ratio 1577 m3 /m3 , viscosity 0.759 mPa s, wax content 18.4%, sulfur content 0.033%, resin + asphaltene content 11%, and pour point 21 °C. This signifies a light oil reservoir. The relative density of the crude oil in the KI reservoir is comparatively low (0.857 g/cm3 ), with a gas-oil ratio of 54 m3 /m3 , viscosity 19.1 mPa s, wax content 11.9%, sulfur content 0.085%, resin + asphaltene content 13%, and pour point of 29 °C. This is a conventional oil reservoir. The average relative density of crude oil in the KII reservoir is 0.9228 g/cm3 , with viscosity 157.1 mPa s, wax content of 16.55%, sulfur content of 0.0757%, and resin + asphaltene content of over 13%. The pour point is only 6 °C, and the gas-oil ratio is 13 m3 /m3 . Again, this is a conventional oil reservoir. The R Formation reservoir is a heavy oil reservoir with a crude oil density of 0.956 g/cm3 , wax content of 1.2%, sulfur content of 0.147%, resin + asphaltene content greater than 30%, and the pour point at −5 °C. It is a conventional heavy oil reservoir. The crude oil density of the B Formation reservoir is 0.966 g/cm3 , with the viscosity of 2481 mPa s, wax content of 0.89%, sulfur content of 0.0755%, resin + asphaltene content of over 40%, and the pour point at 7 °C. This is also a conventional heavy oil reservoir (Wen et al. 2013). The burial depth of the reservoir in the Ronier Oilfield is between 500 and 2500 m, the geothermal gradient is 36.4 °C/km, and the pressure coefficient is 0.948, representing a normal temperature and pressure system (Xiong 1988). The natural gas in the Ronier reservoir is solution gas. Sampling analysis in the Ronier-1 block confirms dry gas with a relative density of 0.573–0.577 g/cm3 and methane content of 97.65–97.7%. The formation water is generally fresh water, the predominant anion is HCO3− , the predominant cations are Na+ and K+ , and the water is type NaHCO3 . The total salinity of the formation water is between 330 and 5485 mg/L (Allen 1990).

304

7 Geological Features of Hydrocarbon Reservoirs

Baobab Oilfield The Baobab Oilfield lies in the central part of the northern slope of the Bongor Basin, on the north side of the Mimosa Subdepression. The top structure of the P Formation is a compression anticline trap. Three sets of faults in the plane—nearly EW-trending, NW-trending, and NE-trending—are dominated by the nearly EW-trending faults. These are all normal faults. The main fault, located in the middle of the tectonic belt, divides the structure into an upper and lower fault terrace: the Baobab and Baobab S structures. The Baobab faulted anticline, as a whole, is high in the north and low in the south, but there is a relatively low saddle structure in the northwest of the central section. A series of north-dipping normal faults develop from northwest to southeast. Although there is no continuity between the sets of faults, they collectively control the reservoir connectivity of the Baobab-1 and Baobab-2 well areas, forming a fault nose structure. The Baobab S area is high in the north and low in the south, with a structural high centered around wells Baobab S-1 and Baobab S-9, which forms the faulted anticline structure in the area (Figs. 7.4 and 7.5). The primary oil-bearing strata of the Baobab Oilfield are four sets of sandstone reservoirs in the Lower Cretaceous P, M, K, and R Formations. The P Formation is the main reservoir. The P Formation was deposited during the rapid rifting stage of the Bongor Basin. Thick dark mudstones and oil shales are intercalated with

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Fig. 7.4 Top structural map of the P Formation, the Baobab Oilfield

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7.1 Hydrocarbon Reservoir Types A

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Fig. 7.5 Cross-section through the Baobab Oilfield (for location see Fig. 7.4)

medium-sandstones and gritstones. The sandstone sediments are coarse (Hurford 1986). The provenance of the P Formation was mainly from fan delta front deposits lying to the northwest. The reservoir has multiple layers with thin individual layers. The pores are mainly primary intergranular pores, and the physical properties are good, with average porosity of 18% and average permeability of 48 mD, signifying a medium-porosity, low-permeability oil layer. The average porosity of the P Formation reservoir in Block Baobab-1 is 20.04%, and the average permeability is 68.88 mD, representing a medium-porosity, medium-permeability oil layer. The average porosity of oil layers in the PI oil group is 20.05%, and the average permeability 69.08 mD. The average porosity of the PII oil group is 19.98%, and the average permeability is 65.8 mD. The physical properties of the PII oil group are slightly inferior to those of the PI oil group. The P Formation in Block Baobab S-1 is a medium porosity, medium permeability oil layer, with average porosity of 18.29% and average permeability of 49.94 mD. The average porosity of the oil layers in the PI oil group is 18.44%, and the average permeability 51.37 mD. The average porosity of the oil layers in the PII oil group is 16.18%, and the average permeability 28.89 mD. The physical properties of the oil layer in Block Baobab S-1 are slightly inferior to those of the oil layer in Block Baobab 1. The sediments of the K Formation are mainly from the braided river and fan delta sedimentary system to the northwest (Magara 1976). The scale is larger than the P Formation, and grain sizes are finer. The sedimentary microfacies are mainly mouth bar and distal bar. The porosity of the K Formation sandstone is between 12.4 and 27.4%, concentrated between 22 and 25%, and an average of 21.9%. Permeability is in the range 0.25–12060 mD, with an average of 1336.6 mD. The superimposed oil-bearing area of the Baobab Oilfield is 12.77 km2 , crude oil density is 0.8811–0.8864 g/cm3 , and the viscosity of surface degassed crude oil at 50 °C is 51.63–99.36 mPa s, wax content is 3.35–8.2%, resin + asphaltene content is 4.68–13.13%, and the original gas-oil ratio is 29.3 m3 /m3 . These values signify high-viscosity conventional oil. The formation pressure coefficient of the P Formation in Block Baobab-1 is 1.07, which is normal pressure, and the geothermal gradient is 37 °C/km (Law 1998).

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7 Geological Features of Hydrocarbon Reservoirs

Crude oil density is 0.8864–0.9132 g/cm3 , and viscosity is 99.36–371.7 mPa s, representing highly viscous conventional oil. The formation pressure coefficient of the K Formation in Block Baobab-1 is 0.98, which is normal pressure, and the geothermal gradient is 17.7–20.8/km. Crude oil density is 0.9537–0.9545 g/cm3 and viscosity 2889–3002 mPa s, signifying high-heavy oil. The original formation pressure of the P Formation in well Baobab S-1 in the southern fault block is 19.23 mPa, saturation pressure is 8.93 mPa, the original gas-oil ratio is 44.2 m3 /m3 , crude oil density is 0.8668–0.8916 g/cm3 , and viscosity is 16.8–88.56 mPa s, representing conventional oil. The southern fault block has a pressure coefficient of 1.43, which indicates an abnormal high-pressure system with a geothermal gradient of 39 °C/km. The formation water is type NaHCO3 , with a total salinity of about 1700 mg/L (Ding et al. 2004). When the development well—Baobab 1–8—was deepened, high-yield oil flows were also obtained in the basement rock, indicating that the basement rock is also oil-bearing. This requires further investigation (Fig. 7.5). Baobab NE Oilfield The Baobab NE Oilfield is located in the middle of the Northern Slope of the basin. It is a fault nose structure with five large and small faults, roughly distributed in NW, NWW, and EW directions, mostly tenso-shear and tensional. The boundary fault is the first-order fault with a large scale, SE-NW-trending and dipping in the E-NE direction, with the dip angle generally 30°–70°. The fault displacement is mostly 900–1000 m, steep in the lower part and gentle in the upper part. The fault controls the southern boundary and the sedimentation of Block Baobab NE. A WNW-ESEtrending second-order fault divides the structure into two fault block traps, making it considerably more complex (Figs. 7.6 and 7.7). In July 2010, well Baobab NE-1, deployed in the Baobab NE structure, won out. According to logging interpretation, the oil layer is 192 m thick, and high-yield oil and gas flows were obtained at depth intervals of 1701.80–1721.20 m and 1434.80–1484.00 m. The Baobab NE Oilfield had been discovered. The main oil-bearing strata in the Baobab NE Oilfield comprise a large set of sandstone in the P Formation, with the overlying mudstone of the M Formation providing the principal caprock, and the whole forming a favorable reservoir-cap assemblage. Oil and gas distribution is controlled by structure and lithology. The sandstone is mainly grayish-brown and gray medium sandstone, gritstone, and sandy conglomerate, with a small amount of fine sandstone. The mudstone is mostly dark gray, massive mudstone, reflecting the development of the sand body in a deepwater or semi-deepwater environment. The core has a scoured surface and graded bedding, the result of deposition in a subaqueous distributary channel. Deformation, muddy gravel, and mudstone tearing clastics occur, indicating rapid deposition between subaqueous distributary channels in fan delta front subfacies. The thickness of individual sand bodies is generally greater than 2 m, with sandbodies 2–5 m thick forming the highest proportion, at 34.8%, representing a medium-thick layer. Reservoir distribution in the plane is uneven, and each sand set’s sedimentary thickness and distribution area is also different, indicating that the thickness center has migrated from time to time and that the sand body is constantly swinging. The porosity of the

7.1 Hydrocarbon Reservoir Types

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Fig. 7.7 Cross-section through the Baobab NE Oilfield (for locations see Fig. 7.6)

oil layer is mostly between 10.6 and 23.1%, with an average of 16.0%, and permeability is basically in the range of 3.0–164 MD, with an average of 34 MD. These values indicate a medium porosity, medium–low permeability reservoir. The Baobab NE Oilfield is a layered lithologic-structural conventional oil reservoir with edge water, with a superimposed oil-bearing area of 17.44 km2 . The pressure coefficient of the oil layer is 1.09, which is normal pressure, and the geothermal gradient is 37.8 °C/km. Crude oil near the oil–water contact has been oxidized and altered by edge water to form a heavy oil asphalt mattress. The oil layer is at a shallow

308

7 Geological Features of Hydrocarbon Reservoirs

depth longitudinally, with a large span (maximum 506 m), medium thickness, and is relatively closely concentrated. The crude oil is mainly medium oil. The surface crude oil contains 11.3–22.8% resin + asphaltene and 0.08–0.25% sulfur. The relative density of the oil is in the range of 0.8681–0.8911 g/cm3 , and the viscosity is 14.7–32.5 mPa s with an average of 26.36 mPa s. Analysis confirms that the crude oil in this reservoir is conventional oil. Prosopis Field The Prosopis Field is located about 7 km east of the Ronier Oilfield. The main oilbearing strata are the lower Cretaceous P, M, and K Formations. The first well to discover oil was Prosopis-1, completed in March 2009. Overall, the Prosopis structure is high in the east and low in the west. There are four structural traps (Figs. 7.8 and 7.9), all faulted anticlines, with the trap areas gradually decreasing from shallow to deep. There are two sets of faults. One set, trending NW–SE, is the main fault system in the area. A major fault in the northeast, with a fault displacement of more than 1000 m, is the primary controlling fault for the formation of traps and oil and gas accumulations. The other set consists of induced faults, EW-trending, with fault displacements of less than 100 m. Longitudinally, these faults are mostly in the Lower Cretaceous. The provenance of the Prosopis Oilfield is from the Ronier area to the northwest. The M Formation is a fan delta front deposit dominated by the front end of the fan delta front. It is close to a semi-deep lake containing more mud than sand. The sediment grain size is fine, and the mudstone is mostly brown-black. The sandstone is predominantly gray-white medium sandstone with a small amount of fine sandstone. The sedimentary environment of the oil group in the K Formation has changed considerably. It primarily consists of gray-white gritstone intercalated with thin mudstone layers. It generally comprises braided river delta front deposits, mouth bar deposits, and submarine distributary channel microfacies. The Prosopis Oilfield’s oil-bearing strata are the K, M, and P Formations, with the K Formation containing the main oil-bearing strata. The burial depth of the K Formation reservoir is 810–1300 m, with a single-layer thickness of less than 2 m. It is a layered edge water conventional oil reservoir with average porosity of 18.6% and average permeability of 58.7 mD. The burial depth of the M Formation reservoir is 1340–1500 m, with a single layer thickness of 0.9 m. The average porosity is 16.7% and, the average permeability is 11.6 mD. It consists of mediumporosity and medium–low permeability sandstone with a relatively concentrated vertical distribution. The original formation pressure of the main oil group in the K Formation is 15.15 mPa, and the pressure gradient is 0.97 mPa/km (a normal pressure system). The geothermal gradient of the reservoir is 35.1 °C/km (a normal temperature system) (Andrews-Speed et al. 1984). Crude oil density is 0.910–0.8872 g/cm3 . Natural gas is a dry gas with a relative density of 0.582 g/cm3 and methane content of 96.54%. The formation water is type NaHCO3 , with total salinity of 2324–4937 mg/L.

7.1 Hydrocarbon Reservoir Types

309

Fig. 7.8 Top structural map of the K formation, the Prosopis Oilfield

Daniela Oilfield The Daniela Oilfield lies at the eastern end of the Northern Slope. It is an inverted faulted anticline structure, developed in the basement and controlled at diverse stages by two NW-trending principal fractures. The north-dipping principal fracture controls the formation of the structure, and a south-dipping fracture reforms and refines the structure (Achiat et al. 2009). Restoration of the paleostructure shows that the structure took shape in the early Cretaceous. Following a strong rifting stage, the structural amplitude was increased by unbalanced regional stress. The intense inversion event that affected the entire basin at the end of the late Cretaceous had little impact on the structure of the P Formation (Wang et al. 2004). However, it made the structure of the K Formation more fragmented and increased its structural amplitude (Figs. 7.10 and 7.11). Well Daniela-1 was completed on August 7, 2011. An oil layer at 136.6 m

310

7 Geological Features of Hydrocarbon Reservoirs Prosopis 3

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Fig. 7.9 Cross-section through the K Formation, the Prosopis Field (for location see Fig. 7.8)

was interpreted in the P Formation by logging, and high-yield oil and gas flow was obtained in the well section at 1280.70–1353.50 m, with the density of the crude oil being 0.8524 g/cm3 . The Daniela Oilfield had been found.

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Fig. 7.10 Top structural map of the P Formation, the Daniela Oilfield

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Fig. 7.11 Cross-section through the P Formation in the Daniela Oilfield (for location see Fig. 7.10)

The primary oil-bearing strata in the Daniela Oilfield are the lower Cretaceous P Formation sandstone, followed by the M and K Formations. The sandstone of the P Formation has a coarse grain size and was formed by superimposed deposition of multi-stage fan delta front and subaqueous distributary channel. The lithology is mainly medium sandstone and gritstone, with porosity of 13.1–24.3% and permeability of 156–3650 md. Generally, the reservoir has medium porosity and medium– high permeability, but its physical properties gradually deteriorate with increasing burial depth. The porosity of the M Formation reservoir is 13.4–25.9%, and the permeability is 189–5654 md, which represents medium porosity and high permeability. The porosity of the K Formation reservoir is 17.1–32.4%, and the permeability is 517–7032 md, representing medium porosity and high permeability. The crude oil in the Daniela Oilfield has complex physical properties. The densities and viscosities of the oils in different fault blocks vary greatly. Viscosity is generally ‘high at the top and low at the bottom’. The upper K and M Formations contain conventional heavy oil (principally in the MII layer in Block Daniela E-1 and Block Daniela E-2), and the P Formation contains conventional oil. The density of the crude oil in the P Formation is 0.8520–0.9370 g/cm3 , with an average of 0.8846 g/cm3 , and the wax content is low (2.22–4.83%). The oil contains a small amount of sulfur (0.01–0.04%). The geothermal gradient of the reservoir is 38–49 °C/km, and the pressure coefficient is 0.9–1.10 (a standard pressure system). The PI layer in Block Daniela W-1 has an abnormal high-pressure system, with a pressure coefficient of 1.33 and a low gas-oil ratio (7.1–30.8 m3 /m3 ). The viscosity of the oil in layers PI and MII are 3.14–21.1 mPa s (except in the PI Formation in Block Daniela E-2), which is conventional oil. The viscosity range of the crude oil in layers MI and MII 1 (Block Daniela E-2) is 139.9–733.8 mPa s, representing conventional heavy oil. The difference between the reservoir pressure and the saturation pressure of the main producing layer in block Daniela-1 is 1150–1232 ψ, with a low gas-oil ratio (16.9–19.1 m3 /m3 ). The viscosity of the crude oil is 3.1–9.1 mPa s. The salinity of the formation water is low (2059–3236 mg/L), the pH value is 7.93–9.52 (weakly alkaline), and the formation water is type NaHCO3 .

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7 Geological Features of Hydrocarbon Reservoirs

Mimosa Oilfield The Mimosa structure is located southeast of the Ronier Oilfield. Overall, it is a long compressional axis anticline zone, high in the east and low in the west and complicated by faults. It consists of an anticline structure and multiple fault nose structures. The plane has two sets of NW–SE-trending and near EW-trending faults. The NW-trending faults are the principal faults, with a displacement of 280 m. The near EW-trending faults are induced faults, with small fault displacement. Longitudinally, the faults are mostly in the Lower Cretaceous. The KI top structure is a fault nose structure in the middle of the Mimosa-1 structure. Its axis is nearly EW, the elevation of the high is −700 m, the stratum dip angle is relatively gentle, the closure is 120 m, and the trap area is 11 km2 . The Mimosa-5 structure in the west is an anticline structure, with the trap area gradually decreasing from shallow to deep. The elevation of the high is −810 m, the closure is 40 m, and the trap area is 0.98 km2 . There are three fault nose structures in the east—Mimosa N-1, Mimosa-10, and Mimosa-2, respectively, from north to south—with mis-tie of 30, 50 and, 240 m, respectively, and trap areas of 0.75, 0.19, and 1.14 km2 , respectively (Figs. 7.12 and 7.13). The Mimosa Oilfield was discovered in 2008. An exploration well—Mimosa-4— obtained high-yield conventional oil flow in oil test in the K Formation in the interval at 1229.16–1249.28 m. This was the second oilfield found in the Bongor Basin. The Mimosa Oilfield can be subdivided into three sets of reservoirs—in the P, K, and R Formations from bottom to top—of which the K Formation is the main oil layer. The P Formation sandstone is light-gray, fine-coarse grained, sub-rounded, and medium sorted. Porosity ranges from 18.2 to 25.7% (an average of 21.9%),

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Fig. 7.12 Top structural map of the K Formation, the Mimosa Oilfield

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7.1 Hydrocarbon Reservoir Types

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Fig. 7.13 Cross-section through the K Formation of the Mimosa Oilfield (for location see Fig. 7.12)

and permeability ranges from 55 to 259 md (an average of 157 md). This represents a medium porosity, medium–low permeability reservoir. The rock types in the K Formation are mainly fine-grained clastic rocks, including conglomerate, pebbly sandstone, sandstone, siltstone, and mudstone. The lithology is primarily arkose, followed by quartz sandstone, mostly fine- and medium coarse-grained and containing a small amount of gravel. The pores are mostly intergranular poresdissolution pores, with porosity generally between 16 and 23% (median 19%), and permeability mostly between 1 and 120 md, concentrated at 10–100 md. Most of the reservoirs are medium porosity and medium–low permeability, although a few have ultra-low porosity and permeability or ultra-high porosity and permeability. The reservoir porosity of the R Formation is mostly between 22 and 35%, with a peak at 28–31%, and the permeability is mostly between 50 and 2000 md, concentrated at 200–1000 md. This is a medium–high porosity and medium–high permeability reservoir. In the Mimosa Oilfield, in the plane, the oil and gas layers are mainly distributed on the high horst of the long axis anticline. Vertically, they are mostly in the K Formation, followed by the P and R Formations. The P Formation oil reservoirs are mostly in the Mimosa N-2 well block, with a crude oil density of 0.8677 g/cm3 , representing light reservoirs. The crude oil in the K Formation has a low relative density (0.8550 g/cm3 ), low viscosity, low sulfur content, and high wax content, signifying medium crude oil. The oil and gas are in thin accumulations with a single oil–water system. The crude oil in the R Formation is high density (0.9590 g/cm3 ) and high viscosity (1953 mPa s), with high acid numbers (5.91–8.28 mg/g) and low wax content (about 1%). This is a heavy oil reservoir with a shallow burial depth and two oil–water systems. The distribution of the oil and gas layers is controlled by the structure and, to some extent, by the lithology. The K Formation oil reservoir is a layered edge water lithologic reservoir with a structural background, and the R Formation oil reservoir is a structural reservoir with a lithologic background. Natural gas is a dry gas, with a relative density of 0.6240 g/cm3 and methane content of 91.92%. The formation water is type NaHCO3 , with total salinity of 137–6046 mg/L. The predominant anion is HCO3 − , and the cations are mostly Na+ and K+ .

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7 Geological Features of Hydrocarbon Reservoirs

Fault Block Oil and Gas Accumulations Fault block oil and gas accumulation is the accumulation of oil and gas in fault traps. The impedance condition of the faults generally controls the abundance and accumulation degree of oil and gas. The oil and gas abundance of fault-block trapped reservoirs in the Bongor Basin depends on the fault’s lateral sealing degree and closed height. The closed height and closed area are related to the fault displacement and the thickness of the overlying mudstone cap and reservoir. The sealing of faults is associated with their degree of opening and the overall cementation of the fault zone. The oil–gas-water systems within fault blocks are simple, but between fault blocks, they are complex, with the oil–gas-water contact changing greatly and fluid properties influenced by the burial depths of the fault traps (Liu et al. 2008). Fault block oil and gas accumulations are mostly found in the Northern Slope. Some small-scale fault block oil and gas accumulations in the upper play. However, the lower play is highly petroliferous. Typical oil and gas accumulations include the Lanea oil and gas. The Lanea Field is situated in a fault nose structure formed by the intersection of two sets of faults east of the Bongor Basin (Figs. 7.14 and 7.15). The NE-trending faults in the south have large fault displacements and long extensions and contain subsidiary faults. They intersect with the NW-trending faults in the east, forming third-order faults with smaller fault displacements and short extension distances. These later faults further complicate the structure. The Lower Cretaceous is the primary sedimentary stratum, with its top denuded and the Paleogene-Neogene providing direct unconformable cover. The burial depth of the high of the P Formation in the Lanea Oilfield is −700 to −800 m, the closed amplitude is 300–500 m, and the trap area is 10 km2 . Well Lanea-1 was completed in May 2012. An oil test was conducted in a well section at

Oil Gas Fault 00 - 10

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A Lanea-1 -800

-1000

-900

Lanea-2 A′ 0

800m

Fig. 7.14 Top structural map of the P Formation, the Lanea Oilfield

7.1 Hydrocarbon Reservoir Types

315 Lanea 1

A

Lanea 2

A′

Oil 700

Gas

Elevation

m

Water 800

Fault

900

1000

P P

1 2

P

3

P

4

P

5

GOC 889m

OWC 996m

Fig. 7.15 Cross-section through the P Formation in the Lanea Field (for location see Fig. 7.14)

1184.00–1186.90 m in the PI 3 sand set and a well section at 1309.81–1315.80 m in the PI 5 sand set with high-yield oil and gas flow obtained in both cases. The main pay zone of the Lanea Field is the P Formation sandstone, which exhibits a certain degree of facies change in the plane. The oil layers in wells Lanea-1 and Lanea-2 are 87 and 43 m in thickness, respectively, with average porosity of 13.2– 26.1%, and average permeability of 179–5814 mD, representing medium porosity and medium–high permeability. The crude oil in the oil layer of the Lanea Field has a density range of 0.8435– 0.8761 g/cm3 , surface degassed crude oil viscosity (50 °C) of 8.3–31.6 mPa s, pour point at 27–32 °C, and a gas-oil ratio of 10.7–38.0 m3 /m3 . There is a gas cap at the top of the structure. The altitude of the gas/oil contact is −889 m, and the altitude of the oil–water contact is −996 m. The pressure system is normal. The oil layer has a geothermal gradient of 52–53 °C/km, a pressure coefficient of 0.99–1.06, and a normal pressure system. Structural-Lithologic Reservoirs Due to changes in regional stress fields, the extension of faults, and migration of sedimentary provenances, the sand bodies in continental rift basins and rifts undergo relatively rapid changes both in the plane and vertically, forming large structurallithological traps under specific structural conditions. The Baobab N Oilfield is a typical case (Qiao et al. 1999). The Baobab N Oilfield is located on the north slope of the Baobab N Subdepression in the Northern Slope of the Bongor Basin, facing the Baobab NE Oilfield across the low. It is a complete fault nose structure. There is a large northwest-striking fault in the north part of the Oilfield, with a steep occurrence and large fault displacement. Small nearly EW-striking faults also occur on the east and west sides, with short extension distances of 0.5–2 km. Their displacements are small, generally no more than 100 m. In May 2010, well Baobab N-1 was deployed in the local fault nose structure at the top of the slope and completed on September 3 of the same year. A thick oil layer was encountered in the P Formation, and a conventional oil layer was found at the bottom

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7 Geological Features of Hydrocarbon Reservoirs

of the M Formation. A total of 121.4 m/35 layers of oil layers were interpreted by logging. On November 21, 2010, an oil test was conducted in well Baobab N-1, with 39.5 m/6 layers perforated in a well section at 1038.60–1086.60 m. The test obtained high-yield oil and gas flow, with a crude oil density of 0.8654 g/cm3 . The crude oil density in the well section at 958.40–1015.60 m is 0.8778 g/cm3 . Further drilling confirmed that the Baobab N Oilfield is a structural-lithologic reservoir (Figs. 7.16 and 7.17). The main oil layer of the Baobab N Oilfield is in the PI oil group, with only conventional oil layers occurring in the MIII oil group. The oil layer is at a shallow depth and has a large span. The top of the oil reservoir is at 834 m and the bottom at 1781 m, an oil reservoir span of 947 m. The hydrocarbon-bearing interval is generally long (230–460 m). The main oil layer is a thick-bedded concentrated combination, with a maximum single-layer thickness of 28.3 m (average thickness 2.5–4.6 m). The P Formation reservoir comprises pebbled medium sandstone-gritstone and medium sandstone intercalated with thin layers of fine sandstone and siltstone. It was formed by superimposing multiple subaqueous distributary channels with fan delta front deposition. The sedimentary microfacies are mostly subaqueous and distributary

A′

0

1200m

B Baobab N 1

Baobab N 9

40

0

50

0

600

Baobab N 4 800

Baobab N 15 B′ 100 0

1400 Baobab N 8

15

110

00

0

130

Oil

0

Baobab N 11

Fault

A

Well location 1400

Fig. 7.16 Top structural map of the P Formation, the Baobab N Oilfield

7.1 Hydrocarbon Reservoir Types A

Baobab N 11

Baobab N 8

317

Baobab N 4 Baobab N 1

A′ B

Baobab N 9

Baobab N 4

Baobab N 15

B′

K 500

Elevation

m

K

M

M 1000

P Oil Wate

P

P 1500 P

Fault

Oil

Fig. 7.17 Cross-section through the Baobab N Oilfield (for locations see Fig. 7.16)

channels, with local gravity flow deposition. The reservoir is distributed in a north– south strip of uneven thickness—‘thin in the north and thick in the south’—and pinches rapidly to the west and east. The thickness center is near the Baobab N8 well block, with a thickness of more than 300 m. The reservoir thickness and distribution range of each sand set are slightly different. The reservoir lithology of the P Formation is mainly feldspathic sandstone of immature composition. The reservoir porosity of the PI oil group is 10.2–26.2% (average 17.7%), and the permeability is mostly between 3.3 and 224 mD (average 48.01 mD), indicating a medium porosity, low permeability reservoir. The geothermal gradient of the Baobab N Oilfield is 35.9 °C/km, and the pressure coefficient is 1.32, an abnormal high-pressure system. The density of the crude oil in the main oil layer is 0.8677–0.8774 g/cm3 , the viscosity is 5.33–41.21 mPa s, the gas-oil ratio is low (15.8 m3 /m3 ), the content of resin + asphaltene is 12.30–13.22%, the sulfur content is 0.0842–0.0918%, and the acid number is less than 0.5 mg/g. This is a conventional oil reservoir. The density of crude oil at the bottom of the reservoir is 0.9498–0.9507 g/cm3 , the viscosity is greater than 9000 mPa s, and the acid number reaches 0.8 mg/g. This represents heavy oil, the result of oxidation and biodegradation at the oil–water contact.

7.1.2 Buried Hill Reservoirs in Basement Rocks The Precambrian crystalline basement rocks in the Bongor Basin experienced longterm weathering and erosion from the Cambrian to the Jurassic, strike-slip extension in the Early Cretaceous, and compressional reversal and stress field transformation in the Late Cretaceous, all of which combined to form well-developed weathering crust and fractures in the basement rocks, which provide good reservoir conditions. Observation and analysis of buried hill configurations on seismic profiles reveal that buried hills with similar geneses have quite different configurations (Li et al. 2017). Some buried hills are large, with shallow top depth, and are overlain by Paleogene

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7 Geological Features of Hydrocarbon Reservoirs

strata. Some are small, with deep top depth and P Formation sediments from the early rifting overlying them (Lin et al. 2000). The structural scope of buried hills may directly reflect their structural configuration, while the strata overlying them may indirectly reflect the timing of their formation. Based on these two factors, the buried hills in the Bongor Basin can be classified into three types according to the ages of their overburdens. The first type is the early-stage buried hill. In the early Early Cretaceous, during a strongly extensional period of the rift valley, these buried hills were exposed on the water surface and overlapped by dark deep-lacustrine mudstone of the M Formation. Plays with ‘upper source rocks and lower reservoirs’ formed, offering abundant oil sources and short migration distances (Magoon 1991). This type of buried hill is the most favorable for forming large-scale oilfields. The Baobab C Buried Hill is a good example. The second type is the intermediate-stage buried hill. This type was still above the water surface during the period of strong extension in the Early Cretaceous and covered by the strata of the K Formation, or even later strata, during later rifting. The oil in this buried hill type mainly comes from lateral source rocks. Whether the buried hills contain oil depends on their development degree and the sealing ability of local K Formation mudstones and other strata. For instance, the lithology of the K Formation overlying the Cassia Buried Hill is primarily sandy mudstone, so exploration has been unsuccessful due to the lack of good-quality regional caprocks. On the other hand, the Mimosa E and Phoenix buried hills are located in depressions, and the overlying K Formation mudstones provide favourable caprocks, so commercial oilfields have been discovered there. The third type is the post-rifting buried hill. These remained exposed on the water surface after rifting came to a stop in the Early Cretaceous and were overlain by Upper Cretaceous or Paleogene strata. Low yield heavy oil has been discovered in buried hills of this type, for example, in the Ruman Structure in the Melut Basin, South Sudan (Awad 2015). In the Bongor Basin, some buried hills are covered by PaleogeneNeogene strata. In these basement rocks, for example, in the Daniela North Buried Hill, exploration drilling has found only bitumen and weak hydrocarbon (Mohamed et al. 1999). Reservoirs might have formed in the early stages of basin development and then been uplifted and eroded from the late Late Cretaceous to the Paleocene so that the caprocks eroded and the oil reservoir was exposed and destroyed. Early-Stage Buried Reservoir P Formation sandstone is widely developed in the early buried hills. The buried hill and P Formation sandstone combine to provide good reservoir conditions where underlying weathering crust is well developed. Whether the buried hills contain oil or not depends on whether the oil column height is greater than the thickness of the reservoir in the P Formation. For instance, the P Formation in the Daniela Field contains plenty of oil, but the oil bottom occurs in the P Formation sandstone, so the buried hills contain only water layers. This reservoir type is classified as a sandstone reservoir. The oil column height in the Lanea E Structure is much greater than the thickness of the P Formation sandstone. The petroleum system consists of the P

7.1 Hydrocarbon Reservoir Types

319

Formation and buried hills, which share the same oil–water contact (OWC) to form a combination reservoir. All the combination reservoirs must therefore be of this early type. The next section will discuss combining reservoirs consisting of P Formation strata and buried hills. The Baobab C Buried Hill is a typical early type. Its area is roughly 80 km2 . The main body of this buried hill is covered by hugely thick mudstones of the upper members of the P and M Formations. From SE to NW, the K and R Formations were gradually eroded due to the buried hill’s uplift. The overburden is very thin in the northwestern buried hill, only 300–400 m locally. The lithology of the P Formation is mainly dark mudstone. Thin sandstone has been encountered in the P Formation in some wells, mainly derived from subaqueous distributary channels Many different lithologies have been uncovered by drilling in the buried hills, but mostly migmatitic granite and some intermediate rocks and gneiss. Acid rocks tend to be found on the tops of buried hills, while migmatitic gneiss, intermediate rocks, and gneiss are layered in individual wells. Baobab C Buried Hill Oilfield The Baobab C Buried Hill formed in the up dip direction of a large NW-trending fault. The Baobab North Subdepression bounds to the northeast. In relief, it becomes lower and gradually disappears southwards, growing gradually higher towards the north and northwest. This buried hill intersects with a series of nearly EW-trending faults, forming multiple faulted blocks (Figs. 7.18 and 7.19). In January 2013, 37 m thick oil layers were interpreted in the buried hill interval in well Baobab C-1, and an oil test was conducted in the open well interval. Thick oil layers of 17 m were reinterpreted on re-examining the buried hill interval in well Baobab E-2. In the open hole test in that well, high production oil and gas flows were obtained in the buried hill interval, with open-flow production of 384.17 m3 oil/d and 29,988 m3 gas/d. This marked the discovery of the Baobab C Buried Hill reservoir and also confirmed that the Baobab and Baobab NE Oilfields are a single, giant, superimposed and connected oilfield. In the Baobab C Oilfield, all the faults in the buried hill are well-developed normal faults. This buried hill belt has identified a total of eighty-five faults of various sizes and large fault displacements. Twenty of the faults have a long-distance extensions. In the plane, the faults are divided into two sets, NW-trending and nearly EW-trending, with a large NW-trending fault in the northeastern buried hill, with large fault displacement and long extension, being the principal fault. This fault controls the formation and scale of the buried hill. The nearly EW-trending faults are of two types: N-dipping and S-dipping. The N-dipping faults are the main ones, with varying fault displacements and extensional distances, all of which control local subdepressions and play reconstructive roles in the structural configuration of the Baobab C Buried Hill. These faults connect with the NW-trending principal fault, and they all intersect the Baobab C Buried Hill, dividing it into faulted-block traps. The faults in the Baobab C Buried Hill have controlling roles in reservoir distribution and hydrocarbon accumulation (Fu 2001). Drilling has revealed that the lithology of the Baobab Buried Hill is 55% migmatitic granite, 13% gneiss, 12% acid rocks, and 12% intermediate rocks. The

320

7 Geological Features of Hydrocarbon Reservoirs 0 -10

0

0

2 km N

Baobab C 9 -1400

-800

-600

-1200

-1000

-800

-1000

0

-80

-1200

Baobab C 2 -80

0

-60

0

-400

Fault -1600

-1600

-1600

-2200

0

-1800

00

-1800

Baobab E 2

-12 0

0

Well location

Baobab C 5

-1800 -1800

-1800 -2000

Oil

-1200

-1800

-18

00 -22 -2300

00

-1200

-800

Baobab C-1

-1800

-1

-1400

-1400

-10 00

Baobab C 3 -1600

-1800 00

-16

-2000

-1400 -1600

-2400

-2200

-2000

-1800

-2400

Fig. 7.18 Top structural map of the Basement, the Baobab C Buried Hill Oilfield

0

Baobab C-9 Baobab C-2

Baobab C-5

Baobab C-1

Elevation m

-500

-1000

Baobab C-3 0

K

900m

M

P

-1500 Basement

Oil

Fault

Basement

Fig. 7.19 Cross-section through the Baobab C Buried Hill (for location see Fig. 7.18)

reservoir is a well-developed, good-quality reservoir with huge thickness, influenced by the reconstruction of the highly uplifted top of the buried hill by weathering and leaching. The reservoir is controlled from the top down by tectonic activity and is developed where fractures and dissolution occur. The buried hill interval uncovered by well Baobab C-2 is 1670 m long; the longest buried hill interval found so far. Weathering crust occurs in a depth interval of 536–640 m from the top of the buried hill. There is a fracture development belt at 640–1415 m, a semi-infill fracture development belt at 1415–1830 m and a tight belt below 1830 m. There are widespread fractures in the Baobab C Buried Hill, and reservoir quality is good. Electric logging in well Baobab C-2 has confirmed that the fractured oil layers have a maximum porosity of 18.07% (6.41% on average) and average permeability in the range 0.07–631.28 mD. The thickness of the reservoir with porosity higher than 3% is up to 350 m, of which the top 102.5 m is a thick reservoir with porosity higher

7.1 Hydrocarbon Reservoir Types

321

than 10%. Some exploration wells have encountered oil layers in thin sandstone in the P Formation, but their reserves are very low. Current drilling results suggest that the oil bottom of the Baobab C Buried Hill is over 1557 m deep. The density of the crude oil in well Baobab C-2, in the depth range 532–810 m, is 0.9539 g/cm3 , which is heavy oil. All the oil is light in other wells, with densities generally in the range of 0.8579–0.8907 g/cm3 (0.8429 g/cm3 on average). Viscosity ranges from 11.65 to 39.19 mPa s (30.4 mPa s on average). The condensation point is usually between 25 and 36 °C. Gas-oil ratios (GOR) are 2.47–78 m3 /m3 . The geothermal gradient in the oil layers is 44 °C/km. The pressure coefficient is 0.88– 1.04, indicating a normal pressure system. Phoenix S Oilfield The Phoenix S Buried Hill formed against a background of basement uplifting and developed as a complex faulted block controlled by NW-trending and N-dipping faults. Its main structure is cut by several NE- and nearly EW-trending faults. In the plane, the faults can be divided according to their strike: NW- and nearly EW-trending faults, and NE- and nearly SN-trending faults. NW-trending and nearly EW-trending faults dominate, controlling the structural formation and style. Two subsidiary faults with the same strike are developed alongside the main faults. Most of the NE- and nearly SN-trending faults are secondary transfer faults that play a reconstruction role in the structural configuration of the buried hill (Figs. 7.20 and 7.21). The total area of the Phoenix S Buried Hill structural trap is 33.2 km2 . Paleostructural reconstruction indicates that, before basin formation, the Phoenix Buried Hill was a paleo-geomorphologic mountain overlapped by P-M Formation sediments on

0

2km

Kubla 1

Paphia S 10 Phoenix S 3

Oil Fault Well location

Fig. 7.20 Structural map of the top basement, the Phoenix S Buried Hill Oilfield

322

7 Geological Features of Hydrocarbon Reservoirs Raphia S-10

S

N Oil 0

-500

375m Fault Basement

Elevation

m

K -1000 P

M

K P

-1500 M

Fig. 7.21 Cross-section through the Raphia S-10 Buried Hill (for location see Fig. 7.20)

its northern and southern sides and that its stereotype occurred at the end of the Early Cretaceous. In March 2013, the first exploration well, Phoenix S-3, was deployed. The top of the buried hill was encountered at a depth of 1033.5 m, and 56 m thick oil layers were interpreted by electric logging at 866.5 m into the Buried Hill. An open well test was conducted in the buried hill interval, obtaining converted open-flow oil production of 595 m3 /d. In well Raphia S-10, the depth of the top of the buried hill is 1557 m, and the buried hill interval is 336 m thick. Interpretation by electric logging identified 40 m thick oil layers. High production oil flow was obtained in an open hole test. These wells reveal that the lithology of the Phoenix X Buried Hill is 44% migmatitic granite, 20% migmatitic gneiss, 20% acid rocks, and 16% other metamorphic rocks (Xing 2006). Vertically, the reservoir is divided into weathering crust and a fracturing zone. In individual wells, identification of the fracturing zone is based on buried hill reservoir porosity and thickness in combination with oil test in the reservoir development intervals. Well-tie correlation diagrams show two fracture development zones in this buried hill, in the well section at 300 m below the top of the buried hill. This indicates that faulting and reconstruction impact the reservoir by weathering and leaching. Below the 300 m well section, the influence of these factors becomes weaker, and reservoir quality deteriorates. Oil test data and fracture development suggest that OWC in the Phoenix S Buried Hill must occurs below -1,450 m. At present, both of the tested wells do not produce water. Fractures occur in the Phoenix S Buried Hill, and according to electric logging interpretation, the maximum porosity of the fractured reservoir in well Phoenix S-3 is 9.11% (5.8% on average). The porosity of the oil layers is in the range of 3.71–9.11%, and permeability 0.12–11.17 mD (2.12 mD on average). There are two sets of fracture intervals in the buried hill. The first set is in the well section at 1037.09–1083.04 m, on the top

7.1 Hydrocarbon Reservoir Types

323

of the buried hill, and the second in the well section at 1132.25–1216.31 m. Average porosity is higher than 5%, indicating a type I reservoir. The combination of oil test and electric logging interpretation in wells Phoenix S3 and Raphia S-10 suggests that the buried hill reservoir in these wells has ‘stratoid’ features. Two sets of type I reservoir intervals (over 50 m thick) are developed vertically. Correlation between the two wells suggests that the fracture reservoirs have certain similarities laterally. There are multiple NE- and nearly EW-trending transfer faults, where the combination of stresses has led to well-developed fractures. The oil density is 0.8460–0.8815 g/cm3 . In-field degassed oil viscosity (50 °C) is 10.8–22 mPa s (Gong et al. 2003). The oil condensation point in the main pay is 29 °C, and the geothermal gradient is 45.1 °C /km, confirming a normal temperature reservoir. The pressure coefficient is in the range of 1.02–1.07, which is normal pressure. The GOR is 1–17.1 m3 /m3 . Intermediate-Stage Buried Reservoir The Mimosa E Buried Hill developed against a background of basement uplift and is controlled by complex faulted block structures formed by a WNW-trending, Ndipping fault system. An NW-trending and N-dipping fault in the early Early Cretaceous controlled sedimentation. This fault has a long extension with fault displacement up to 3600 m in the basement and a fault plane with a 53° dipping angle. An S-dipping fault developed later, which controlled the deposition of the overlying P and M Formations, with fault displacement of roughly 3000 m in the basement and a fault plane with a dipping angle of 68°. The main structure intersects the en echelon faults of an N-dipping main fault system, creating five highs. The shallowest burial depth at the top of the buried hill is 950 m, and the deepest is 2750 m, so the maximum drop height is around 1800 m. Several buried hills are formed within the area (Figs. 7.22 and 7.23). In Mimosa E Buried Hill, the total area of structural traps is 55 km2 . The buried hill directly overlies the K Formation sediments. In February 2013, the first exploration well, Mimosa E-1, was deployed in this buried hill. The depth of the top of the buried hill was found to be 1075 m, its thickness is 327.5 m, and 33.04 oil layers were interpreted by electric logging. Industrial oil flow was obtained in the buried hill interval in the open hole test. The fractured buried hill reservoirs are strongly heterogeneous and are better developed in the east than in the west. Two nearly EW-trending transfer faults, combined with stress, have caused relatively developed fractures in the east. Electric logging interpretation indicates that the interval with fracture development in well Mimosa E-1 is concentrated in the well section at 1075.6–1332 m and there is a type-II reservoir with a cumulative thickness of up to 33.04 m. In the west, the nearly EW-trending transfer faults that caused fracturing in the east of the buried hill are absent, so fractures are not developed. Electric logging interpretation indicates that the basement rocks in both wells Mimosa-9 and Mimosa W-2 have tight features. In electric logging interpretation of well Mimosa E-2, the maximum porosity of the fractured reservoir is 7.96% (average 4.81%), and oil layer porosity is in the range of 3.2–7.96%, and permeability 0.06–12.01 mD. There are two sets of favorable fractured intervals in the buried hill. The first is in the well section at 1075.59–1096.5 m

324

7 Geological Features of Hydrocarbon Reservoirs

Mimosa E 1 A

2km Mimosa E 3 1500

1800

15 00

Mimosa E 2 Oil

Fault

A′

Well location

Fig. 7.22 Structural map of the top buried hill, the Mimosa E Oilfield

Mimosa E-3

Mimosa E-1

A

Mimosa E-2 E

A′

B

-500

Elevation

m

R

-1000

-1500

K

Oil

Gas

Fault

Basement

Basement 0

1km

Fig. 7.23 Cross-section through the Mimosa E Oilfield (for location see Fig. 7.22)

on the top of the buried hill. The second is at 1313–1332 m. Average porosity is higher than 5%, confirming a type I reservoir. Oil test data and fracture development analysis suggest that OWC in the Mimosa E Buried Hill occurs at about -1,150 m. Oil density is 0.8458 g/cm3 . In-field degassed oil viscosity (50 °C) is 18 mPa s. The oil condensation point in the main pay is 33 °C. The geothermal gradient is 49 °C/km, representing a normal temperature reservoir. The pressure coefficient is 1.08, representing a normal pressure system. In-situ oil viscosity is 3.4 mPa s. The GOR is 31.1 m3 /m3 .

7.1 Hydrocarbon Reservoir Types

325

7.1.3 Combination Reservoir Traps controlled by a single factor are rare under natural geologic conditions. A combination of several factors controls most traps, and this is particularly so of continental rifting basins. Vertical superimposition of multiple reservoirs can generate diverse superimposed and connected traps. Buried hill traps are stratigraphic and can form combinations with structural traps in overlying sediments. The Xinglongtai Field, in the Liaohe subbasin in the Bohai Bay Basin, East China, is a typical combination trap reservoir (Xie et al. 2012). In the Bongor Basin, the crystalline basement rocks contain good reservoir space for the formation of buried hill traps against a background of warping and dipping faulted blocks. Overlying sedimentary rocks can drape them to form anticlinal traps, and later-stage compression and reversal can further enhance trap scope, ultimately generating combination traps. The M Formation and the upper member of the P Formation are great source rocks and act as regional vertical and lateral sealing rocks when adjacent reservoirs span faults. They can form excellent closure systems with the sandstones of the lower member of the P Formation and the reservoirs in the basement rocks (Dou et al. 2015). If P Formation sandstone directly overlies buried hills in basement rocks, sandstone and basement oil reservoirs have the same OWC and or similar oil quality, as, for example, in the Lanea E and Raphia S Oilfields. Sandstone interlayers in large sets of overlying mudstone caprocks can also become separate reservoirs, with different OWC and even various pressure systems from the buried hills oil reservoirs. Combination Reservoirs in Faulted Block-Buried Hills Most of the buried hills in the Bongor Basin are faulted block hills formed during the early stretching and extension of the basin. The age of their overlying strata is dependent on the timing of burial of the hills, the upper intervals of which are often overlain by sedimentary rocks of different geologic ages, forming various types of structural traps, for example, in the Lanea E and Phoenix Oilfields. Lanea E Field The Lanea E Buried Hill is located in the eastern section of the Northern Slope of the Bongor Basin. It is a complex faulted block structure developed on the uplifted basement, striking NW–SE, NW dipping as a whole, roughly 10 km long from east to west, and 4–5 km wide from north to south. A large fault on the northeastern side of the buried hill separates it from the high on the eastern side, and another fault on the southwestern side separates it from the Mango Depression on the southern side. NW-trending and ENE-trending faults occur in the buried hill as its burial depth increases from SE to NW. The minimum burial depth of the buried hill is 700 m, and at that point, it consists primarily of faulted block hills. The Lanea E Buried Hill can be divided into two: the Lanea E-2 Buried Hill on the northern side and the Lanea SE-1 Buried Hill on the southern side. The burial depths of the traps are shallow, with

326

7 Geological Features of Hydrocarbon Reservoirs

the highest point of the largest trap being at −400 m. The closure scope is relatively large, generally in 100–500 m (maximum 1000 m) (Figs. 7.24, 7.25 and 7.26). The P Formation structure overlying the Lanea E Buried Hill is also a complex faulted block, with a configuration consistent with the underlying buried hill. The Lanea E Structure is separated by a master and internal faults into four faulted blocks or faulted nose traps in the plane. Their high points and scopes are quite different, -90 -80

0

0

900

0

2km

Lanea E 2

800

Lanea E 4

Lanea E 3

0

70

70

0

Lanea SE 2 Lanea SE 1

90

0

600

Oil

Fault

Gas

Well location

Fig. 7.24 Structural map of the top of the buried hill in the Lanea E Oilfield

A

800m

0

300

400

500

Lanea E 1

600

A′ Lanea E-3

Lanea E 2

-5

Lanea E-4

00

Oil

Fig. 7.25 Structural map of the top P Formation, the Lanea E Oilfield

Fault

Well location

7.1 Hydrocarbon Reservoir Types Lanea E 1

A Oil 300

Water

Lanea E 4

Lanea E 2

A′ P P

1 3

P

P

2 4

Fault

m Elevation

327

Basement

600

900 P

4

Fig. 7.26 Cross-section through the Lanea E Oilfield (For location see Fig. 7.25)

and they include three favorable traps: the Lanea E-2 Faulted Block, the Lanea SE1 Faulted Nose, and the Lanea E-3 Faulted Block. The total trap area is 25 km2 . Well Lanea E-2 is targeted on the Lanea E Buried Hill Zone, with its main horizon of interest being the P Formation in addition to the basement rocks. The well was spudded-in on December 3, 2012. First, the production hole was drilled and cemented at 826 m after entering the buried hill in the basement rocks. Unbalanced drilling was completed in the basement rocks. Severe drilling fluid loss (309 m3 ) occurred in the fractured buried hill section. During drilling, the gas survey was included in mud logging. Buried hill 364 m thick was uncovered, with 80.57 m oil layers according to electric logging interpretation. In January 2013, an open hole test for oil was conducted in the buried hill interval at 834–1190 m, obtaining converted open-flow oil production of 495 m3 /d. This represented an important breakthrough in exploring buried hills in the Bongor Basin, Chad. Thick oil layers (60 m) were interpreted in the P Formation overlying the buried hill in the well, where high production oil flow was obtained during the test. Following this initial discovery, wells Lanea E-3, Lanea E-4, Lanea SE-1, and Lanea SE-2 were completed in rapid succession, all found to contain oil and gas. In the Lanea E Buried Hill, the rock types are mainly migmatitic granite (63%) and acid rocks (29%), with other lithologies occurring only rarely. The top of the buried hill has been widely reconstructed by weathering and leaching, forming a thick reservoir with good physical properties. At greater depths, the reservoir is controlled by tectonic movements and developed where dissolution has occurred. Vertically, it can be divided into two zones: a weathering crust zone and a fracturing zone. In well Lanea E-2, fractured oil layers, as interpreted by electric logging, have a maximum porosity of 25.25% (12.49% on average) and average permeability in the range 0.36– 765.06 mD. The average porosities and permeabilities of the oil layers confirm that there are two sets of well-developed fractured intervals in the buried hill. One on the top of the buried hill, at 824.27–888.05 m, and the other at 1028.86–1104.15 m. Both are type I reservoirs. Electric logging interpretation results from many wells indicate that the weathering crust on the top of the buried hill has ‘stratoid’ characteristics, so the Lanea E Buried Hill reservoir is apparently of stratoid type.

328

7 Geological Features of Hydrocarbon Reservoirs

In Well Lanea SE-1, individual gas top occurs due to the intersection of the well by faults. It is predicted that gas-oil contact (GOC) occurs at −525 m. In Block Lanea E-2, OWC occurs at the same depth in the P Formation and the buried hill, at −787 m. This implies that the OWC in these faulted blocks is the same. In the buried hill, the oil density is 0.8670 g/cm3 . In-field degassed oil viscosity (50 °C) is 20.8 mPa s. The oil condensation point in the main pay is 29 °C. The geothermal gradient is 53 °C/km, which signifies a normal temperature reservoir. The pressure coefficient is 1.03–1.10, which is a normal pressure system. The GOR is low. The formation water is NaHCO3 type with a salinity of 1076–1200 mg/L. Phoenix Field The Phoenix Field is controlled by a complex faulted nose structure formed by an NW-trending master fault. A later NE-trending fault intersected the structure, making it more complex. Warping and dipping towards the end of P Formation deposition caused the P Formation to erode in the northwest. Intense tectonic reversal at the end of the Late Cretaceous destroyed the structural configuration of the K Formation. The Phoenix-1 block is a faulted nose structure with its highest point at −850 m. The closure scope is 400 m, and the total trap area is 3.65 km2 . Well Phoenix-1 was completed in December 2010. An oil test was conducted in the well section at 1590.00–1626.50 m in the P Formation, producing large oil flows (Fig. 7.27). The main pay zone in the Phoenix Field are the Lower Cretaceous sandstone and the basement rocks. These can be subdivided into four oil layers: the basement rocks, the P Formation, the K Formation, and the R Formation. The R Formation reservoir is mostly in fine sandstone. It is well developed in Block Phoenix-3, up to 13 m thick with an average porosity of 15.1–27.2% and average permeability of 54–1872 mD, representing medium porosity and permeability. The K Formation reservoir contains mainly medium-fine sandstone, up to 31 m thick, with an

0 Phoenix1 B1 B

1

Phoenix 3

A Phoenix 1 B′ A′ Phoenix 4

Phoenix1 B2

Phoenix W 1 Phoenix 2

Oil

Kubla 1

Fault Well location

Fig. 7.27 Structural map of the top P Formation, the Phoenix Oilfield

Phoenix S 3 Phoenix S 3A

2km

7.1 Hydrocarbon Reservoir Types

329

average porosity of 15.4–25.4% and average permeability of 28–1678 mD, representing medium porosity and permeability. The lithology of the P Formation reservoir is mainly grey mudstone intercalated with fine-medium sandstone up to 34 m thick. It has average porosity (13.5–23.9%) and average permeability (196–3277 mD), representing medium porosity and medium–high permeability. The reservoir is composed of superimposed sediments in subaqueous distributary channels in a multi-stage fan delta front, and its quality tends to deteriorate with increasing burial depth gradually. In September 2017, Well Phoenix1-B1 was drilled in the high part of the buried hill. Good oil and gas shows were observed in the basement rocks, and 51.38 m oil layers were identified in the sandstone overlying the basement. The well entered the basement at a depth of 1324.5 m, uncovering 275.5 m of basement rocks, with electric logging confirming 90.44 m of oil layers. Open hole oil test obtained high-production oil flow from the basement rocks. In November 2017, good oil and gas shows were observed in the basement rocks in Well Phoenix 1-B2. This well entered the basement at 949.5 m, uncovering 350.5 m of basement rocks, including 38.4 m of oil layers confirmed by electric logging. Industrial oil flow was obtained by pumping in the buried hill interval, which confirmed that this is a combination oilfield (Figs. 7.27, 7.28, 7.29 and 7.30). In the Phoenix Field, the burial depth of the main pay zone, PI, is 1510–1660 m and both structure and the lithology control it. In-field degassed oil viscosity (50 °C) is 10–15 mPa s. The oil density is 0.8560–0.8438 g/cm3 . The condensation point varies from 15 to 33 °C. The geothermal gradient in this reservoir is 39–45 °C/km and the pressure coefficient is 0.97–1.15, indicating normal temperature and pressure systems. The basement rocks and P Formation reservoir is a layered, edge-water, lithologic-structural light oil reservoir. The K Formation reservoir is an unconventional oil reservoir with an oil density of 0.8417 g/cm3 . The R Formation reservoir is a heavy oil reservoir with an oil density of 0.9632 g/cm3 and an in-field degassed oil viscosity (50 °C) of 3239 mPa s.

1km

B

Phoenix1-B1 140 0 150

0

Phoenix-1

1600

1800

1700

Oil

Phoenix1-B2 B′ -10

1900

00 -1100 1200 1300

Fault Well location

160

0 150

0

Fig. 7.28 Structural map of the top basement, the Phoenix Oilfield

1400

330

7 Geological Features of Hydrocarbon Reservoirs Phoenix 1

A

Phoenix 4

A′

1100

Elevation

m

1200

1300

P1 1

1400

P12 P1 3

1500 Oil

P14

Fault

P1 5

Fig. 7.29 Cross-section through the P Formation, the Phoenix Oilfield (for location see Fig. 7.27) Phoenix 1 B2

Phoenix 1 B1

B

E

B′

R

400

K

K M

Elevation

m

K 800

K 1200 Oil Basement

M

1400

Fault Basement

Fig. 7.30 Cross-section through the Phoenix Oilfield (for location see Fig. 7.28)

Combination Reservoir in the Faulted Anticline-Buried Hill Three sets of faults occur in the structural zone of the Raphia S Buried Hill. The first set is nearly NW-trending. WNW-trending faults with a NE-dipping fault plane are the master faults in this area. Their displacement in the basement is roughly 1000 m but tends to decrease upwards. These master faults control the formation and distribution of the buried hill zone. The second set consists of nearly EW-trending faults with a N-dipping fault plane and short extension distance. Their displacement in the basement is about 400 m. They play a partitioning role in the buried hill zone. The third set consists of NE-SW-trending strike-slip transfer faults. This set of faults intersects the NW-trending faults, complicating the overall fault structure of the buried hill. The faults in this set play a vital role in fracture formation in the

7.1 Hydrocarbon Reservoir Types

331

2km

16 00 180

Raphia S 8 B1

0

Raphia S 8A

Raphia S 8

1000

Raphia S 3

120 0 0

00

12

100

Raphia S 11 Raphia S 10

1200 Oil Fault Well location

Raphia S 13 Raphia S 1 Raphia S 9 Raphia S 5 Raphia S 6

Raphia S 4

Fig. 7.31 Structural map of the top P Formation, the Raphia S Oilfield

buried hill. The three sets of faults divide the Raphia S Buried Hill into multiple faulted blocks (Fig. 7.31). In field in the Raphia S Buried Hill Oilfield, the source rocks in both the M and P formations are well-developed and mature. Oil and gas generally migrate laterally, with ‘generation in upper interval and storage in the lower interval’. These source rocks provide sufficient oil for the P Formation sandstone and the buried hill structure. The main pay zones in the Raphia S Field are in the P Formation, the buried hills, and the M, K, and R formations (Figs. 7.31, 7.32 and 7.33). In the P Formation, average porosity is 15.1–32.4%, and average permeability 380–9497 mD, representing medium porosity and high permeability. In the M Formation, the oil layers are mainly thin-layered fine sandstone with average porosity of 15.6–26.1% and average permeability of 346–5898 mD, representing medium porosity and high permeability. In the K Formation, the porosity of the oil layers is 18.5–24.5% and permeability 768–4878 mD, signifying medium porosity and high permeability. Well Raphia S-8 encountered 8.3 m oil layers in the M Formation in the well section at 912–964.3 m, and 154.6 m oil layers in the P Formation in the well section at 1168.8–1360.1 m. High production of light oil was obtained in the oil test at 1168.86–1223.05 m and 1349.66–1359.66 m. Good oil and gas shows were also observed in the basement rocks. Appraisal well Raphia S-8B1 penetrated 37.8 m oil layers in the P Formation and 196 m in the basement rocks. High production oil flow was obtained in individual open hole tests in the basement rocks, which tends to suggest that the reservoir in the P Formation sandstone coincides with the oil bottom in the buried hill oil reservoir at a depth of 1142 m (Fig. 7.33). In well Raphia S-11, the burial depth of the top of the buried hill is 1406 and 274 m thick. There are 48.38 m oil layers according to a sectional test by electric logging. In the open hole test, converted formation water production was 216 m3 /d in the well section at 1515.10–1602.89 m, and high production oil flow (with oil density of 0.8473 g/cm3 ) was obtained in the open hole test in the well section at 1412.00– 1474.87 m. Fractures are reasonably well developed in the Raphia S Buried Hill,

332

7 Geological Features of Hydrocarbon Reservoirs 2km -1700

Oil

-1700

Raphia S 8 B1 Raphia S-8A A Raphia S 8 Raphia S 8A

-270

0

Fault Well location -17 00

Raphia S 3

00

-17

A′ Raphia S 11 Raphia S-10

Raphia S 13 -17

Raphia S 1

00

-1700

Raphia S 9 -1700

Raphia S 5 Raphia S 6

-1700

Fig. 7.32 Structural map of the top buried hill in the Raphia S Oilfield

A

Raphia S 8A Raphia S 8 B1

Raphia S 11

Raphia S 8

0

R

A′ 800m

500

Elevation

m

K

1000

M

Oil

P 1500

Basement

Fault Basement

Fig. 7.33 Cross-section through the Raphia S Oilfield (for location seeing Fig. 7.32)

and the reservoir has favourable physical properties. The drilling results demonstrate that the fractured reservoir in the buried hill is weakly heterogeneous. The oil layers show small lateral variations up to 100 m thick. OWC occurs at −1144.5 m, with the P Formation sandstone and the buried hill sharing OWC (Fig. 7.33). All the oil reservoirs in the Raphia S Field are unsaturated reservoirs with marked differences between reservoir pressures and saturation pressures (light oil, 381– 1854 ψ). The volume coefficient is 1.024–1.132, with low GORs of 3.6–36.1 m3 /m3 . In-situ oil viscosity in both the PI and MII layers is in the range 2.6–32.0 mPa s, and the oil is conventional light oil. In Block Raphia-1, in-situ oil viscosity in the KIV layer is 231.3 mPa s, and the oil is conventional heavy oil. In Block Raphia S-1, insitu oil viscosity in the K Formation is 3.5 mPa s, and the oil is conventional light oil.

7.2 Hydrocarbon Accumulation Periods

333

In the Main Block, Raphia S-8, in the main layer, PI, of the P Formation, saturation pressure is 624 ψ, in-situ oil viscosity is 5.0 mPa s, and oil density is 0.8458 g/cm3 . In other layers, density is in the range 0.9632–0.8423 g/cm3 , the condensation point is 30 °C (within the range 27–38 °C), and the initial GOR is 19 m3 /m3 . In the buried hill oil reservoir, the oil density is 0.8484 g/cm3 , the in-field degassed oil viscosity (50 °C) is 10.4 mPa s, and the condensation point is 10.4 °C. Generally, in the PI Formation in the oilfield group, the geothermal gradient is 37–49 °C/km and the pressure coefficient 0.98–1.08, confirming normal temperature and pressure systems. The formation water is type NaHCO3 .

7.2 Hydrocarbon Accumulation Periods The timing of hydrocarbon accumulation correlates strongly with trap formation and hydrocarbon generation and charging, as well as regional tectonic movements (Burke et al. 2003). The dynamics and timings of hydrocarbon accumulation in basins are considered important targets for basin modeling (Tissot et al. 1987). Therefore, the study of hydrocarbon generation has great significance for evaluating plays and selecting exploration targets in petroliferous basins, contributing materially to improving the success rate of oil and gas exploration projects (Chapman 2000). Since the 1940s, determining the timing of hydrocarbon accumulation relied on indirect geological and geochemical methods (Carlson et al. 1999). However, this yields only approximate timings and the earliest possible charging times (Leverson and Berry 1967). Since the 1970s, the development of high-precision instruments and the move towards multi-disciplinary research has led to new isotopic dating techniques in ore deposit geology such as K–Ar and Ar–Ar dating, which are commonly conducted on authigenic illite fillings in sandstone pores to much more accurately date hydrocarbon charging (Carlson 1990). In the 1980s, researchers began to investigate the heterogeneity of hydrocarbon reservoirs using a combination of fine organic geochemical analysis and the timings of hydrocarbon accumulation (Cederbom et al. 2000). Hydrocarbon charging and mixing directions are also examined to establish dynamic hydrocarbon charging models, which assist in identifying favorable blocks and traps (England et al. 1987). Now, apatite fission track analysis provides a reliable means for accurately reconstructing structural burial and thermal histories (Laslett et al. 1982, 1987; Green et al. 1986). Since the 1990s, researchers have used the homogenization temperatures of inclusions in authigenic minerals (authigenic quartz, authigenic albite, and authigenic K-feldspar) in conjunction with an examination of thermal and burial histories to geochemically analyze oil charging periods and hydrocarbon sources of reservoirs (Nedkvitne et al. 1993; Karlsen et al. 1993). Most of the oil and gas in Central Africa is in the Lower Cretaceous, Upper Cretaceous, and Paleogene, and there has been considerable debate about the hydrocarbon accumulation periods in the region (Crowhurst et al. 2002). It has been suggested that the main hydrocarbon accumulation period was in the late Early Cretaceous, with the Bongor Basin cited as an example (Dou et al. 2011). It has alternatively been proposed that the late Late Cretaceous was the main accumulation period, based on

334

7 Geological Features of Hydrocarbon Reservoirs

0

20km

Slope Uplift

Oil Baobab C 2

Fault Ronier 4

Baobab C 2

Drilled well Structural trap

Baobab N 8

Baobab NE 1 Baobab S 1 Mimosa 4 Mimosa NE 1 Phoenix 3

Raphia S 8A Raphia S 3

Lanea SE 2

Fig. 7.34 Distribution of typical oilfields in the northern slope of the Bongor Basin

the example of the Fula subbasin in the Muglad Basin, where hydrocarbon accumulated in the middle and late Late Cretaceous, with some adjustments occurring even later (Zhang 2004). The Nugara subbasin in the Muglad Basin experienced hydrocarbon accumulation in the middle and late Late Cretaceous, with adjustment occurring in the Paleogene-Neogene (Zhang 2004). The Sufyan subbasin of the Muglad Basin generated and expelled large amounts of hydrocarbons and formed reservoirs at the end of the Late Cretaceous (Zhang 2004). In contrast, hydrocarbons in the Melut Basin mostly accumulated during the Paleogene (Dou 2005; Tong et al. 2006). In the absence of suitable experimental and technical methods for determining hydrocarbon accumulation periods, previous studies have generally approximated the accumulation histories of Central African reservoirs based on understandings of regional geology, tectonic histories, and the hydrocarbon generation and expulsion histories of source rocks. We used apatite fission track analysis (as described in Chap. 3) to analyze authigenic inclusions in sandstone and basement rock fractures of the oilfields on the northern slope of Bongor Basin to determine their hydrocarbon accumulation periods and oil and gas charging histories (Fig. 7.34) (Duddy et al.1988).

7.2.1 Inclusion Analysis Occurrence Characteristics of Inclusions Knowledge of inclusion petrography and homogenization temperatures and compositions helps to distinguish the formation of primary inclusions in authigenic minerals, the formation sequences of secondary overgrowth boundary in minerals, and the

7.2 Hydrocarbon Accumulation Periods

335

intersections of mineral fracture zones (Womenka B 1990). The northern slope of the Bongor Basin contains authigenic minerals such as quartz overgrowth in sandstone and authigenic calcite and quartz in basement rock fractures (Sun et al. 1998). Sandstone inclusions are found in enlarged rims and microfractures in four wells in the Ronier, Mimosa, Baobab N, and Baobab S oil reservoirs, dominated by yellow fluorescent group inclusions, with other types of fluorescence occurring locally. This indicates that the main sandstone oil reservoir on the northern slope experienced a single continuous episode of hydrocarbon accumulation, although some areas had multi-stage charging events (Fig. 7.35). There are two stages of inclusions in fissure filling in the basement rock buried hills. The first phase inclusions mostly occur in microfractures or quartz veins that crosscut quartz and its enlarged rims or in early calcite minerals and veins. They are distributed in groups or zones including oil inclusions, reddish-brown heavy oil inclusions, dark brown oil and gas inclusions, and dark gray gas inclusions. The second phase inclusions occur in quartz enlargement rims, along microfractures intersecting quartz and quartz enlargement, and in feldspar dissolution pores, or are observed in sparry calcite filling or feldspar dissolution pores in later fractures. They are distributed in groups or zones, including light brown oil inclusions, dark brown oil and gas inclusions, and dark gray gas inclusions, suggesting more than one hydrocarbon fluid migration and accumulation event (Fig. 7.36). Fluid Inclusion Composition We analyzed hydrocarbon inclusions from different buried hill zones in the Bongor Basin using Fourier transform infrared spectroscopy (FT-IR). The ratio of methylene to methyl is expressed as CH2 /CH3 . Xinc is the number of alkyl carbon atoms in organic matter, and Xstd is the number of straight-chain carbon atoms in organic nalkanes (Lu et al. 2004). As the maturity of oils evolves, CH2 /CH3 , Xinc, Xstd, and other parameters gradually decrease predictably, providing a scale for determining the maturity of oil and gas and differences in oil types (Table 7.1) (Xu et al. 1996). The inclusions in the Baobab C buried hill reservoir show two types of fluorescence. The first is orange fluorescence. Oil inclusions with orange fluorescence have CH2 /CH3 values of 9.93–18.84 and Xinc and Xstd ranging between 90.32–200.42 and 33.44–70.14, respectively, which indicate relatively low maturity. The second type is yellowish green fluorescence. Oil inclusions with this type of fluorescence have CH2 /CH3 , Xinc, and Xstd values of 1.89–6.78, 12.12–70.92, and 7.37–28.64, respectively relatively rich methyl, relatively short hydrocarbon chains, and relatively high maturity (Table 7.1). We applied this correlation between fluorescence and maturity to further analyze oil and gas maturity in the Baobab C buried hill (Fig. 7.37). The yellowish green fluorescence of the oil in the Baobab buried hill reservoir represents phase-I mature crude oil. The proportion of yellowish green fluorescent samples suggests that mature crude oil accounts for about 70%, with the remaining 30% being relatively low mature crude oil, represented by an orange fluorescence. We preliminarily infer from infrared spectrum parameters that the buried hill reservoir in well Baobab C-2 experienced

336

7 Geological Features of Hydrocarbon Reservoirs

(a) Inclusion groups in quartz grains, well Mimosa 4 -1, 1187.56 m

(b) Yellow fluorescent oil inclusions observed in cracks of quartz grains, well Mimosa 4 -1, 1187.56 m

(c) Secondary inclusions in quartz grains, well Ronier 4 -1, 1521.00 m

(d) Bright yellow fluorescence of quartz, well Ronier 4 -1, 1521.00 m

(e) Inclusion in quartz fractures, well Baobab N-8, 1394.54 m

(f) Bright yellow fluorescence in quartz fractures, well Baobab N-8, 1394.54 m

(g) Inclusion group in quartz grain fractures, well Baobab S1- 1, 1523.00 m

(h) Inclusions in quartz grain fractures, with yellow fluorescence, well Baobab S1- 1, 1523.00 m

Fig. 7.35 Occurrence and fluorescence characteristics of inclusions in sandstones

7.2 Hydrocarbon Accumulation Periods

Oil inclusions in quartz veins, dark brown, plane-polarized light,×100

337

Intergranular pores, plane-polarized light, ×100

Yellowish green fluorescence, plane-polarized light, ×100

(a) Well Baobab C- 2, 534.50m

Oil inclusions in feldspar dissolved pores, nearly colorless, ×630

Yellowish green fluorescence, ×630

(b)Well Raphia S- 8A, 1571.46 m

Gas inclusions in quartz phenocrysts, primary inclusions, ×630 (c) Well Raphia S-8A, 1573.80 m

Gas and brine inclusions in calcite veins, grayish Gas and brine inclusions in calcite veins, grayish Gas and brine inclusions in calcite veins, grayish black, plane-polarized light, ×100 black, crossed polarized light, ×100 black, plane-polarized light, ×630 (d)Well Baobab C -2, 1792.80 m

Oil inclusions and brine inclusions in microcracks intersecting quartz and its enlarged rims, orange fluorescence, ×400 (e)Well Baobab C -2, 534.50 m

Oil inclusion group in microcracks crosscutting quartz and its enlarged rims, yellowish green fluorescence, ×630 (f) Well Raphia S- 8A, 1573.18 m

Fig. 7.36 Occurrence of inclusions in buried hills

two episodes of oil and gas charging. Therefore, the oil and gas properties are not completely consistent. The inclusions in the Mimosa-Phoenix buried hill oil accumulation generally emit green and yellowish green to green fluorescence, with a small amount of dark brown fluorescence in some wells (Table 7.2). The inclusions emitting yellowish green to green fluorescence have significantly lower values for CH2 /CH3 , Xinc, and Xstd than those emitting dark brown fluorescence.

338

7 Geological Features of Hydrocarbon Reservoirs

Table 7.1 Fluorescence characteristics of inclusions in the buried hill reservoir in well Baobab C-2 Depth(m)

534.50

Inclusions emitting orange fluorescence

Inclusions emitting yellow-green fluorescence

CH2 /CH3

Xinc

Xstd

Sample number

CH2 /CH3

Xinc

Xstd

Sample number

9.96

101.80

37.27

7

1.89

12.12

7.37

1

534.70

15.09

158.74

56.25

7

6.63

70.92

28.64

8

536.10

16.04

169.26

59.75

4

6.11

59.00

23.00

5

548.50

14.54

152.00

54.00

1

5.25

47.22

19.07

6

549.50

13.05

136.14

50.71

1

5.81

55.61

21.87

14

785.50

18.84

200.42

70.14

1

6.78

66.41

25.47

5

1106.09

9.93

90.32

33.44

2

5.77

44.04

18.01

3

1107.15

5.36

50.72

20.24

11

1107.34

5.50

52.19

20.73

4

Fig. 7.37 Comparison of fluorescence parameters of inclusions in the Baobab C buried hill

Similarly, the hydrocarbon maturity of inclusions correlates to their fluorescence (Fig. 7.38). Most inclusions emitting green to yellowish green fluorescence are in the range of mature crude oil. Some wells, such as Mimosa E-2, contain high-mature oil. The inclusions emitting dark brown fluorescence is of consistently low maturity. They are using sample numbers to calculate the proportion of fluorescence, yellowish green to green fluorescence accounting for about 90% of the samples, while dark brown fluorescence constitutes only about 10%. This suggests that the oil in the Mimosa-Phoenix buried hill is predominantly mature. Fluorescence parameters reveal that the Baobab C buried hill oil reservoir contains two types of oil and gas. In contrast, the Mimosa-Phoenix buried hill oil reservoir contains predominantly mature crude oil, with two types of oil and gas found only in some areas. In general, the maturity of the oils in the northern slope increases in a southward direction. The Baobab C buried hill oil reservoir has the lowest crude oil maturity, followed by the Mimosa-Phoenix and Raphia S oil reservoirs. The crude oil in the Mimosa-Phoenix reservoir is more mature than the Raphia S oil reservoir. Dou et al. (2011) suggested that oil and gas in the Bongor Basin generally migrated locally and did not undergo long-distance migration and charging. Planar diagrams

Mimosa-9

Mimosa-10

Mimosa E-2

Raphia SW-2

6.12

1072.14

7.29

5.62

1070.81

1644.50

4.53 5.24

1758.20

1068.49

3.77

1757.50

5.70 5.73

993.45

1757.25

5.50

993.24

5.77 4.50

1577.30

992.72

6.50

1575.50

9.68 5.41

1

6.50 6.20

1573.80

63.36

1 7

1574.20

180.07

41.78 49.41

6.00

5.00

17.01

115.33 138.22

Sample number 4

1573.18

13.24

11.18

1571.46

1645.70

Raphia S-8A

Xstd 43.72

72.13

59.09

53.60

49.32

41.44

33.00

54.77

44.90

35.47

29.62

55.21

63.29

51.17

98.70

40.14

59.97

45.70

52.56

Xinc

CH2 /CH3

Xinc 121.16

CH2 /CH3

11.70

1644.06

Phoenix S-3

Yellowish green to green

Dark brown

Depth(m)

Well

Table 7.2 Fluorescence characteristics of inclusions in the Mimosa-Phoenix S buried hill reservoir Xstd

27.38

25.00

23.00

22.00

17.15

14.34

21.59

18.30

15.16

13.21

21.74

24.43

20.39

36.23

16.71

23.32

18.57

20.85

Sample number

6

9

5

9

6

8

2

14

22

11

29

9

9

6

17

17

6

11

7.2 Hydrocarbon Accumulation Periods 339

340

7 Geological Features of Hydrocarbon Reservoirs

Fig. 7.38 Comparison of fluorescence parameters of inclusions in the Mimosa-Phoenix S buried hills

and profiles indicate that the crude oil in every buried hill oil reservoir came from adjacent depressions. In particular, the Baobab buried hill oil reservoir was supplied from two depressions, slightly different from the other buried hill oil reservoirs. Thus, it is preliminarily considered that the crude oil in the Baobab C buried hill is sourced from source rocks in the two adjacent subdepressions and has two types of inclusions. It may therefore have experienced two episodes of oil and gas charging. The crude oil in the Mimosa-Phoenix buried hill comes from the North Mimosa Subdepression. Analysis of hydrocarbon inclusions indicates that the Mimosa-Phoenix buried hill generally contains mature oil and gas, with two types of oil and gas found locally in some areas, suggesting a single hydrocarbon accumulation event. Homogenization Temperature Characteristics of Inclusions Homogenization Temperature Characteristics of Inclusions in Sandstone Reservoirs Oil and gas inclusions in the Ronier oil reservoir in well Ronier 4-1 mostly occur in secondary microcracks of quartz grains, with yellowish green fluorescence and occasional yellow fluorescence. The associated brine inclusions generally have homogenization temperatures of 65–135 °C, with a peak at 115–125 °C, which also represents the peak of charging (Fig. 7.39a). The inclusions in the Mimosa oil reservoir

7.2 Hydrocarbon Accumulation Periods

341

in well Mimosa 4-1 are mostly in secondary microfractures in quartz grains, generally with yellow fluorescence. The associated brine inclusions have homogenization temperatures of 75–135 °C, with the main temperature/charging peak at 75–85 °C (Fig. 7.39b). Sandstone inclusions in the Baobab S oil reservoir in well Baobab S1-1 are mostly in secondary microcracks in quartz grains, showing yellow fluorescence. The homogenization temperature range of the associated brine inclusions is between 75 and 145 °C, with the temperature/charging peak at 85 and 105 °C (Fig. 7.39c) (Gallager 1995). The inclusions in the Baobab N oil reservoir in well Baobab N-8 are in secondary microfractures in quartz grains, with generally yellow fluorescence, although a few inclusions show yellowish brown fluorescence. The temperatures of the associated brine inclusions are between 65 and 135 °C. However, in this case, there are two main temperature/charging peaks, at 75–85 °C and 115–135 °C, which suggests that the Baobab N oil reservoir experienced two oil and gas charging events (Fig. 7.39d). Homogenization Temperature Characteristics of Inclusions in Buried Hill Oil Reservoirs We investigated the inclusions in the basement rocks by taking samples from around the Baobab, Mimosa-Phoenix, Cassia, and Lanea buried hills. Overall Distribution of Homogenization Temperatures The Baobab C buried hill oil reservoir contains mostly secondary inclusions in microfractures that crosscut quartz and secondary overgrowth boundary of quartz. We conducted microscopic observation and analysis of the hydrocarbon-bearing brine

Fig. 7.39 Homogenization temperature histograms of brine inclusions in four wells

342

7 Geological Features of Hydrocarbon Reservoirs

inclusions and their associated oil and gas inclusions (Smith et al. 1985). In general, we found that the secondary inclusions had formed later than the primary crystal minerals, a result of transformation events that altered the fluid environment, structural characteristics, and physicochemical conditions in the reservoir and affected the late-forming crystal minerals. Homogenization temperature histograms of the secondary inclusions in the Baobab C oil reservoir reveal that the temperature of the hydrocarbon-bearing brine inclusions is between 75 and 135 °C. Analysis of sixteen samples of basement rock from five wells in the Mimosa-Phoenix buried hill oil reservoir shows that the primary inclusions occur in late calcite, with the secondary inclusions mostly in microcracks in quartz veins secondary overgrowth boundary of quartz, feldspar dissolution pores, and siliceous quartz-healed fractures. Homogenization temperature histograms give the salinity values (wt% NaCl) of two hydrocarbon-bearing brine inclusions in well Mimosa E-2 as 6.71 and 6.88%. This indicates that the oil and gas in the different media were trapped simultaneously, which is suggestive of long-term oil and gas charging. Well Mimosa-10 has a temperature range of 75–86 °C and more developed gas inclusions than other wells, implying a various material compositions and environments from other wells during or after inclusion formation. Our other samples were mostly hydrocarbon-bearing brine inclusions associated with oil inclusions, with homogenization temperatures ranging from 95 to 125 °C. Wells Cassia-2 and Lanea SE-1 contain mostly primary inclusions in calcite veins, coeval with mineral formation. Their homogenization temperatures are relatively high, and few data points suggest secondary inclusions were found in the tested samples (Fig. 7.40). Homogenization Temperature Characteristics of Inclusions in Key Wells The Baobab C buried hill oil reservoir samples were mainly taken from well Baobab C-2. The hydrocarbon-bearing brine inclusions in this well can be divided into two phases based on mineral sequences. The first phase inclusions occur in authigenic minerals in quartz veins and secondary overgrowth boundary of quartz, and the second phase inclusions are hosted in structural cracks that crosscut quartz and secondary overgrowth boundary of quartz. The homogenization temperatures of the first phase inclusions show only a single temperature peak, at 115–120 °C. In contrast, those of the second phase show two discontinuous temperature peaks, at 125–130 °C and 85–90 °C, with the former predominating (Fig. 7.41a). Overall, the high-temperature sections of phase I and II inclusions have bimodal, continuous distributions, with the peak temperatures of the authigenic minerals being lower than those of the structural cracks. However, a low peak temperature range of 85–90 °C is evident in phase I in structural cracks, and authigenic minerals are continuously distributed in the middle and low-temperature sections with no temperature peak. This disparity suggests that the structural cracks’ low and medium peak temperatures may represent a separate and relatively independent hydrocarbon accumulation event.

7.2 Hydrocarbon Accumulation Periods

343

25

14 12

20 Frequenc

Frequenc

10 15 10

8 6 4

5

2

0

Homogenization temperature

Homogenization temperature

20

20

165 156

155

145 136

146 135 126

135

125

126

115

125

135

106

116

126

155 146

105

145 136

96

135 126

95

125 116

Homogenization temperature

86

115

96

106

0

105

5

0

85

10

5

76

10

15

75

15

65

Frequenc

25

(g) Phoenix S-3

116

(f) Mimosa-9

25

95

135

Homogenization temperature

(e) Mimosa E-2

86

125

115 106

105 96

155 146

95

145 136

10 9 8 7 6 5 4 3 2 1 0 86

135 126

Frequenc 125

115 106

116

105 96

95 86

116

(d) Mimosa-10

45 40 35 30 25 20 15 10 5 0

85

115

Homogenization temperature

(c) LaneaSE-2

76

106

105

165 156

Homogenization temperature

96

155 146

95

145 136

126

116

135

125

0

86

2

85

4

76

6

75

8

8 7 6 5 4 3 2 1 0 65

Frequenc

10 Frequenc

126

115

(b) Cassia-2

12

Frequenc

125

106

Homogenization temperature

(a) Baobab C-2

Frequenc

116

105 96

145 136

85

135 126

95

125 116

76

115 106

86

105 96

95

85 76

86

75 65

0

Homogenization temperature (h) Raphia SW-2

Fig. 7.40 General characteristics of homogenization temperature of inclusions

344

7 Geological Features of Hydrocarbon Reservoirs 40

8

Quartz vein and quartz enlarged rims

6

Microcracks intersecting quartz and its enlarged rims

35 Frequency

4

30 25

Microcracks without intersecting quartz healing cracks Quartz siliceous healing cracks

20 15 10

2

5

0 12

11 5 11 5

11 0

5 0

10 5

10

0 10

95

10

95

5 13

13 0 13 0

12 5 0

5

12

12

12 0

11 5 11 5

11 0 5

10

11 0

10 5

0 10 0

10

95 95

90 90

85

11 0

0

0

90

Frequency

10

Fig. 7.41 Homogenization temperature distribution of inclusions in buried hill reservoirs

The wells used for inclusion analysis in the Mimosa-Phoenix buried hill zone are scattered. Most of them fall within a narrow range of homogenization temperatures and exhibit single peak or continuous bimodal distribution (Fig. 7.40). Well Raphia S-8A was selected as the most representative well for analyzing oil and gas charging periods in the Mimosa buried hill. The inclusions in well Raphia S-8A can be divided into two stages according to their mineral sequences: microcracks that do not cut through quartz-healed fractures and siliceous quartz-healed fractures. The inclusions in siliceous quartz-healed fractures formed slightly later than the microcracks that do not cut through quartz-healed fractures. Homogenization temperature diagrams show a normal distribution (Fig. 7.41b). The peak temperatures of the two types of inclusions are continuous, which may be evidence of continuous charging, with the temperature peak of each type also representing the charging peak.

7.2.2 Hydrocarbon Generation and Expulsion Time of Source Rocks Hydrocarbon Generation and Expulsion History Burial and thermal histories determine source rocks’ hydrocarbon generation and expulsion histories and their corresponding hydrocarbon fluid activity histories (Barker 2000). In light of the extensive tectonic erosion in the Bongor Basin, the vitrinite reflectance constraint correction method was used to simulate the stratigraphic burial histories and thermal histories of the Baobab North and Mimosa North subdepressions (Bray et al. 1992). Well Mimosa NE-1 in the Mimosa North Subdepression and well Baobab NE-1 in the Baobab North Subdepression were selected for the reconstruction of hydrocarbon generation and expulsion histories using Petromod software. The simulations suggest that the primary source rocks of the M-P formations began to generate hydrocarbon at the end of the Early Cretaceous (Ro = 0.5%) (Burnham 1989). Driven by thermal evolution and affected by thermogenic events, the peak of hydrocarbon generation and expulsion was reached at the end of the Late Cretaceous. Hydrocarbon generation then gradually halted under the influence of

7.2 Hydrocarbon Accumulation Periods Cretaceous

0

Paleogene

Neogene

Cretaceous

0

Cz B Fm. R Fm.

Paleogene

Neogene Cz R Fm. K Fm.

M Fm. 0.4% P Fm.

2.0

Depth (km)

K Fm.

1.0 Depth (km)

345

1.0 M Fm. 0.4% P Fm. 2.0

0.6%

3.0

0.6% 0.8%

0.8%

1.0% 120

100

80

3.0 60 Age (Ma)

(a) Mimosa NE 1

40

20

0

120

100

80

60 Age (Ma)

40

20

0

(b) Baobab NE 1

Fig. 7.42 Burial and thermal evolution histories of the Baobab North and Mimosa North sags

tectonic uplift (Fig. 7.42). The M-P formations source rocks have remained in the same state since the end of the Late Cretaceous (Green et al. 1995). The thermal evolution of the source rocks in the Mimosa North and Baobab subdepressions reveals that they entered hydrocarbon generation at about 105 Ma (Ro = 0.5%; Fig. 7.43). However, they were not coeval in reaching their hydrocarbon expulsion thresholds. The Mimosa N Subdepression entered the generation stage earlier than the Baobab N Subdepression and has a higher degree of thermal evolution. The Mimosa N Subdepression source rock reached the hydrocarbon expulsion stage (Ro = 0.6%) at about 95 Ma when hydrocarbons began to migrate to the Mimosa-Phoenix and Baobab C buried hills. The source rock of the Baobab N Subdepression began hydrocarbon expulsion much later (at about 85 Ma, Ro = 0.6%), with the hydrocarbons migrating to the Baobab C buried hill. At the end of the Late Cretaceous, both subdepressions reached their maximum thermal evolution degree, with the Ro of well Mimosa NE-1 being 1.0% and that of well Baobab NE-1 at 0.8%. The thermal evolution degree of the Mimosa N Subdepression was higher than that of the Baobab N Subdepression. Hydrocarbon Accumulation Periods from Inclusion Analysis Hydrocarbon Accumulation Period of Buried Hill Oil Reservoirs Apatite fission track analysis of wells Baobab SE-3 and Raphia S-8A indicates similar Meso-Cenozoic tectonic thermal evolution histories, represented by ‘three drops and two increases’ (Fig. 7.44) (Barbarand et al. 2003). Burial and heating in the early Early Cretaceous (about 132–124 Ma) and the middle of the Early Cretaceous– end of the Late Cretaceous (about 124–65 Ma) reveal a continuous annealing stage on AFTA (Crowley et al. 1991; Crowley 1993). The burial history diagram shows that the basement was buried by sedimentation for a long time, during a period of tectonic geothermal history dominated by burial heating, and reached a heat flow peak with a paleogeothermal gradient of 30 °C/km (Gong et al. 2008). At this time,

346

7 Geological Features of Hydrocarbon Reservoirs

Fig. 7.43 Thermal maturity history of source rocks in wells Baobab NE-1 and Mimosa NE-1

large quantities of hydrocarbons were generated and expelled from the source rocks, representing the main hydrocarbon generation stage. Tectonic uplifting and cooling continued from the end of the Late Cretaceous to the Paleogene (about 75–40 Ma), resulting in denudation with a thickness greater than 1500 m (O’Sullivan 1998). From the end of the Paleogene to the early Neogene (about 40–20 Ma), the basin entered a stage of transient tectonic subsidence and sedimentary burial (20–5 Ma), with temperatures consistently within the annealing zone (60–120 °C). In the Neogene, the basin entered a rapid uplift and denudation phase, followed by a subsidence phase (5 Ma to the present). It is considered that the Baobab C buried hill oil reservoir was supplied from two hydrocarbon sources: the Mimosa N Subdepression at ~80 Ma, and both the Mimosa North and Baobab N subdepressions at ~70 Ma. The Mimosa Phoenix buried hill began to receive crude oil from the Mimosa N Subdepression at ~80 Ma, which continued until the end of the Late Cretaceous.

0.6 % % 0.8 Ro

60 70

N

Basement

Tight basement rock zone

P Fm.

100

Basement

110

0

0

20

0

Cz R Fm.

50 K Fm.

70

M Fm.

80 Basement

90

130

14 (a) Baobab C 2

40

N

120

150 60 Age (Ma)

E

110

130

10

80

K

100

120

12 100

J

60

90

160 120

40

M Fm.

140

3.5

30

R Fm.

80

0

3.0

E N

K Fm.

70

2.0

80

E

60

Fracture cavity development zone

Semi filling zone

90

K

50

Weathering leaching zone

1.5

2.5

J

40

M Fm. P Fm.

o

0.7 %

0.5% 1.0 Depth (km)

30 Cz

R

50

Ro

Ro

0.5

N

Temperature (ºC)

E

Temperature (ºC)

K 0

140 140

120

100

80

60

40

20

0

140

120

100

80

60

Age (Ma)

Age (Ma)

(b) Baobab SE 3

(c) Raphia S 8A

Fig. 7.44 Burial and structural thermal histories of the northern slope

40

20

0

7.2 Hydrocarbon Accumulation Periods

347

Based on this understanding, the hydrocarbon accumulation periods and timings were investigated by analysis of inclusions and burial and thermal histories (Figs. 7.41, 7.42, 7.43 and 7.44). The first-stage inclusions in the Baobab C buried hill oil reservoir, hosted in quartz veins and secondary overgrowth boundary of quartz, have peak homogenization temperatures of 115–120 °C, corresponding to the oil charging episode at 80 Ma on the burial history diagram of well Baobab C-2 and the thermal history diagram of well Baobab SE-3. The second-stage inclusions, in microfractures intersecting quartz and secondary overgrowth boundary of quartz, have peak homogenization temperatures of 125–130 °C, which correspond to the oil charging episode at ~70 Ma on the burial and thermal history diagrams. The date of 70 Ma lies within the timing range of hydrocarbon generation and expulsion, confirming the accuracy of the timing of the hydrocarbon accumulation period. The low peak temperature at 85–90 °C observed in structural fractures may be a record of inclusions trapped during later uplifting and reformation, corresponding to an oil and gas charging adjustment episode at ~30 Ma in the late Paleogene which appears on the burial history diagram. This is suggestive of a third hydrocarbon accumulation event in the buried hill oil reservoirs caused by secondary oil and gas adjustment and charging during strong structural uplift and reformation in the Baobab area. The charging period and timing of the Mimosa-Phoenix buried hill oil reservoir in well Raphia S-8A were also analyzed. In this well, the homogenization temperature of inclusions in microcracks that do not intersect quartz healing cracks corresponds to ~80 Ma on the thermal history diagram and that of siliceous quartz-healed fractures to ~70 Ma. These oil and gas charging events fall within the hydrocarbon generation and expulsion stage, confirming the accuracy of the charging times. The continuous peak value is indicative of continuous charging. Integrated analysis of the hydrocarbon generation and expulsion history, crude oil characteristics, inclusion composition, and homogenization temperatures suggests that the crude oil in the Baobab buried hill derives from the adjacent Baobab North and Mimosa N subdepressions, with the maturity of the source rocks in the Mimosa N Subdepression being higher than those of the Baobab N Subdepression. The Baobab C buried hill received low-mature and mature oil from these two depressions, with oil and gas charging beginning at ~80 Ma. Both depressions experienced two stages of low-mature and mature oil charging, with the ratio of low mature to mature oil being nearly 3:7. A later adjustment event occurred in the buried hill reservoirs. The Mimosa-Phoenix-Raphia buried hill reservoirs contain mature crude oil from the Mimosa N Subdepression, although the possibility of contributions of oil from other depressions cannot be excluded. The oil and gas charging peak began at ~80 Ma and corresponded to continuous charging with mature oil and gas. More than 90% of the oil and gas is mature. Hydrocarbon Accumulation Periods of Sandstone Reservoirs Hydrocarbon Accumulation Period of the Ronier Oilfield Geochemical analysis of the crude oil in the Ronier Oilfield shows the co-occurrence of relatively complete saturated hydrocarbon series and 25-norhopane series. The

348

7 Geological Features of Hydrocarbon Reservoirs

Table 7.3 Biomarker characteristics of Lower Cretaceous crude oil in the Ronier Oilfield Well

Depth(m)

Formation

Feature

Ronier-1

1057–1070

K

Ronier C-1

392.2–402

B

Coexistence of relatively complete saturated hydrocarbon series with obvious 25-norhopane

Ronier C-1

734–770.5

R

Ronier CN-1

1014.4–1024

R

Ronier N-1

561.0–571.0

K

presence of 25-norhopanes indicates that the crude oil has undergone strong biodegradation. At the same time the relative completeness of the saturated hydrocarbon series implies that recharging with normal oil occurred later (Table 7.3). The inclusions in well Ronier 4-1 in the Ronier Oilfield are mostly in microfractures, with two types of peak temperatures: a low-temperature section between 75 and 95 °C and a high-temperature section between 115 and 125 °C (Figs. 7.39, 7.40, 7.41, 7.42, 7.43, 7.44 and 7.45). We projected these temperatures onto the burial history diagram. The result shows that the dominant high-temperature section corresponds to the primary charging period in the late Late Cretaceous. The relatively low-temperature section may correspond to recharging with crude oil following later adjustment (Fig. 7.46), which may explain the highly unusual biomarker feature of co-occurrence of complete saturated hydrocarbons and 25-norhopanes. Hydrocarbon Accumulation Period of the Baobab N Oilfield Most of the oil reservoirs in the Baobab N oilfield contain normal oil, with crude oil gravity ranging between 24° and 32°API. Biomarkers rarely include 25-norhopanes,

Fig. 7.45 Hydrocarbon-bearing brine inclusions in quartz grain fractures at a depth of 1521 m in well Ronier 4-1

7.2 Hydrocarbon Accumulation Periods Cretaceous K2

K1

0

349 Paleogene E2

E1

Neogene

E3

Neogene 40 Paleogene

Depth (km)

40

1.0

B+R Fm.

50

60

K Fm. 70 70

80 2.0

80

90 100 110 120 100

0

50 Age (Ma)

Fig. 7.46 Burial history and hydrocarbon accumulation period of well Ronier 4-1

and the oils are mature, which indicates that the Baobab N Oilfield may have experienced a single charging episode. However, there are exceptions. For example, the Baobab N Oilfield has slightly biodegraded heavy oil at 1751.8–1765 m and normal crude oil at a shallower depth of 1388–1407.7 m. Surprisingly, the shallow normal oil is more mature than the deeper heavy oil (Table 7.4). This may result from reservoir adjustment following late tectonic action, which allowed oil from the deep part of the Baobab N-8 oil reservoir to migrate to the shallow layers through fractures. The inclusions in well Baobab N-8 are mainly in microfractures. Statistics suggest two ranges of peak temperatures, with a low-temperature section between 65 and 85 °C and a high-temperature section from 115 to 135 °C (Figs. 7.47 and 7.48). Projecting these temperatures onto the burial history diagram suggests that primary oil and gas charging took place in the Late Cretaceous and the crude oil became degraded due to structural adjustment (Galbraith 1981). Contemporary compression inversion increased the amplitudes of shallow traps, allowing deep oil and gas to enter the shallow part of the reservoir through fractures and resulting in the observed inversion of crude oil with different maturities shown in Table 7.4.

Table 7.4 Statistics of crude oil maturity parameters at different depths in well Baobab N-8 Well

Depth(m)

Ts/Tm C29 Ts/ 20S/20(S + ββ/(αα + (C29 Ts R)-C29 sterane ββ)- C29 + sterane 17aC29

Baobab 1388–1407.7 0.69 N-8 1751.8–176 0.52

Rearranged 4,4,8,8,9-pentamethyl drimane/drimane decahydronaphthalene/ 8β- drimane

0.23

0.36

0.34

0.96

0.74

0.21

0.43

0.31

0.57

0.32

350

7 Geological Features of Hydrocarbon Reservoirs

Fig. 7.47 Hydrocarbon-bearing brine inclusions in quartz grain fractures at a depth of 1395.51 m in well Baobab N-8 Cretaceous K1

0

E1

K2

Paleogene E2

E3

Neogene Neogene Paleogene

40

30

B+R Fm. K Fm.

40 50 1.0

M Fm.

Depth (km)

60 70

P Fm.

80 2.0 90

100 110 3.0

120 130

100

50

0

Age (Ma)

Fig. 7.48 Burial history and hydrocarbon accumulation period of well Baobab N-8

Hydrocarbon Accumulation Period of the Mimosa Oilfield The inclusions in the Mimosa oil reservoir are mostly in secondary overgrowth boundaries and microfractures, with homogenization temperatures of 75–135 °C and peak temperatures of 75–85 °C. Crude oil entered the reservoir for the first time just as hydrocarbon generation and expulsion were at their peak, which was also the charging peak. With increasing burial depth, later crude oil also migrated along the charging path to reach the oil reservoir. Projecting these homogenization temperatures onto the burial history diagram shows that the timing of oil and gas entering the Mimosa traps was also in the late Late Cretaceous (Fig. 7.49).

7.2 Hydrocarbon Accumulation Periods

0

Cretaceous K2

K1

351 Paleogene E2

E1

E3

Neogene Neogene

40 40

Paleogene

B+R Fm.

Depth (km)

50 1.0 60

K Fm. 70 80 2.0 90 100

100

50

0

Age (Ma)

Fig. 7.49 Burial history and hydrocarbon accumulation period of well Mimosa 4–1

Hydrocarbon Accumulation Period of the Baobab S Oilfield The inclusions in the Baobab S Oilfield are mostly in secondary overgrowth boundary and microfractures, with inclusion homogenization temperatures of 75–145 °C. This oilfield shares the same source as the Mimosa Oilfield: the high-quality source rock in the Mimosa N Subdepression. The two oilfields have the same wide range of homogenization temperatures, with the temperature peak in the low-temperature section, implying the same oil charging process and timing: that is, the crude oil entered the reservoir for the first time at the peak of hydrocarbon generation and expulsion, which coincided with the peak of charging. At deeper burial depths, crude oil continued to fill the oil reservoir. Projecting homogenization temperatures onto the burial history diagram suggests that the timing of oil and gas entering the Baobab traps was, again, during the late Late Cretaceous (Fig. 7.50).

7.2.3 Dynamic Oil and Gas Charging in the Great Baobab Oilfield The Baobab oil and gas zone is the most developed in the Bongor Basin, with large reserves and complete distribution of pay zones. It can be divided into three major accumulation zones—Baobab S (BS), Baobab N (BN), and Baobab C (BC). Clastic layered reservoirs are primarily found in the P Formation in BS and BN, and massive buried hill reservoirs are found in BC (Fig. 7.51). The primary reservoirs in the Mimosa oil and gas belt are layered in the K and P Formations, with massive buried hill reservoirs developed in the east.

352

7 Geological Features of Hydrocarbon Reservoirs Cretaceous K1

0

K2

E1

Paleogene E2

E3

Neogene

40 40

1.0

Neogene Paleogene B+R Fm.

50

K Fm.

Depth (km)

60 M Fm.

70 2.0

80

P Fm. 90 100 110

3.0

120

100

50

0

Age (Ma)

Fig. 7.50 Burial history and hydrocarbon accumulation period of well Baobab S1-1

Fig. 7.51 Distribution of oil reservoirs in the Great Baobab Oilfield

Crude Oil Source and Filling Direction The essence of oil-source correlation is to clarify the differences between key components and biomarkers from various parent materials. The commonly used indicators include biomarkers, elements, and stable isotope compositions. The principal method

7.2 Hydrocarbon Accumulation Periods

353

for oil-source correlation of elements and determination of stable isotope composition is an analysis of disparities in distribution range (Li et al. 2012). However, the volume and representativeness of data often affect the results of the oil-source correlation. In addition, for crude oils from source rocks formed in similar sedimentary environments, there is inevitably some overlap, so it is impossible to establish fine correlations. The analogy between Gas chromatography (GC) and Gas chromatography-mass spectrometry (GC–MS) parameters for biomarkers and related biomarker compounds has long been the most commonly used means to correlate oils and sources. Specific biomarkers in source rocks are compared with biomarkers in crude oil. If the geochemical characteristics of the crude oil and the source rocks are similar, it indicates that the oil is from that source. The source of oil and gas, and the direction of oil and gas filling and migration, can be clarified by a comparative analysis of oils and sources. We used this approach to identify the sources and migration directions of the oils in reservoirs in diverse zones in the Great Baobab Oilfield. The Great Baobab Oilfield has very specific structural characteristics, so we analyzed mudstone samples from the Baobab North and Mimosa N subdepressions and crude oil samples from the Baobab and Mimosa Oilfields to determine the differences between the Baobab Oilfield and the Mimosa Oilfield. Mass spectrometry of saturated hydrocarbons from the source rocks (Fig. 7.52) shows that the alkane series found in both the Baobab North and Mimosa N subdepressions are generally similar, as are the distribution patterns of steroid and terpene series. The biggest difference between the two oilfields is in the overall proportions of tricyclic terpanes in the terpane series, the contents of long-chain tricyclic terpane, and the contents of pregnane, homopregnane, and diasterane in the sterane series. As previously suggested, there are few differences between the parameter values of relevant biomarkers in the crude oils of the Mimosa Phoenix zone and the Baobab C buried hill. The mass spectra of saturated hydrocarbons in sandstone and buried hill reservoirs are similar. The subtle discrenpancies in the compositions of biomarkers in oils in the various reservoir zones are similar to those found in the source rocks, principally disparities in the relative contents of tricyclic terpanes, hopanes, steranes, and other compounds. Tricyclic terpanes in buried hill crude oil and mudstones in the depressions show normal distributions, with C23 tricyclic terpanes as the main peak and C30 hopanes as the main peak in the hopane series. The relative contents of tricyclic terpanes and hopanes reflect the parent materials, so parameter diagrams of the main peaks are established to allow comparison (Fig. 7.53a). These parameter values distinguish between crude oils from the sandstone and buried hill reservoirs in the Mimosa Oilfield and those in the Baobab Oilfield. The data points of the oils in the sandstone and buried hill oil reservoirs in the M zone are closer to the source rock parameters of the Mimosa N Subdepression and are therefore likely to have been supplied from those source rocks. The data points of the oils in the sandstone oil reservoirs in the BN zone are close to those of the source rocks in the BN zone and are therefore likely to have come from there. The parameter diagram shows that the oils in the sandstone oil

354

7 Geological Features of Hydrocarbon Reservoirs m/z57

m/z191

C30H

m/z57

m/z191

C30H

C23TT C23TT

Ts

Tm Ts BN- 1 Sandstone crude oil (P Formation)

BN- 1 Sandstone crude oil (P Formation) m/z57

m/z191

C23TT

C30H

m/z57

m/z191

Ts Tm

BE- 2 Buried hill crude oil m/z57

m/z191

m/z191

C30H

C23TT C23TT BNE- 1 Mudstone (P Formation)

C30H

C23TT

Tm Ts

BC- 5 Buried hill crude oil m/z57

Tm

Tm Ts

C30H

Ts Tm

BNE- 1 Mudstone (P Formation)

Fig. 7.52 Distribution spectra of biomarkers in source rocks and crude oils in the northern slope of the Bongor Basin: TT-tricyclic terpanes; Ts-C27 trisnorneohopane; Tm-C27 trisnorhopane; Hhopane

reservoirs in the BS zone are closer to the source rocks in the Mimosa N Subdepression, from which they were primarily supplied. Buried hill oil reservoir parameters in the BC zone fall between the biomarker parameters of the source rocks in the two depressions, which suggests that they received contributions from both the Mimosa N Subdepression and the Baobab N Subdepression. Given the unique characteristics of biomarkers in the Bongor basin, the comparison parameter C28-29 TT/C30 H—longchain tricyclic terpane and hopane—is adopted. Further fine comparison of oil source attributions can be conducted with the Ts/Tm ratio (Fig. 7.53b). Attribution of oil source can be intuitively judged from the parameter comparison diagram, which coincides with Fig. 7.53a. The sandstone oil reservoirs of the Mimosa N Subdepression, the BS Depression, and the buried hill oil reservoirs in the Mimosa Depression were all supplied from the source rocks in the Mimosa N Subdepression. The sandstone oil reservoirs in the Baobab N Subdepression were supplied from the local source rocks in the subdepression. The crude oil in the BC buried hill comes from source rocks in both the Mimosa North and Baobab N subdepressions. The high content of C30 diahopane is derived from the catalysis of clay in a weak oxidizing-reductive environment. This reflects the sedimentary paleoenvironment, and this parameter can be used to estimate subtle environmental differences. The 22RC31 H/C30 H ratio here is

7.2 Hydrocarbon Accumulation Periods

355

less than 0.25, indicating fresh continental water and, therefore, a lacustrine environment. Gammacerane (γ) also reflects the salinity of the water body. The value of this parameter is high in salt water and low in fresh water. The oil-source relationship is quite apparent from the correlation diagram between C30 diahopane parameters and 22RC31 H/C30 (Fig. 7.53c, d). Sandstone and buried hill crude oils in the M and BS zones have relatively high C30 diahopane/C29 Ts ratios, having been largely generated in the source rocks of the Mimosa N Subdepression, which have high C30 diahopane. The crude oil in the BN zone has a lower C30 diahopane/C29 Ts ratio, as it was mostly generated in the source rocks of the Baobab N Subdepression, which have low C30 diahopane. The C30 diahopane /C29 Ts ratio of the buried hill crude oil in the BC zone falls between the parameters of the source rocks in the two depressions, suggesting that the buried hill crude oil in the BC zone came from both sets of source rocks. In the maturity parameter diagram of steranes and terpanes (Fig. 7.53e, f), the source rocks and crude oil both fall within the mature area, so these are effective source rocks. This indicates that the sandstone and buried hill oil reservoirs in the M, BS, BN, and BC zones all contain mature crude oil. Charging Process of Reservoirs To further understand changes in crude oil composition during charging, we selected the buried hill oil reservoir of the Great Baobab Oilfield for analysis of the geochemical characteristics of hydrocarbons in both fluid inclusions and crude oils in the reservoirs. We then compared the compositions of the oil reservoir and the fluid inclusion to obtain a visual understanding of the filling process. Buried hill samples from well Baobab C-4 were selected for simultaneous GCGC–MS analysis of the compositions of authigenic calcite inclusions and crude oils in pores (Fig. 7.54). The distributions of normal alkanes in both the crude oil and the inclusions from well Baobab C-4 are similar; both are normal distributions with a smooth baseline and C25 as the main peak. The Pr/Ph ratio is greater than one, and the environment for hydrocarbon parent material is consistent, indicating that they formed in freshwater lacustrine facies. The distribution of normal alkanes shows that neither the crude oil nor the hydrocarbon inclusions are degraded. This confirms that, during the dynamic process of crude oil charging into the buried-hill traps, the traps were closed and intact, hydrodynamism did not occur, the oxygen content in the reservoir was low, and there was little or no bacterial activity. In the distribution diagram of hopanes, C30 hopane is the main peak in crude oils and inclusions, the homohopane series decreases successively, and the Ts/Tm ratio is less than 1. Tricyclic terpanes with high carbon numbers are present, the peak pattern of gammacerane is higher than that of C31 homohopane, diahopane is not present, and the parameter values are in line with each other. In the sterane series, C29 regular steranes predominate in crude oil and the inclusions, and C27 -C28 -C29 steranes are distributed in an asymmetric “V” shape. The distribution characteristics and parameters of hopanes and steranes indicate that the compositions of the crude oil and the hydrocarbon inclusions accord with each other, implying that their parent material sources, parent material environment, Etc., are similar. The C29 isomerization parameters are between 0.4 and 0.45, representing a mature stage. On this basis, it is

356

7 Geological Features of Hydrocarbon Reservoirs 0.8

0.4

0.2

1.0 (a) TT/H

0.5

1.5

0

0.5

1.0 1.5 (b) C28 C29TT/C30hopane

2.0

0.2

C30DH/C30hopane

0.5 Crude oil in BS zone Crude oil in BN zone Buried hill crude oil in BC zone Crude oil in M zone Buried hill crude oil in M zone Mudstone in BN zone Mudstone in M zone

0

0.1

0.2 0.3 (c) 22RC31H/C30hopane

1.0

Crude oil in BS zone Crude oil in BN zone Buried hill crude oil in BC zone Crude oil in M zone Buried hill crude oil in M zone Mudstone in BN zone Mudstone in M zone

0.5

Crude oil in BS zone Crude oil in BN zone Buried hill crude oil in BC zone Crude oil in M zone Buried hill crude oil in M zone Mudstone in BN zone Mudstone in M zone

0 1.0

0.5 (d) /C30hopane

1.0

Crude oil in BS zone Crude oil in BN zone Buried hill crude oil in BC zone Crude oil in M zone Buried hill crude oil in M zone Mudstone in BN zone Mudstone in M zone

0.5

22S/22 (S+R)

Mature—High mature

Low mature Immature 0

0.1

0.4

C31hopane

C30DH/C29Ts

1.0

2.0

1.0

C29sterane

1.5

0.5

0

/ +

Crude oil in BS zone Crude oil in BN zone Buried hill crude oil in BC zone Crude oil in M zone Buried hill crude oil in M zone Mudstone in BN zone Mudstone in M zone

2.0

Ts/Tm

0.6 C23TT/C30hopane

2.5

Crude oil in BS zone Crude oil in BN zone Buried hill crude oil in BC zone Crude oil in M zone Buried hill crude oil in M zone Mudstone in BN zone Mudstone in M zone

0.5 (e) 20S/20 (S+R) C29sterane

1.0

0

0.5

1.0

(f) 22S/22 (S+R) C32hopane

Fig. 7.53 Comparison of parameters of buried hill crude oil and source rocks in the Bongor Basin. TT—tricyclic terpanes; Ts-C27 trisnorneohopane; Tm-C27 trisnorhopane; DH—diahopane; γ— gammacerane; C29 Ts-C29 norneohopane

considered that the compositions of inclusions and crude oil are coincident and that their maturity is equivalent, indicating that the crude oil and the inclusions formed simultaneously, and that no secondary effects such as biodegradation occurred during charging. Analysis of inclusions and reconstruction of burial histories suggest that the formation age of the sandstone and the basement rock reservoirs in the Great Baobab Oilfield is the same. Both reservoir types began to be charged and form primary reservoirs in the late Cretaceous, and the reservoirs are generally well preserved. Secondary phenomena occurred in some areas, such as adjustment and degradation in shallow reservoirs. By recovering the traps in the Great Baobab Oilfield, we

7.2 Hydrocarbon Accumulation Periods

357

Fig. 7.54 Distribution spectra of hydrocarbon biomarkers in well Baobab C-4

reconstructed the formation process of the reservoirs from the perspective of their structural evolution. (1) From the Cambrian to the Jurassic, the Bongor Basin did not receive sediments. The basement, which contains Precambrian granite, migmatite, gneiss, Etc., experienced weathering and denudation long before the Cretaceous deposition, forming a plain of denudation and weathering crust, with little topographic relief in the plane (Fig. 7.55a). (2) The early Cretaceous (the sedimentary period of the P-M Formations) was a rapid subsidence during the early rifting stage. At this time, fault activity was intense, with faults penetrating the basement and significantly impacting it. During this period, the mountain-controlling fault was generally steep, and the dip angle of the fractured surface was more than 50°. The P Formation commonly onlapped the basement, the buried hills warped under the action of faults, the shape changed considerably, and the depressions between buried hills deepened. The uplift pattern of the buried hill belt in the M-P and B zones was formed at this time (Fig. 7.55b, c). (3) The late Early Cretaceous was a slow subsidence stage. The buried hills in the MP and B zones were completely covered by sedimentary strata. Faults controlled sedimentation and there was little change in the buried hill pattern. The basement was covered with fine-grained sediments such as lacustrine mudstone, and structural closure of the buried hill traps and sedimentary caprocks occurred (Fig. 7.55d) (4) In the period from the late Cretaceous to the Paleogene, the basin initially continued to receive sediments. The source rocks entered the threshold of hydrocarbon generation and began to generate and expel hydrocarbons, which gradually migrated into the buried hill traps. Hydrocarbons accumulated in the clastic structural traps in the BS zone and the structural and structural-lithologic traps in the BN zone, represented by BS-1 and other blocks. The buried hill traps in the BC zone, represented by wells BE-2 and BC-5, were supplied from the source rocks in the subdepressions on both sides (Fig. 7.55e, f). The entire basin

358

7 Geological Features of Hydrocarbon Reservoirs

Mimosa E 1

0

A

1

+ + + + + + + + + + + + + + + + + + + + + + + + + +

Baobab C 5 Baobab E 2

+ + + + + + + + + + +

+ + ++ ++ + + + + + + + + + + + + + + + + + + + + + + + + + + + + +

Mimosa E 1 + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +

A′ + + + + + + + ++ + + + + + + + +

+

+

+ + + + + + + + + + + + + +

Baobab C 5 Baobab E 2

A

Baobab N 1

2km (a) Before the deposition of P Formation

Baobab N 1

+ ++ ++ ++ + + + + + + + + + + + + + + + + + + + ++ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +

+ + + + + + + + + + + + + + + + + +

A′

+ + + + +

(b) Sedimentary period of P Formation A

Mimosa E 1 Baobab N 1 A′ Baobab E 2 Baobab C 5 + + + + + + + + + + + + ++ + + + + ++ ++ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +

Mimosa E 1

Baobab E 2

Baobab C 5

Baobab N 1

A′

A

+ + + + + + + ++ + + + + + + + + + + ++ + + + + + + + + + + + + + + + + + + + + + + + + ++ + + + + + + + ++ ++ ++ + + + + + + + + + + + + + + + + + ++ ++ + + + + ++ + + + + + + + + + + + + + + + + + + + + + + + + + + +

(c) Sedimentary period of M Formation

Mimosa E 1

Baobab E 2 Baobab C 5

A

Baobab N 1 A′

+ + + + + + + + + + + + ++ + + + + + + + + + + ++ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + ++ + + + + + + + + ++ ++ ++ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +

+ + + + + + + + + + + + + + + + + + + + + + + +

(d) Sedimentary period of K Formation

A

Baobab N 8 Mimosa NE 1 Baobab C 5 Baobab NE 1 Baobab N 1 Mimosa E 1 Baobab E 2 A′

+ + ++ + + ++ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + ++ + + + + + + + + ++ ++ ++ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +

(e) Sedimentary period of R Formation

(f) Present

+ + Basemnet

P Formation

M Formation

K Formation

R Formation

B Formation

Cenozoic

Oil

Fig. 7.55 Reservoir forming and evolutionary process of the Great Baobab Oilfield

was reversed and uplifted in the late Cretaceous, and the upper Cretaceous was almost completely eroded. During this stage, faulting had a marked destructive effect on the overlying sandstone oil and gas reservoirs. Above plays in the structural traps were generally heavy or normal-heavy reservoirs with high acid numbers and a wide occurrence of 25-norhopane. Middle plays were also locally degraded (Fig. 7.52). During this period, the overlying Lower Cretaceous P, M, and K Formations mudstones in the buried hills were not significantly denuded, and the barrier beds of the traps were well preserved. Only a small number of well points in the buried hill reservoirs were damaged by buried hill-controlling faults, with the crude oil at these points becoming slightly degraded. (5) A weak inversion occurred in the basin at the end of the Paleogene, and the overlying strata suffered a certain amount of denudation. However, this had no impact on the buried hill oil reservoirs, and the oil reservoir pattern was maintained (Fig. 7.55f).

7.3 Main Controlling Factors of Hydrocarbon Enrichment ME 1

MNE 1

BE 2

BC 5

359 BNE 1 BN 8 BN 1 NE

Sag

Salient

Fault

Basemnet

P

M

K

R

B

Cenozoic

Oil

Oil migration

Fig. 7.56 Filling model of the Great Baobab Oilfield

Filling Model Geochemical characteristics analysis, inclusion analysis, and structural history analysis indicate that the oil and gas accumulation processes of the BN, BS, and BC zones in the Baobab Oilfield were quite distinct. In the BN and BS zones, hydrocarbons were supplied from source rocks in the local depressions. The BC zone, on the other hand, is a buried hill oil reservoir, and the oil and gas were generated from the source rocks in both the Baobab North and Mimosa N subdepressions (Fig. 7.56). However, the timing of reservoir formation in all of the zones in the Baobab Oilfield was the same, with oil and gas migrating locally, driven by hydrocarbon generation and expulsion from Late Cretaceous source rocks.

7.3 Main Controlling Factors of Hydrocarbon Enrichment Global exploration practice suggests that every basin, subbasin, and petroleum system has its unique hydrocarbon accumulation and distribution features, affected by its general tectonic characteristics and petroleum geological conditions. For a halfgraben depression that has experienced a single major rifting stage, oil and gas accumulation can be divided into three types: gentle slope enrichment, steep slope enrichment, and gentle- to steep-slope balanced enrichment. However, the Central

360

7 Geological Features of Hydrocarbon Reservoirs

African Rift System (CARS) is complicated, for three stages of rifting superimposed on it. The common source rocks in CARS are generally regional Lower Cretaceous lacustrine mudstones. However, hydrocarbon distribution and enrichment vary greatly between the basins and depressions—resulting from later tectonic movements and diverse fault conduit systems. For example, in the Muglad Basin, regional caprocks formed in the second rifting stage provide an excellent seal for the underlying Bentiu Formation sandbodies (Tong et al. 2004). Oil and gas are enriched in the Bentiu Formation of the “above source play” and trapped in antithetic fault blocks. In the plane, oil and gas are enriched in structural accommodation zones between depressions such as the Bamboo, Heglig, and Fula subbasins (although those in the Sufyan and Nugara subbasins and the Kaikang trough are less enriched) (Tong et al. 2006). The Melut Basin is comparatively lacking in thick regional mudstone from the second rifting stage, but regional mudstone formed in the third rifting stage acts as a high-quality caprock. Because of this favorable structure, the Melut Basin hosts the world-class Palogue Oilfield and a series of small and medium-sized oilfields in the Paleogene, with oil and gas predominantly found in the northern depression. In the Doba Basin, the main oil and gas accumulations are in the Kome structural belt in the basin’s center. This is an oblique inversion anticline structural belt, with the principal enrichment strata being the Upper Cretaceous. Generally, more than 80% of the oil and gas reserves in the Muglad, Melut, and Doba Basins are enriched in ‘above source plays’. The steep slope is not abundant in oil and gas, which suggests that the lateral accommodation zone exerts significant control over oil and gas migration and accumulation (Dou et al. 2006). Macgregor (1995) considered that the trap types in regional inversion rifts are predominantly inversion anticlines and fault blocks. Finding large oilfields in these structures is difficult because of their inaccessibility to hydrocarbon generation and accumulation. The Bongor Basin is a strong inversion rift basin, with great denudation thickness caused by massive uplifting and a compressional shortening rate of up to 8%. Two wells were drilled in the 1970s in the basin but failed, and exploration halted. A new round of drilling was begun in 2003, with six wells being drilled without discovering any commercial oil flow. The main reason for this lack of success was not the absence of oil but rather that the inverted nature of the basin was not well understood, leading to inaccurate assessment of the distribution and characteristics of source rocks and uncertainty about play and the location of the petroleum play. Although the Bongor Basin shares the same distributions and types of lacustrine source rocks as other basins in the CARS, strong inversion has led to denudation of the second rifting sequence and non-development of the third rifting sequence. As a result, the Bongor Basin has significantly distinct oil and gas accumulation and distribution characteristics from the other basins in the rift system. The primary plays in the other basins are large-scale fluvial facies or delta facies, which do not occur in the Bongor Basin. Exploration in the basin has targeted fan delta and subaqueous fan sandbodies from the early rifting stage. The challenge faced by exploration efforts is difficulty restoring prototype basins, which have been

7.3 Main Controlling Factors of Hydrocarbon Enrichment

361

obscured by rapid facies change and basin inversion, making prediction and exploration of sandbodies a complicated endeavor. Moreover, little attention has been paid to the exploration potential of basement rock buried hills. The unique geological structure of the Bongor Basin means that appropriate, specific geological and reservoir-forming models must be established for this strongly inverted rift basin to identify hydrocarbon generation and accumulation zones, which is the key to successful exploration and the discovery of large oilfields in the basin. Ten years of exploration practice has proved that, in aiming to delineate favorable plays for large oilfields, it is essential to focus on early fan delta and subaqueous fan sandbodies, combinations of inversion anticlines and sandbodies, and combinations of sandbodies and basement rock. Source-caprock assemblages in the Bongor Basin should be evaluated in light of the understanding of ‘under source play’ while also considering the need to avoid combinations where the crude oil has been strongly degraded (Dou et al. 2011; Lirong et al. 2015).

7.3.1 ‘Below Source Plays’ are the Main Hydrocarbon Accumulation Structures Oil and gas exploration in the WCARS over the past 40 years has been successful in targeting ‘above source plays’, with the discovery of several large and medium-sized oilfields hinting at wider exploration potential. For instance, the Doba and Doseo Basins in Chad and the Muglad Basin in Sudan host more than 80% of the Upper Cretaceous (initial oil in place) IOIP. In the Termit Basin in West Africa and the Melut Basin, where CARS meets the East African rift system, more than 90% of the IOIP are in the Paleogene (Dou et al. 2011). In the Bongor Basin, the Upper Cretaceous has been eroded due to Late Cretaceous uplifting and inversion, so none of the Paleogene and Upper Cretaceous plays that occur in other CARS basins. Nevertheless, the Lower Cretaceous plays in the basin were uplifted by 1000–2000 m and show promise as exploration strata. More than 85% of the oil and gas reserves so far discovered are below the source rock in the M Formation and the upper member of the P Formation (Fig. 7.57). The extremely thick mudstone in the M Formation and the upper member of the P Formation, deposited during the rifting stage, plays an important role in preserving deep oil and gas in the basin. This set of thick mudstone divides the basin vertically into two types of plays: ‘above source play’ and ‘under source play’. ‘Above source plays’ are mainly composed of the K, R, and B Formations, with internal sandstone and mudstone forming play-level reservoir-caprock assemblages. Due to the gradual upward coarsening of sediments and the absence of regional thick caprock, the formations have thin-layer heavy oil predominantly, for example, the Ronier and Mimosa Oilfields in the K and R Formation oil reservoirs and the B Formation heavy oil reservoirs drilled in well Ronier C-1 (Fig. 7.58). Some small compressional anticline ‘above source play’ oil and gas reservoirs have also been discovered

362

7 Geological Features of Hydrocarbon Reservoirs Oilfield

Reservoir

Ronier

Mimosa

G Baobab Phoenix

Raphia S

B Fm.

Daniela

Lanea

Lanea E

Delo

Mango

Absent

Lower Cretaceous

R Fm.

K Fm. M Fm. P Fm.

Basement Heavy oil

Conventional oil

Absent

Caprock

Fig. 7.57 Exploration formations of the main oil and gas fields in the Bongor Basin

in the steep slope zone of the basin, for example, the Mango and Delo Oilfields. Structurally, ‘under source plays’ take the form of ‘upper source, upper caprock, and lower reservoir’. The thick organic-rich mudstone of the M Formation and the upper member of the P Formation is capable of both hydrocarbon concentration sealing and under compaction sealing and therefore functions as both high-quality regional caprock and effective source rock. This set of mudstone protected the underlying oil and gas from the strong forces acting during uplifting and structural inversion. Oil and gas are enriched in the Lower Cretaceous sandstone from the early rifting stage, and in Precambrian basement rock buried hills. Sealing by the thick M Formation mudstone also ensures the maturity of underlying oil and gas and almost completely protects the crude oil from biodegradation. Asphalt, heavy oil, normal oil, conventional oil, and condensate have all been discovered in the Bongor Basin. However, normal oil and conventional oil have only been discovered below the M Formation caprock. For example, the P Formation oil layer in well Laneae-2 has a burial depth of only 710 m and a crude oil density of 0.8612 g/cm3 , although geochemical analysis suggests that it has been slightly biodegraded.

7.3.2 Compressional Inversion Anticlines are the Main Hydrocarbon Trap Type The main trap type in the Muglad Basin of CARS is antithetic fault block, such as those of the Unity Oilfield in the Bentiu Formation (Tong et al. 2004; Giedt 1990). In the Melut Basin, the primary trap type is large Paleogene drape anticlines, such as those of the Palogue oilfield (Dou 2005). In the Doba Basin, the main trap type is compressional anticlines developed on paleouplift, which have been subjected to draping followed by inversion (Genik 1992). For example, the Kibea Oilfield in the

7.3 Main Controlling Factors of Hydrocarbon Enrichment Ronier C 2

Ronier 4

363 Ronier 1

South

North

0

B Fm. -500

0.966g/cm3

Elevation (m)

Density0.989

Density0.919g/cm3

R Fm.

Density0.855g/cm3 K Fm. -1500

M

Density0.792g/cm3

Fm

.

P Fm.

oil

Water

Condensate

Fig. 7.58 Cross-section through the Ronier Oilfield

Doseo Basin is an Upper Cretaceous compressional anticline on the hanging wall of a boundary fault. The formation and development of traps in the eastern basins in CARS are controlled by faults and basement rock uplifts significantly. However, they have been less affected by basin inversion. However, the traps in the central rift basins have been greatly impacted by compressional inversion. All the oil and gas fields discovered in the Bongor Basin are in compressional inversion anticlines with high inversion intensity. They can be divided into two types: the first is drape anticlines developed on paleouplift which have been subjected to later compressional inversion to form anticlines with greater amplitude, such as the Baobab-1 anticline (Fig. 7.59); the second is developed in the hanging walls of large faults, with new compressional anticlines forming in the hanging walls of steep faults, such as the Prosopis anticline (Fig. 7.60), the Baobab NE structure, and the Baobab N structure (Fig. 7.61). These share the common characteristics: the trap area is large at the top and small at the bottom and the trap amplitude is small at the top and large at the bottom, completely different from typical drape anticlines. The Baobab N structure was originally a monocline which evolved into a large lithologic trap due to updip pinch-out of the P Formation sandbody. Later compressional inversion formed an inverted nose structure at the top of the sandbody. Oil and gas filling was greater than the local structural amplitude at the top, so a large lithologic trap reservoir formed, with an oil column height of 1000 m. Inversion increased the trap amplitude and the strata dip and promoted later oil and gas filling, eventually forming a large oil and gas reservoir.

364

7 Geological Features of Hydrocarbon Reservoirs

Fig. 7.59 3D seismic line of the Baobab-1 structure

Fig. 7.60 3D seismic line of the Prosopis structure

Prosopis-1

7.3 Main Controlling Factors of Hydrocarbon Enrichment

365

Fig. 7.61 3D seismic line of the Baobab NE—Baobab N structure

7.3.3 Subaqueous Fan and Fan Delta Sand Bodies are Main Reservoirs The deposition rates of the P and M Formations in the Bongor Basin reached 475 and 552 m/Ma, respectively, which are higher than the deposition rate of the main source rocks in the Bohai Bay Basin. Steep boundary faults, high sedimentation rates, few topographic fluctuations, and a ‘hungry’ environment are highly conducive to sediment accumulation and forming deep lake basins. The fault activity rate of the P-M Formations along the boundary faults in the south of the Mango Depression reached 350 m/Ma, which is also higher than the activity rate of low-controlling faults in the hydrocarbon-rich depressions of the Bohai Bay Basin during source rock formation (Deng et al. 2013). During the sedimentary period of the K-R-B Formations, the activity rate of boundary faults was 120 m/Ma, with the reducing depth of the lake basin resulting in an increasing supply of terrigenous organic matter. Shore-shallow lake facies and local semi-deep lacustruine facies developed in the middle of the depression, forming delta sand bodies. The overall lithology transformed from muddy gravel in sandstone to sandstone-mudstone interbeds, in a coarsening-upwards sequence (Wang 1983). In addition to basement rock buried hill, the Bongor Basin contains 80% of the reserves in the P Formation, 15% of K Formation reserves, and 5% of M-R-B Formations reserves. The P Formation is the main sandstone reservoir divided into three oil layers: PI , PII , and PIII . The PI oil layer is subdivided into five sand sub-zones. The

366

7 Geological Features of Hydrocarbon Reservoirs

sedimentary environment is a nearshore subaqueous fan and fan delta, distinguished by horizontal rows and belts, vertical multi-layer overlap, small sandbody scale, and rapid lateral facies change. The reservoir lithology is gravel-bearing inequigranular lithic arkose or feldspathic lithic sandstone. The reservoir space is dominated by primary intergranular pores, secondary dissolution pores and intergranular micropores. The physical properties of the reservoir change greatly, with strong heterogeneity. The main reservoir is a medium-porosity and medium–high permeability reservoir. In the early development stage—when the basin was a small, segmented rift—a high protruding from the water surface provided an inner source of detrital material, subaqueous fan sandbodies and fan delta sandbodies formed in the hanging walls of the faults. The Baobab N Subdepression is a typical example. During deposition of the P Formation, the subdepression developed a series of fan delta deposits on both sides (Fig. 7.62). Coring in well Baobab N-8 has confirmed that the P Formation has coarse-grained sediments, dominated by grayish-brown and gray medium sandstone, gritstone, and glutenite, with few fine sandstones (Fig. 7.63). Most of the mudstone is dark gray massive mudstone, mixed with a thin layer of low-quality combustible oil shale, indicative of a semi-deep-water environment during deposition of the P Formation sandbodies. A scoured surface and graded bedding suggest deposition in subaqueous distributary channels. Deformation structure, boulder clay, and mudstone tearing debris are observed, resulting from rapid deposition of fan delta front subfacies in subaqueous distributary channels. The sediments are, therefore, primarily fan delta front subfacies, and the microfacies are mostly subaqueous distributary channels, microfacies between distributary channels, and local gravity flow deposition (Fig. 7.64). The sediments in the P Formation in the Daniela Oilfield are generally nearshore subaqueous alluvial fan deposits, and the microfacies are mostly subaqueous distributary channels with small numbers of interchannel bays and mouth bars. The P Formation, which is penetrated by well Daniela-1, has a maximum reservoir thickness of 335 m. The coring horizons of well Daniela-3 are the PI 2 and PI 4 sand sub-zones, with all the mudstones in the core being gray and gray-black, implying a reducing environment. Sandstone is generally medium sandstone and gritstone, followed by fine sandstone. A fine conglomerate is occasionally observed, with medium sorting and roundness and particle sizes of 2–4 mm. The fabric of the sediments is supported by the matrix, which is composed of fine silt and mud. A C-M diagram of samples shows that the point group is parallel to the baseline C=M, suggesting turbidite deposition. Sandstone and conglomerate in coring sections mostly show graded and massive bedding (Fig. 7.65a). Wavy and parallel bedding are occasionally observed in the siltstone, and argillaceous siltstone at the top of the cycle (Fig. 7.65b). A scoured surface is evident at the bottom of the cycle (Fig. 7.65c). Analysis of seventy-four cast thin sections from well Daniela-3 indicates that the P Formation is mostly lithic arkose, followed by feldspathic lithic sandstone. The proportion of feldspar is greater than 80%.

7.3 Main Controlling Factors of Hydrocarbon Enrichment

367

Baobab NE 3 Baobab NE 1

M Formation Basement

Late P Fm. Oil

Middle P Fm. Fan delta front

Early P Fm. Root fan

Fig. 7.62 Sedimentary model of the lower P Formation in Baobab NE Oilfield

7.3.4 Coupling of Felsic Basement Rock with a Strike-Slip-Extensional Environment Leads to the Widespread Development of Buried Hill Reservoirs Exploration of metamorphic rock buried hills in the Liaohe subbasin in eastern China has shown that the ‘dominant lithology’ in any given set of metamorphic rocks tends to act as the reservoir, with the ‘non-dominant lithology’ forming an interlayer inside buried hills (Xie et al. 2012). The ‘dominant lithologies’ are, from best to worst, leptite, leptynite, migmatite granite, gneiss, biotite leptynite, lamprophyre, diabase dyke, plagioclase amphibolite, and amphibolite (Xie et al. 2012). Protolith reconstruction shows that the parent rock of non-reservoirs in the buried hill in the Liaohe subbasin is a sedimentary rock. The amphibolite has inherited the layered structure of the parent rock and has become an interlayer inside the buried hill. In contrast, the protoliths of leptynite and leptite include sedimentary and magmatic rocks (Lu 2009). Large numbers of parametamorphic rocks and late intrusive lamprophyre dykes complicate the internal structures of the buried hills, making exploration complex and difficult. Metamorphic rocks in the Bongor Basin include leptite, gneiss, and leptynite. The varying degrees of metamorphism and deformation makes it difficult to reconstruct the protoliths of regional metamorphic rocks in the basin by relying only on their geological occurrences, rock combinations, and petrographic characteristics revealed

GR 120 API

Depth m

Core section

Resistivity 2 400  m

Oil bearing grade

70

7 Geological Features of Hydrocarbon Reservoirs Oil layer

368

Lithologic description

Sedimentary structure

Sedimentary Sedimentary Microfacies subfacies

1380 Grayish green mudstone Grayish brown sandy mudstone Grayish brown fine sandstone

Flaser bedding Lenticular bedding

Grayish brown sandy mudstone

Semi deep Semi deep lacustrine lacustrine facies facies

Dark gray oil shale Gray argillaceous fine sandstone

Grayish brown glutenite

1385

Grayish brown argillaceous medium sandstone and gritstone Grayish brown argillaceous fine sandstone Grayish brown medium and coarse sandstone Grayish brown glutenite Grayish brown fine conglomerate Grayish brown medium and coarse conglomerate

1390

Lenticular bedding Massive bedding

Grayish brown fine conglomerate

Grayish brown fine conglomerate Grayish brown glutenite Grayish brown fine conglomerate Grayish brown glutenite Grayish brown fine conglomerate Grayish brown glutenite Grayish brown fine conglomerate

Channel axis

Scouring surface

Point bar Normal grading bedding Scouring surface Parallel bedding Scouring surface Normal grading bedding Parallel bedding

Channel axis

Gravity flow channel

Grayish brown gravel bearing coarse sandstone

Grayish brown fine conglomerate

Normal grading bedding

Grayish brown glutenite

1395

Grayish brown gravel bearing medium sandstone Grayish brown gravel bearing gritstone Grayish brown sandy mudstone

Grayish brown medium sandstone Grayish brown gritstone Grayish brown fine conglomerate Gray sandy mudstone

Scouring surface

Point bar Channel axis Overflow

Grayish brown gravel bearing medium sandstone Grayish brown fine conglomerate

Grayish brown fine and medium sandstone Grayish brown glutenite

1400 Grayish brown fine conglomerate Grayish brown glutenite Grayish brown fine conglomerate Grayish brown fine conglomerate

Grayish brown medium sandstone Grayish brown gravel bearing medium sandstone and gritstone

Parallel bedding

Normal grading bedding Parallel bedding

Channel Gravity flow axis channel

Graded bedding

Fig. 7.63 Sedimentary microfacies of a core interval of the P Formation from well Baobab N-8

by drilling. We selected representative samples for litho-geochemical analysis based on regional geological research combined with drilling cores and microscopic observations. We successfully restored the protoliths of the non-migmatized metamorphic rocks in the area. Protolith reconstruction of metamorphic rocks included the use of rock mineral methods, petrochemical methods, and geochemical methods. Though dozens of common petrochemical methods can be used for protolith reconstruction of metamorphic rocks, they all produce varying errors. However, if the objective is only to distinguish orthometamorphic rocks from parametamorphic rocks, the error can be as small as 8% (Zhou 1984). In major element analysis using the Nigri value calculation (Simonen 1953; Leake 1969), most samples in the Si–(al+fm)–(c+alk) diagram fall within the range of igneous rocks (Fig. 7.66). The regional metamorphic rocks in the study area are, therefore, generally orthometamorphic rocks. Vandekamp and Beakhouse (1979) used the contents of quartz (Q), feldspar (F), ferromagnesian minerals, and mica (M) in metamorphic rocks to distinguish protolith types. After normalization (Q + F + M = 100), they calculated the percentages of each mineral in each sample and projected them as points onto a ternary diagram to obtain possible protolith types. The mineral contents of two hundred metamorphic

7.3 Main Controlling Factors of Hydrocarbon Enrichment

369

Fig. 7.64 Core photos showing sedimentary structure characteristics in the P Formation of well Baobab N-8

370

7 Geological Features of Hydrocarbon Reservoirs

Fig. 7.65 Typical core images of the P Formation in well Daniela-3

Fig. 7.66 Protolith reconstruction diagram of regional metamorphic rocks (template from Simonen 1953)

7.3 Main Controlling Factors of Hydrocarbon Enrichment

371

Fig. 7.67 QFM diagram (template from VAN de Kamp and Beakhouse 1979)

rock core samples from the Bongor Basin suggest that most protoliths are igneous rocks, predominantly acid, and intermediate rocks with a small proportion of mafic rocks (Fig. 7.67). Lithologies penetrated by drilling in each buried hill show that, as a whole, the Bongor Basin is dominated by migmatitic granite and acid rocks exposed by drilling, with a certain proportion of migmatitic gneiss, gneiss, and intermediate rocks. Basic rocks are only distributed in the Raphia, and Lanea buried hills and have small thicknesses (Fig. 7.68). The lithologic distribution of buried hills in single wells also changes longitudinally, which corresponds with the current understanding. This feature is significantly different from the lithological characteristics of non-sedimentary basement rocks in eastern China. In general, the basement rock of the Bongor Basin is composed of felsic rocks such as granite and migmatite. Long-term weathering during the Cambrian and Jurassic produced relatively developed weathering crust. Early Cretaceous regional transtension led to the development of conjugate open joints on the top of the basement rock, forming a weathering-leaching zone (weathering crust), a fracture development zone, and a semi-filled fracture development zone, and a tight zone. The well-developed weathering leaching zone and fracture development zone contributed to good reservoir physical properties, making the basement rock of the basin a crucial reservoir and exploration target.

372

7 Geological Features of Hydrocarbon Reservoirs

Fig. 7.68 Diagram showing lithologic distribution of buried hills in the Bongor Basin (the top 100 m)

7.3.5 Composite Sandstone-Basement Rock Traps in Uplifts Between Depressions is the Favorable Play for the Formation of Large Oilfields Uplifts between depressions are favorable locations for forming large Oilfields (Fig. 7.69). First, oil sources are available on both sides and in overlying strata; second, two sets of high-quality reservoirs—in the buried hills and the P Formation—are superimposed and developed; third, the combination of early drape anticline and late compressional inversion has produced large amplitude traps; fourth, later uplifting has reduced the burial depth of the oil layers, while retaining a normal or even overpressure pressure system. The pressure coefficient can reach 1.4, with high single-well production (over 1000 t/d). A typical case is the Baobab Oilfield, the largest so far discovered. Other oilfields include the Lanea, Raphia, Mimosa, and Phoenix. The Great Baobab Oilfield is composed of the Baobab C buried hill, with several sandstone oilfields, such as Baobab-1, Baobab S, Baobab NE, and Baobab N, on either side. The Baobab C buried hill has high-yield oil flow and a continuously expanding oil-bearing area, so it is generally inferred that several oilfields have access to the bottom of the P Formation sandstone, and that the oil-bearing formations are stacked vertically and connected in the plane, forming a large oilfield with a total oil-bearing area exceeding 100 km2 .

7.3 Main Controlling Factors of Hydrocarbon Enrichment

373

Cz

K Fm.

M Fm. P Fm.

Heavy oil

Oil

Source rock

Basement

Fault

Fig. 7.69 Hydrocarbon enrichment model of uplifts between depressions

7.3.6 The Northern Slope is the Most Favorable Oil and Gas Enrichment Area The western slope of the Liaoxi Depression in the Liaohe subbasin in the Bohai Bay Basin contains 71.1% of the proved geological reserves in the Western Depression. This slope zone hosts Middle-Upper Proterozoic metamorphic rock buried hills and Paleogene sandstone oil reservoirs and is also rich in heavy oil (Qiu and Gong 1999). The Bongor Basin has three play fairways: slope zone, depression zone, and steep slope (Figs. 7.70 and 7.71). The steep slope hosts small compressional anticline reservoirs, mostly in the K and R Formations. These two formations have experienced rapid change and are predominantly interbedded sand and mud, with limited reservoir thickness. The sources of oil and gas are mainly in the deeply buried mature-highly mature M Formation, with a high GOR. The Mango and Delo Oilfields are examples. The oil-bearing formations in the Pera and Vitex Fields are also thin. The slope zone has abundant oil and gas resources in Precambrian buried-hill oil reservoirs and Lower Cretaceous sandstone oil reservoirs, which provide more than 90% of the proven geological oil reserves in the basin (Fig. 7.70). Unlike the Western Depression in the Liaohe subbasin, the northern slope of the Bongor Basin has no heavy oil reservoirs. However, the area still has great exploration potential, particularly in buried hills. Abundant oil in slope areas is uncommon in CARS. Oil enrichment in the northern slope of the Bongor Basin may result from the specific geological environment during its geological history. In the early formation stage of Bongor Basin, the northern slope was not a simple slope but the center of both sedimentation and subsidence, and a series of oil-generating sag developed. The basin was then inverted at the end of the Late Cretaceous as the southern boundary

374 Age

7 Geological Features of Hydrocarbon Reservoirs Reserve distribution

0.5 0

Steep slope zone

Depression zone

Northern slope zone N

Cz

E B Formation R Formation

K21 K Formation

M Formation

K11

P Formation

Angular unconformity

Fault

Condensate reservoir

Heavy oil reservoir

Reservoir

Basement

Fig. 7.70 Hydrocarbon accumulation model of the Bongor Basin

0

50km Uplift

Fault

Basement rock uplift Oil field 1 3 4

2

Location of Figure (b)

6

5

7

8

10 9

Lower Cretaceous sandstone oilfield 1 Ronier 2 Mimosa 3 Baobab 4 5 Raphia 6 Daniela 7 Lanea 8 Lanea E 9 Mango 10 Delo

Phoenix a

0

Baobab C Oilfield

2

4

6km

N

Baobab C 2 Baobab C

Baobab C 5 Mimosa 9

Phoenix S BA

Mimosa 10

Phoenix S 8 Phoenix S 11

Mimosa E 1

Mimosa E Oilfield

Phoenix S 3 Mimosa E 2

Phoenix S 10

Phoenix S Oilfield

Raphia S Oilfield Lanea E 2 Lanea E 4

Lanea E Oilfield b

Oil

Fault

Lanea SE 1

Well location

Fig. 7.71 Diagram showing distribution of oil and gas fields a and buried-hill Oilfields in the northern slope b of the Bongor Basin

References

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fault rotated. During this process, the strata of the northern slope suffered large-area uplifting and denudation. Therefore, the sedimentation of the northern slope covered a much wider area than the residual portion today. The boundary of the primary basin has been calculated to have extended 10 km further north than the boundary of the current basin. The present northern slope may therefore be a slope break zone formed during the deposition of the P and M Formations, with the original coarse facies belt uplifted and denuded. The present northern slope is a source rock development area, overlying the early P Formation fan and forming a superior ‘upper source and lower reservoir’ type play, which is favorable for hydrocarbon enrichment. Later compressional inversion resulted in the re-migration and re-accumulation of oil and gas, forming the row of oilfields that have now been discovered.

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Chapter 8

Seismic Reservoir Prediction Technology

In recent years, reservoir prediction has evolved into a new discipline, integrating physics, mathematics, computer technology, and rock physics. Continuous developments in science and technology, particularly electronics, instrumentation, and algorithms, have dramatically improved the accuracy of seismic exploration. Characterization of diverse geological phenomena is constantly improving as a result, and the accuracy of reservoir prediction is increasing. The Bongor Basin has been affected by multi-stage tectonic movements and changes in stress fields at different stages in its evolution. Faults with a variety of structural types are particularly common. Moreover, due to the changeable sedimentary environment and provenance from multiple directions, lithology, and lithofacies vary greatly within short distances, so there is strong heterogeneity and diversity of trap and reservoir types, making reservoir prediction a challenge. However, pre-drilling reservoir prediction in crystalline basement rock is a problem that is not unique to the Bongor Basin; it is faced worldwide (Petford 2003). Conventional 3D seismic and ‘wide-azimuth, broadband and high-density’ 3D seismic data acquisition and processing provide a sound basis for characterization of thin sand layers, prediction of lithological sandstone bodies, and prediction of basement rock reservoirs in areas of igneous rock intrusion in strongly inverted rift basins (Hillis 1995).

8.1 Inversion Technology for Identifying Thin Sandstone Reservoirs in Areas with Igneous Rock Intrusions Due to changes in the types of sedimentary basins in diverse periods and the influence of multi-phase inversion structures, strongly inverted rift basins can be divided vertically into several distinct formations. The Bongor Basin is divided (from top to bottom) into the B Formation, the R Formation, the K Formation, the M Formation, the P Formation, and the basement rock. Faults in the basin, thin sand bodies in the K Formation, rapid lateral changes, strong heterogeneity, late inversion, and © Petroleum Industry Press 2023 L. Dou et al., Petroleum Geology and Exploration of the Bongor Basin, https://doi.org/10.1007/978-981-19-2673-0_8

379

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8 Seismic Reservoir Prediction Technology

complex history of tectonic movements and associated magmatic activity all combine to increase the difficulty of reservoir prediction (Chen et al. 2012). All currently available inversion technologies are deployed and implemented in the basin. It is essential to select the most practicable methods and appropriate sets of parameters for relative amplitude fidelity processing, analyzing relationships between seismic trace and well log data from the various formations, and performing accurate migration imaging. Reasonable reservoir prediction results can be obtained as long as adequate preliminary research has been carried out. As an example of the process, we will describe the application of inversion technology in thin sand layers in igneous rock intrusions to determine the distribution of favorable sand bodies in the area of well Ronier-4. Igneous rock intrusions in the Ronier area make stratigraphic correlation difficult. The interpretation shows various thicknesses of strata on either side of the fault block in the area due to a translayer of igneous rock. The igneous rock has strong seismic reflection properties, shielding the underlying sandstone strata from seismic signals, so the reflection of the sandstone is not obvious on the seismic profile. We used logging and mud logging curves to effectively apply seismic technology in these complex geological conditions carefully selected the correct marker bed, and calibrated the igneous rocks and faulting points with the maximum possible accuracy (Tan 1987). We then painstakingly carried out time-depth calibration and applied various geophysical methods to interpret seismic-geological horizons finely. Fine interpretation of geophysical logging allowed correction and normalization of the logging curves. Sparse spike inversion was used for reservoir prediction, with perspective igneous rock technology being applied during processing to eliminate the influence of igneous rocks on the reservoir inversion as far as possible.

8.1.1 Fine Interpretation of Complex Fault Blocks The Ronier area is impacted by a regional tectonic stress field, which manifests as a superimposition of multi-stage structures. Strike-slip-extension occurred in the early stage, forming a series of extensional structures. In the late stage, the formation underwent reversal, with reactivation of the early fault due to compression. Faults are therefore developed, and the quality of seismic data is normal. Analysis suggests that the igneous rocks are late intrusions that destroyed the original sedimentary layer, making it challenging to identify the sand body from seismic data. Interpretation techniques accordingly focus on the following three key points. First, logging is the main method for fine stratigraphic correlation. Interpretation is based on horizon division, faulting point location, and fault throw (Fig. 8.1). Second, wavelet reconstruction technology is the principal interpretation method for eliminating the influence of igneous rocks and for fracture reprocessing (Achiat et al. 2009). Third, fine descriptions of structural shapes include time-depth calibration. The difference between this and previous calibration methods is that igneous rocks’ particularity is considered a marker. At the same time, data processing is calibrated with reference to faulting

8.1 Inversion Technology for Identifying …

381

points to determine the longitudinal distributions of reservoir groups. During interpretation, reference to drilled faulting points allows accurate homing of the hanging walls and footwalls of faults. The framework for reservoir inversion is established by the application of interpretation techniques such as coherence cubes, time slices, and three-dimensional perspective to accurately determine the locations of faulting points, combine all types of faults, and thus carry out fine structure interpretation of complex fault blocks. Fine interpretation reveals that the Ronier structure is a small dome complicated by faults, with apparent structural disparities between its deep and shallow layers.

8.1.2 Distribution Characteristics of Igneous Rocks Igneous rocks can be observed on both logging and seismic curves. The logging curves, they are characterized by high resistivity, low gamma, low acoustic interval transit time, and high density. They are mostly characterized by strong amplitude and low frequency on seismic profiles, which are obviously different from the surrounding rock. There is no overlapping between the igneous rocks and surrounding rocks. The igneous rock upwells along fracture channels and moves concordantly, characteristic of late intrusion (Cuong et al. 2009). In the plane, igneous rock occurs on a large scale across the fault zone, distributed in multiple strata longitudinally, mainly in the upper part of the R Formation and the lower parts of the K and M Formations (Fig. 8.2).

8.1.3 Reservoir Inversion in Strong Development Areas of Igneous Rocks Analysis of Geophysical Differences in Lithology in the Work Area Analysis shows significant differences between the wave impedance values of igneous rocks and those of sandstones and mudstones in the area (Fig. 8.3). These disparities in wave impedance values can be used to perform reservoir inversion. After first eliminating the influence of igneous rocks, geophysical methods can be used to distinguish between sandstone and mudstone, thus achieving the prediction of sandstone and mudstone, as well as the igneous rocks. Nevertheless, analysis of actual acquired data shows that igneous rocks produce strong reflections on seismic profiles, which shield the reflections of underlying strata (Koning 2003). The underlying strata have weak reflection energy, so the inversion effect is unsatisfactory. In response to this, we separately identified the strong reflections of igneous rocks and removed them from the profile of the work area. Reservoir prediction was then achieved by conducting interbed analysis and inversion.

0.2

0.2

0.2

a Well Ronier 4 1

Ronier 4 1 AT10  m 200 1.84 AT20  m 200 AT90  m 200

GR

R4

API 190.48

988m

R4

1441m

1060

1050

1040

1030

1020

1010

1000

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980

967.5

Depth m

1070

GR

API 166.07

1076.3 b Well Ronier 4

AT90 4.7800 AT20 4.6720 AT10 4.6260

Ronier 4 AT10  m 200 1.03 AT20  m 200 AT90  m 200

1060

0.2

0.2

0.2

1066.3

1050

1040

1030

1020

1010

1000

990

977.78

970

957.5

Depth m

Fig. 8.1 Stratigraphic correlation of the Member IV of R Formation of wells Ronier 4; Ronier 4–1 and Ronier 6

1089.3

1080

1070

1060

1050

1040

1030

1020

1010

1000

990

980.5

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0.2 0.2

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AT10  m AT20  m AT90  m GR

R4

API 180.78

382 8 Seismic Reservoir Prediction Technology

8.1 Inversion Technology for Identifying …

383

Fig. 8.2 Magma channels in the Ronier Oilfield

140

GR (API)

120 100 80 60 40

Sand and mudstone

Igneous rock

20 2

106

4 106

6 106

8 106

10 106 12 106 14 106 16 106 18 106 20

106 22 106

3

Impedance[(kg/m ) (m/s)]

Fig. 8.3 Impedance versus GR of igneous rocks

Principle and Steps of Strong Reflection Separation Mallat et al. first proposed the matching pursuit algorithm in 1993. This algorithm is used to amplify sparsely represented signals in over-complete dictionaries. Adapting the concepts of the matching pursuit algorithm, if the optimal sparse representation dictionary can be found and the strong reflection information in the seismic signal is

384

8 Seismic Reservoir Prediction Technology

matched, the shielding effect on the target’s reflection can be eliminated. There are eight steps in applying the algorithm: Step 1: The sparse dictionary D = [ϕ1 ,…,ϕk ] is determined based on the seismic data (the dictionary is the wavelet library of different frequencies and diverse amplitudes). The sampling number for each atom (atoms are individual wavelets) ϕk is N. Step 2: NT is set as the total number of seismic traces. Step 3: Read the ith seismic record χ. The sampling number in the trace is N. Step 4: The sparse representation coefficient (projection coefficient) α1 = α2 = … = αk = 0 is initialized. ϕk  , kmax = argk max|αk | Step 5:αk = x, ||ϕk ||22 Step 6: Remove the strong reflection x = x − ϕkmax αkmax . Step 7: The number of seismic trace I is set to be i = i + 1. Step 8: If i > NT, end the calculation, otherwise return to step 3. Actual Effect Analysis Accurate prediction of thin sand reservoirs is a global problem. The currently available resolution of seismic data means that it is often impossible to achieve the desired accuracy. Methods to counter this (such as seismic sedimentology) are constantly being developed and improved, but still need to be improved. Through comprehensive analysis of actual well data, we established the sequence stratigraphic framework of the area, carried out single-well sedimentary facies analysis based on logging and coring data, and established a sedimentary facies model for the work area. Finally, we performed inversion on the seismic volume with the strong reflection of the igneous rock removed (Fig. 8.4). Figure 8.4 a is the original seismic profile with strong igneous rock reflection at 1000 ms. Figure 8.4b shows the seismic reflection profile without the strong reflection of the removed igneous rock. The signal energy is balanced, and reflections from the igneous rock are enhanced. The reservoir group was infilled and interpreted based on this processed seismic profile. Figure 8.5 shows a statistical analysis of various seismic attributes in different time windows. The results of reservoir prediction using the unprocessed profile suggest that the igneous rock has the characteristics of submerged reservoirs. Figure 8.5b shows the results of reservoir prediction using the processed profile. The reflection of the igneous rock is still clear, but the underlying sandstone reservoir is also clearly reflected. This confirms that the inversion results of seismic profiles are much improved by removing the strong axis. By combining and comparing the results with the reflection characteristics of the thin sand layer of the reservoir group confirmed by drilling, we carried out reservoir prediction and analysis to determine the plane distribution of favorable sand bodies. The results show that the upper oil group’s main sedimentary types in the Bongor Basin’s northern margin are channel belts and floodplains. The primary sedimentary types of the middle oil group in the northern margin of the Bongor Basin are fan delta and turbidite fan deposits. The high-quality reservoirs of the upper oil group are distributed in the fluvial-delta sedimentary system in the Ronier-1 well field

8.1 Inversion Technology for Identifying … Ronier 6

Ronier 4 1

Ronier 6

Ronier 4 1

385 Ronier 4 2

Ronier 4 3

700 800

TWT (ms)

900 1000 1100 1200 1300 1400 (a) Original seismic profile Ronier 4 2

Ronier 4 3

700 800

TWT (ms)

900 1000 1100 1200 1300 1400

(b) After removing strong reflection of igneous rocks

Fig. 8.4 Comparison of the original seismic profile and the seismic profile after removing the strong reflection of igneous rocks

(Fig. 8.6). The high-quality reservoirs of the middle oil group are distributed in the delta sedimentary system in the Ronier-4 well field (Fig. 8.7). Analysis of multiple attributes confirms that wave impedance inversion offers the optimum effect for reservoir prediction. Fine prediction results from the target area show that the K Formation reservoirs in the Ronier-4 well field are fan-shaped on the inversion plane, with a north-to-south provenance. The Ronier-1 well field changes with time on the planar graph. The results confirm that it is a channel sedimentary system that has experienced varying development characteristics in distinct periods.

386

8 Seismic Reservoir Prediction Technology Ronier 6

Ronier 4 1

Ronier 4 2

Ronier 4 3

Ronier 4

1000

1050

TWT (ms)

1100

1150

1200

1250

1300 (a) Reservoir inversion before processing Ronier 6

Ronier 4 1

Ronier 4 2

Ronier 4 3

700 800

RIV

RIV

TWT (ms)

900 1000 1100

KJ KJ KII KII

1200 1300

KIII KIV

KIV

PIMP

1400

6500 7000 7500 8000 8500 9000 9500 10000

(b) Reservoir inversion after processing

Fig. 8.5 Comparison of the original seismic profile and the profile of reservoir inversion after removing the strong reflection of the igneous rock

8.2 Characterization of Fan Body Boundaries Against High and Steep Backgrounds in Small Rifts Rapid rifting during the initial rifting of the Bognor Basin formed numerous deep and steep small depressions. In this early stage, these small depressions were filled with thick layers of proximal glutenite bodies, overlying thick layers of dark mudstone. Due to their great thickness, there are slight differences in the background seismic characteristics of the sandbodies and the mudstone, so the sandbodies are challenging to precisely define. Compression and inversion during the Late Cretaceous ‘shortened’ the early rift significantly (the local shortening rate was 10–35%) and the top stratum was eroded by over 1000 m. The imaging quality of seismic data of the two limbs of the small residual rift (area less than 100 km2 ) is poor under a high-angle (about 45°) monoclinic background, and the responses of sandbody

8.2 Characterization of Fan Body Boundaries …

387

Quartz, calcite, dolomite Reuss Voigt Hill Matrix

Fracture/dissolved pore DEM

Crack/ dissolved matrix

Clay/organic matter DEM

Clay + fracture/ dissolved matrix

Matrix pore

DEM Dry rock

Fluid Gassmann Fluid-saturated rock

Fig. 8.6 Modelling procedure of rock physics 100 Baobab N 10:GR:MI MII Baobab NE 2:GR:MI Baobab NW 1:GRNRM:MI MII Baobab NE 22:GRNRM:MI MII

90 80 70

50 40 30 20 10 0

20

40

60

80

100

Normalized Gamma

120

140

160

180

0 200

API

Fig. 8.7 Normalized results of the density curve of the M Formation in the Baobab N area

Frequency

60

388

8 Seismic Reservoir Prediction Technology

boundaries are fuzzy. Due to differential compaction, the M Formation mudstone experienced seismic creep. The seismic data show ‘lumbricoid’ reflection characteristics, affecting the underlying strata’s seismic imaging and making reservoir prediction difficult. To counter the challenges to interpretation presented by the possible development of lithologic oil and gas reservoirs in the Baobab N Subdepression, frequent lateral variations in reservoirs, and uneven distribution in the vertical direction, we quickly determined the sedimentary facies of the area using core observation, single-well sedimentary facies analysis, and well tie comparison, guided by sequence stratigraphy and based on drilling data. Constrained by the fine stratification, we conducted fine interpretation of the complex fault blocks using fine horizon calibration. To do so, we used coherence cubes, time slices, zoom displays of seismic profiles, and other technologies to lay a firm foundation for reservoir prediction. Moreover, guided by fine layer interpretation and sedimentary facies, we developed a research method—using seismic facies, frequency-division and conventional seismic attributes, reservoir prediction, and a three-dimensional perspective—to determine the planar and vertical distribution of the sandbodies. Combining the results from this method with existing understandings of the sedimentary facies and reservoir-forming characteristics of the area, we were able to quickly determine the optimum lithological target and provide a drilling well location. Characterization of the ultra-thick fan body in Baobab north illustrates the use of this method.

8.2.1 Stratigraphic Sedimentary Characteristics The P and M Formation sandbodies in the Baobab North area are subdivided into four layers: (1) PIII is the lowermost deposit in the subdepression. Mud logging shows that it is predominantly mudstone and siltstone above the basement rock, and logging is characterized by a slender neck shape with high gamma and low resistivity. The formation lay directly on the basement rock and was deposited in the initial rifting stage. The seismic reflection is characterized by low frequency, discontinuity, low energy, base lap, truncation, Etc. (2) PII is above PIII . Mud logging indicates that it is dominantly mudstone intercalated with siltstone and fine sandstone. The seismic reflection is low-frequency, medium-continuity, and medium-amplitude. (3) PI is above PII . Mud logging indicates that it primarily comprises conglomerate, pebbled gritstone, and gritstone. The logging curve is box-shaped, with low gamma and high resistivity, and the seismic reflection is characterized by medium frequency, medium continuity, and strong amplitude. This layer is the main reservoir in the area.

8.2 Characterization of Fan Body Boundaries …

389

(4) MIII is mainly thick mudstone intercalated with thin, fine sandstone. Logging curves show that the formations above and below the base top have high resistance, high density, and low acoustic interval transit times. The MIII has occasional finger-like low gamma and high resistivity against a general background of high gamma, low resistance, low density, and high acoustic interval transit times. The seismic facies shows medium frequency, high continuity, medium– high amplitude, and parallel layers. This layer is the second reservoir in the area

8.2.2 Analysis of Petrophysical Characteristics of Reservoirs Optimal Logging Evaluation of Multiple Pore Structures In evaluating reservoirs with complex pore structures, it isn’t easy to obtain stable interpretation results from calculating a single curve. The optimization method we applied uses the nonlinear weighted least-square method to resolve the rock volume model. The inputs include gamma, density, neutron, and other conventional logging data, which comprehensively reflect the response of multiple logging curves to the pore structure and consider each logging curve’s measurement error (Table 8.1). The key to achieving the optimum solution is high-quality initial data input, so pre-interpretation of pores is indispensable. Density and neutron curves often reflect the total porosity of the rock, the acoustic interval transit time curve reflects matrix pores of reservoirs, and dual lateral resistivity reflects fracture pores (Nur et al. 1998). Petrophysical Modeling of Multiple Pore Structures The key to petrophysical modeling of multiple pore structures lies in treating the elastic responses of diverse pore types. Matrix pores are primary pores, while fracture and dissolution pores are secondary pores, which develop in matrix minerals other than clay and organic matter. The width to length ratios of the pores is used to distinguish the different types. The petrophysical modeling process consists of five steps: (1) the Reuss-VoigtHill petrophysical limit theoretical method is used to treat matrix minerals such as quartz equivalently; (2) the differential equivalent medium model (DEM) is used to add fracture and dissolution pores into the matrix; (3) DEM is further used to add fillers such as clay and organic matter; (4) DEM is then used to add matrix pores; (5) finally, the Gassmann equation is applied to replace dry rock with fluid to simulate the elastic characteristics of saturated rock (Fig. 8.6). Case Study We conducted logging evaluation and petrophysical modeling of the high-porosity sandstone reservoirs and mudstone formations of the P Formation in the Baobab N area.

2.78

0.23

0.20

0

0

DEN (g/cm3 )

CN

DT (μs/ft)

Dissolution porosity

Fracture porosity

0.05

2.71

0 0

0.01

0

0

1 × 10–5

0.02

0.03

0

1 × 10–5

0.01

0.02

0.03

0.05

0.05

Error

Matrix

0.05

Error

Matrix

1.00

Calcite content

Clay content

GR (API)

Logging curve

Table 8.1 Parameters of optimization logging interpretation model

0

0

0

0.01

2.87

0

Matrix

1 × 10–5

0.01

0.02

0.03

0.05

0.05

Error

Dolomite content

0

0

1.00

1.00

1.00

0

Matrix

1 × 10–5

0.01

0.02

0.03

0.05

0.05

Error

Matrix porosity

0

1.00

0

1.00

1.00

0

Matrix

1 × 10–5

0.01

0.02

0.03

0.05

0.05

Error

0

0

0

1.00

1.00

0

Matrix

1 × 10–5

0.01

0.02

0.03

0.05

0.05

Error

Dissolution porosity Fracture porosity

390 8 Seismic Reservoir Prediction Technology

8.2 Characterization of Fan Body Boundaries …

391

Quality Control and Correction First, we conducted the quality inspection and quality control of the logging data, including analysis and correction of acoustic interval transit times and density curves. According to the requirements of formation evaluation and petrophysical modeling, we conducted inspections and quality control on the petrophysical parameters of the formation, such as mineral content and porosity, including: (a) Data availability for inspection and quality control; (b) Data editing, including supplementing missing segments, eliminating spikes, etc. (c) Bad borehole correction; (d) Standardized processing; (e) Inspection of consistency between multiple wells. It is necessary to edit poor-quality logging curves, particularly density and acoustic interval transit time curves during quality control. These curves are the basis for establishing the relationship between logging data and seismic data, so high quality is vital. During editing, it is essential to use good-quality well sections and multiple regressions to calculate the optimal logging response to replace poor-quality logging data in other well sections. According to the requirements for the selection of key wells, we selected the most appropriate well for multi-well standardization inspection and processing. During the standardization process, we used histograms and cross plots to standardize the geological horizon of the target well (Fig. 8.7), and the processed results were used for reservoir prediction. Lithology Identification and Analysis of Response Characteristics The purpose of lithology identification is to determine rock types, as the correct understanding of the rock and mineral composition of the formation is the basis for subsequent petrophysical modeling. Drilling in the Baobab N area has confirmed the presence of sandstones and mudstones. The compaction degree of the mudstones does not change significantly with depth, so compaction correction is unnecessary. In the petrophysical analysis of reservoirs, the lithology of each well is divided into two types, and the contents of the various minerals are calculated according to the logging curve, laying the foundation for subsequent reservoir prediction (Figs. 8.8 and 8.9). Targeted Reservoir Prediction Technology To determine the seismic stratigraphic characteristics of the area, we developed a new reservoir prediction technology; “frequency division attribute to fix the target point, three-dimensional perspective to fix the boundary, and reservoir inversion to fix the thickness”. In the sequence stratigraphic framework and under the constraints of sedimentary facies, we optimized various techniques to carry out joint prediction and evaluation of reservoirs.

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8 Seismic Reservoir Prediction Technology

Fig. 8.8 Compaction curve of the Mimosa Formation mudstone

Frequency Division Attribute Technology Time–frequency analysis technology is a method for transforming time-domain data into frequency-domain data for analysis. Commonly used methods include Fourier transform and wavelet transform. The geological reason is that frequency domain data can be used to identify differences in the scales of geological bodies. The average velocity of the P Formation in this area is about 2400 m/s, and the thickness of a single sand set is about 20 m. The 30 Hz attribute body can effectively identify this geological body (Al-Chalabi 2002). The main frequency of seismic data in the study area is 25 Hz, within a frequency band of 10–60 Hz. The reservoirs of the P Formation show strong reflections on the seismic profile. The energy characteristics change markedly in the Baobab N Subdepression, from well Baobab N-5 in the east to well Baobab N-6. Wells Baobab N-5 and Baobab N-7 are in areas with weaker energy levels, consistent with the reservoir characteristics revealed by well tie comparison. Wells Baobab N-2, Baobab N-3, and Baobab N-6 are in the same depositional unit. Although the reflection of the

8.2 Characterization of Fan Body Boundaries … Top of horizon

COR

5

in

15

100

Bit size 5

in

mV

Resistivity

DT

SP

Well diameter

m

15 70

gAPI

NDS

0.2



m

200 0.6

TVR3 0.2

150

 m

ONL

Neutron

TVR2

Depth 50

GR

200 230

s/ft

doc

Shale content

doc

100 0

1 0

VOLHD 30 0

STATMIN

DT

VCLSO 0 0

DT

Sand content

1 0

100 0

VCLAT

VQUA

393

1 10

VCLGR

SW

POR PORT 1 0.1

SW

mV POR

0.3 0

V/V

30 0

V/V

doc

VCLGR

3

g/cm

3 1000

RHOM 1 2

3

g/cm

VCLGR

VP

RHOZ 1 2

SW_S

t/s

3 1000

VCLGR

3000 2000 t/s

NPVS 14000 1.4

PINPM

VSM 7000 0

VCLGR

FIMP

[VS] 7000 0

VPN

3000 2000

t/s

2.4 VPVSM

14000 1.4

None

2.4

N11 1438 1450

1500

1550

P 1584

1600

1650

1700 P 1720

1750

1800

1850

1900

1950

2000

P 2050

2050

Fig. 8.9 Optimized interpretation results of sandstone content in well Baobab NE-22 in the Baobab N Subdepression

oil layer is weak, it does not affect the prediction of multiple surrounding sedimentary sandbodies. A total of eight target sandbodies—identified as A–H—were interpreted (Fig. 8.10). Sculpture Technology The stratigraphic interpretation was performed on the isochronous sequence interface and the three-dimensional time window using the fusion of wave impedance and amplitude information. We could adjust and change the color, transparency, and other parameters for each data volume. In the same window, daughter tracking, horizon-oriented sculpture, fault sculpture, and other types of processing could be carried out simultaneously, and the reservoir body could be rapidly identified. We maximized the advantages of comprehensive interpretation of multiple data volumes by studying the shape and internal structure and identifying the deposition mode of the reservoir body. Sand body sculpture of MIII , PI u , PI l , and other formations (Fig. 8.11) was carried out using this method.

394

8 Seismic Reservoir Prediction Technology

Fig. 8.10 Prediction of favorable sandbodies with frequency division attributes of the P Formation in the Baobab N Subdepression (30 Hz frequency volume)

Fig. 8.11 Sand body prediction map showing a three-dimensional perspective of the P Formation in the Baobab N Subdepression

8.2 Characterization of Fan Body Boundaries …

395

Seismic Inversion Technology Figure 8.12 is a wave impedance-constrained sparse-pulse inversion profile through the Baobab NE oil reservoir. It clearly shows the reflections of the four sandbodies at the top of the P Formation of well Baobab NE-1. These sandbodies have high impedance (against a general background of low impedance) and become thicker towards the north. However, there are fewer oil layers due to the relatively low structural position of well Baobab NE-2. Overall, the inversions of wave impedance and the variation trend of reservoirs revealed by drilling are consistent, with the constrained sparse pulse inversion results accurately reflecting the vertical and horizontal changes in the reservoir. Generally, this method only performs iterative inversion for large events, is limited by the seismic frequency band and has a poor vertical resolution. In this case, identifying large sets of sandbodies in the P Formation was achieved with high vertical and horizontal resolution. Figure 8.13 (the plan of inversion data extraction) shows that the inversion results reveal the distribution direction and range of the fan delta sandbodies on the northern slope of the Subdepression. Analysis of the Distribution Characteristics of Sedimentary Systems

TWT ms

Combining this seismic amplitude perspective with statistics of sandstone thickness in drilled wells indicates that sedimentary distribution in the area is generally characterized by the independence of the sandbodies in the plane. The sandbodies are distributed north–south direction, with the northern provenance as the main source, supplemented by the southern provenance. The distribution of individual sandbodies has a certain degree of inheritance in the vertical direction. PI l is mainly composed of gritstone-medium sandstone (Fig. 8.14), with the lithology of PI u sandstone being relatively coarse and its distribution range the widest. The MIII sandstone is thin, medium sandstone-fine sandstone with a limited distribution range. 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500

B SE 1

B E 2

P Basement P

B C 5

P P Basement

B NE 1 B NE 2 B N 11

B N1 8

N 1 B N1 1 P P

P P

P P

P P Basement P

P P P

P

P

P

Basement

P 9000

Basement

8500

Basement

8000

Granite

7500 7000

Sandstone

6500 6000

Shale

5500 5000

Fig. 8.12 Inversion profile of wave impedance through well Baobab NE-1 to well Baobab N-1

396

8 Seismic Reservoir Prediction Technology

Fig. 8.13 Overlay of the structure and the thickness of the sandstone in the P Formation in the Baobab N Subdepression

Fig. 8.14 Distribution of sedimentary sand bodies of the PI l sand group in the Baobab N Subdepression

8.3 Reservoir Prediction Technology for Basement Rock Buried Hills

397

8.3 Reservoir Prediction Technology for Basement Rock Buried Hills The basement rock buried hills of the Bongor Basin are mostly in the Northern Slope. Regional tectonic movements and structural frameworks control formation and distribution of buried hills (Dou et al. 2015). The buried hill belts are associated with major regional faults, impacting the shape and distribution of local buried hills (Hu et al. 1981). The section is generally steep, with the dip angle usually above 50°. The faults control buried hill trap amplitude, scale, and plane distribution. The buried hills show considerable differences in area, shape, and amplitude, and their reservoir development and preservation degrees vary. For example, the Baobab C buried hill, the Mimosa buried hill, the Phoenix buried hill, and the Raphia buried hill are all controlled by WNW–trending north-dipping faults consistent with the overall basin strike, whereas the Lanea E buried hill is controlled by a near–EW–trending southdipping fault. Controlled by the formation and variations in the fault system, the plane distribution of buried hills is in line with a striped mountain-mountain system (Fig. 8.15).

8.3.1 Research of Seismic Forward Modeling Seismic forward modeling provides a basis for selecting optimal buried hill reservoir prediction technologies and determining related parameters. It can also test the rationality and reliability of reservoir evaluation and prediction results. It, therefore, has a role as a connecting link, promoting all areas of work by drawing upon and sharing experience gained on key aspects. Chapter 5 proposes a classification scheme for basement rock buried hill reservoirs based on geological origin, establishes a development model for the sequence of basement rock reservoirs, and summarizes the seismic response characteristics of

0

C Buried hill

Prosopis Buried hill Baobab C Buried hill Daniela Buried hill

Top depth of bed rock m

Ronier Buried hill

300

10km

Mimosa Phoenix Buried hill Raphia Buried hill

970 2250 3840 4800

Fig. 8.15 Distribution of buried hills in the Northern Slope of the Bongor Basin

Lanea E Buried hill

398

8 Seismic Reservoir Prediction Technology

different reservoir types. In addition to drilling verification, seismic forward modeling offers an economically feasible theoretical analysis and demonstration approach for verifying results and has the added benefit of suitability for wide understanding and application. Figures 8.16 and 8.17 are the seismic profiles, geological interpretation results, and synthetic seismic forward modeling profiles of the Baobab C and Phoenix buried hill zones, respectively. The simulated seismic records of the reservoirs in sections A and B show medium-strong amplitude with good continuity in the inner buried hill while displaying weak amplitude reflection with poor continuity in section C (the semi-filled fracture-developed zone) and section D (the tight zone). This is in line with the actual seismic data, confirming that the geological interpretation profile accurately reveals the vertical superimposition and lateral change characteristics of the reservoir. Similarly, in the weathering and leaching zone and the fracturecavity zone, the reservoirs in the Mimosa and Lanea buried hill structural zones present medium-strong amplitude reflections with favourable continuity on both the actual seismic and forward modeling profiles, indicating that high-quality reservoirs are widely distributed and have stratiform and stratiform-like characteristics. The reservoirs in the Phoenix buried hill in the zone are primarily distributed in the higher part of the buried hill, where the shape is relatively gentle. They may be welldeveloped at the toe of the slope but underdeveloped in the steeply inclined part of the middle section of the slope.

Fig. 8.16 Synthetic seismogram from seismic forward modeling of a platform-type buried hill (well Baobab C-2) a weathered and leaching zone, b fractured-cavity developed zone, c semi-filled zone, d tight zone

8.3 Reservoir Prediction Technology for Basement Rock Buried Hills

399

Fig. 8.17 Synthetic seismogram from seismic forward modeling of a spike-type buried hill (well Phoenix-3) a weathered and leaching zone, b fractured-cavity developed zone, c semi-filled zone d tight zone

8.3.2 Seismic Prediction Technology for High-Quality Reservoirs High-quality reservoirs in granite basement rock buried hill in the Bongor Basin are found in the weathering and leaching zone, and the fracture-cavity developed zone on the upper part of the basement rock buried hill. This is the principal enrichment zone for reserves, and the main pay zone of the basement rock buried hill. Drilling has revealed that the high-quality reservoirs are mainly in a 200 m well section in the upper part of the buried hill and show stratiform-like characteristics. On the seismic profile, the weathering and leaching zone, and the fracture-cavity developed zone are characterized by continuous strong low-frequency amplitude reflections. In the relatively gentle part of the buried hill, strong low-frequency amplitude reflections are obvious, indicating that high-quality reservoirs are generally present in basement rock buried hills. However, the development location is comparatively unusual, and the degree of development is greatly affected by the ancient landform of the buried hills. These characteristics provide a basis for developing a technical process for predicting and evaluating high-quality reservoirs, combining and optimizing calculation methods, and determining parameters (Sneider et al. 1977). Acquisition of seismic data with high signal-to-noise ratios, high fidelity, and all-azimuth observation with ‘wide-azimuth, broadband, and high-density’ in the Bongor Basin offers advantages in enabling the multi-attribute fusion of multiple disciplines (geology, seismic exploration, logging, paleogeomorphology) and multiple data sources (structure, seismic data, logging, drilling, and reservoir engineering). This provides a firm

400

8 Seismic Reservoir Prediction Technology

basis for research and development, optimization of reservoir prediction techniques, such as seismic inversion, and the design and deployment of improved technical processes. Technical Process for High-Quality Reservoir Prediction Reservoir identification and prediction accuracy depend on data quality and effective use. For high-quality reservoir prediction, we applied seismic data with ‘wideazimuth, broadband and high-density’, core data, logging data, well testing and early production test data, ECS, FMI, and other specialized logging data (Nelson RA 2008). This supported the optimization of effective technologies, the development of new targeted technologies, and the completion of reservoir prediction and evaluation (Nelson et al. 2000). Combining this data-driven approach with an understanding of geological problems and technical issues, we formulated a technical process for predicting and evaluating high-quality reservoirs in basement rock buried hills (Fig. 8.18). Time–frequency domain interpretation was applied in addition to conventional seismic attribute analysis for high-quality reservoir prediction in basement rock buried hills. We significantly improved the gradient algorithm technique of amplitude spectrums and developed an attribute fusion technique based on buried hill landforms. These technologies are highly beneficial for predicting and evaluating basement rock buried hill reservoirs. Key Technologies for Reservoir Prediction and Evaluation We used time–frequency attribute analysis to study reservoir parameters and changes in their seismic attributes in both the time and frequency domains. This technology can be used independently or in combination with other methods to predict the plane distribution of reservoirs and evaluate their properties.

Fig. 8.18 Flow chart of prediction technology for high-quality reservoirs in basement rock buried hills

8.3 Reservoir Prediction Technology for Basement Rock Buried Hills

401

Spectral Decomposition Technique Mathematical methods such as Discrete Fourier Transformation and maximum entropy are used to mathematically transform seismic data from the time domain to the frequency domain and form a series of discrete single-frequency and amplitude seismic data volumes. Combined with spectrum analysis of seismic data from the developed areas of the buried hills, we compared and analyzed variations features of reservoir thickness, reservoir type and their composite relationships in seismic responses in a dual-frequency volume to determine the sensitive frequencies (tuning frequencies). This provided a basis for optimizing seismic techniques for predicting reservoirs (Morlet, 1982; Partya, 1999; Marfurt, 2001). In low-frequency seismic data with ‘wide-azimuth, broadband, and high-density’, the responses of high-quality reservoirs show medium–low continuity and mediumstrong amplitude (Fig. 8.19). This kind of response, with medium–low continuity of inner reservoirs, indicates that pore and solution-pore reservoirs are continuously distributed (within a certain range) and have relatively obvious boundaries with the underlying fractured reservoir. The fractured reservoir presents a discontinuity point or zonal anomaly on a low-frequency (around 5 Hz) single-frequency volume, and there is no apparent seismic reflection from the underlying reservoir. Thus, singlefrequency volumes using spectral decomposition technology can accurately identify high-quality reservoirs and determine their sensitive frequencies and sensitive frequency bands. Amplitude Spectrum Gradient Attribute Technology Amplitude spectrum gradient attribute technology is a seismic reservoir prediction technology that uses frequency variations in the amplitude of seismic data to predict reservoirs. It is based on viscoelastic theory and analyzes the relationships between seismic amplitude, reservoir permeability, and fluid properties. The attribute is only related to the formation’s permeability and the fluid’s physical properties. The application of this technology, combined with the results of time–frequency analysis, can be used to identify and evaluate basement rock buried hill reservoirs accurately. Baobab C 2

Depth

B

C 1000

Baobab C 1

1000 ms

ms

A

B Depth

500

Baobab E 1

Basement 1500

Basement

Fig. 8.19 Profile through wells from a 5 Hz single frequency volume in the Baobab area. The blue curve is the acoustic logging curve. a weathered and leaching zone, b fractured-cavity developed zone, c semi-filled zone, d tight zone

402

8 Seismic Reservoir Prediction Technology

On the amplitude spectrum gradient data volume of well Baobab C-2 (Fig. 8.20), the weathering and leaching zone, where pore reservoirs are developed, shows continuous high values (strong amplitude) on the amplitude spectrum gradient section. The development zone of fracture-cavity reservoirs shows middle-low values (weak amplitude) with poor continuity. Fractured reservoirs are discontinuously distributed with punctiform weak amplitude anomalies. The amplitude spectrum gradient data volume accurately reveals the distribution characteristics of the various types of reservoirs. Attribute Fusion Technology Based on Paleogeomorphic Features of Ancient Landforms The seismic responses of high-quality pore and fracture-cavity reservoirs in basement rock buried hills are medium-strong amplitude reflections, with occasional high-frequency abnormalities and good continuity, mainly distributed in areas with wide and gentle structural shapes and small dip angles on the surfaces or low parts of the buried hills. The upper sections of large regional faults and their scale and spatial distribution are controlled by ancient landform morphology. Combining morphological understandings with the characteristics of seismic responses, we constructed a multi-attribute fusion seismic technology based on ancient landforms. We fused the sensitive seismic attributes to basement rock buried hill reservoirs and the structure dip angle of one of the ancient landforms to predict the distribution of high-quality basement rock reservoir sections, combining the use of amplitude attributes, instantaneous frequency attributes, and the ancient landform parameters of basement rock buried hills.   F(a, f, d) = a × f n ÷ d

Baobab C 2

500 ms

A

Depth

B

Amplitude spectrum gradient

10 1000

C

5

0

Fig. 8.20 Amplitude spectrum gradient profile through well Baobab C-2. The pink curve is the acoustic interval transit time logging curve. a weathered and leaching zone, b fractured-cavity developed zone, c semi-filled zone.

8.3 Reservoir Prediction Technology for Basement Rock Buried Hills

403

where a is the amplitude attribute value, f is the instantaneous frequency, d is the dip angle value of the stratal surface, and n is a constant (usually ± 1). This equation uses at least two seismic dynamic parameters and one ancient landform parameter to predict buried hill reservoirs in the Bongor Basin (Sorensen 2005). Its significance is that it not only considers the reservoir’s seismic response and change characteristics but also reflects the impact of ancient landform morphology on the formation and preservation of reservoirs. When the reservoir is calibrated according to the changing trend of low-frequency strong amplitude, the value of n is 1, when the reservoir is calibrated according to the changing trend of strong high-frequency amplitude, the value of n is −1. The distribution of high-quality reservoirs predicted by this equation agrees with the high-quality reservoirs confirmed by drilling (Fig. 8.21). Wells Raphia S-8A, Phoenix S-3, and Raphia S-10, with developed high-quality reservoirs, are in the high-value area, while wells Mimosa E-2 and Baobab SE-3, with underdeveloped reservoirs, are in the low-value area. The qualitative coincidence rate with the reservoirs revealed by actual drilling is 100%, indicating that this attribute accurately predicts the distribution of basement rock pore and fracture-cavity composite reservoirs. A superimposed map of the fusion properties and the top surface structures of the buried hills (Fig. 8.22) indicates that high-quality reservoirs in the weathering and leaching and fracture-cavity developed zones are mostly in the relatively gentle high part and on the basal slope of the buried hill, but are not well developed in the steeply inclined slope zone. High-quality reservoirs are distributed in nearly east–west strips, in line with the extension direction of the fault, indicating that the WNW-trending fault controls the distribution of favorable reservoirs. Drilling has revealed that the depths of high-quality reservoirs in basement rock buried hills are generally 0–150 m from the buried hill surface. With an increase in burial depth, the reservoirs become gradually less developed, and attribute prediction is consistent with drilling and the geological origin mechanism of basement rock reservoirs. Combined analysis of strata slices from shallow to deep (0–50, 50–100, and 100–105 m from the top of the buried hill) along the top of the basement rock buried hill shows that the most favorable reservoirs are in the shallow layers at the top of the buried hill, generally decline in quality towards the interior of the buried hill, and develop only locally along the fault zone. Figure 8.22a shows that favorable reservoirs in buried hills are mostly in the depth range of 0–50 m, distributed in strips. However, they gradually decrease in the depth range of 50–100 m (Fig. 8.22b), where the reservoirs show punctiform distribution. In the depth range of 100–150 m, reservoirs develop only sporadically along the fault zone (Fig. 8.22c). Seismic Inversion Technology Seismic inversion is an essential technique for quantitative reservoir prediction. We summarized the wave impedance characteristics of reservoirs. We predicted their distribution using sparse spike inversion to form wave impedance data volumes, combining the results of rock physics analysis with crossplots and fine reservoir calibration. Regardless of the wave impedance profiles from the Phoenix buried hill zone (Fig. 8.23) and the Baobab C buried hill zone (Fig. 8.24), the green zone with low

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Fig. 8.21 Overlay of the distribution of high-quality reservoirs and the top structure of buried hills of the Phoenix 3D area. Red represents high values of attributes which indicate developed reservoirs; blue represents high values of attributes which represent underdeveloped reservoirs

impedance near the top of the buried hill represents the weathering and leaching zone and dissolution fracture-cavity zones. These zones contain high-quality reservoirs with favorable porosity and permeability characteristics (Nguyen et al. 2014). Their planar distribution on the profile also accords with seismic fusion attributes and reservoirs confirmed by drilling. This confirms that wave impedance inversion can accurately predict the distribution of weathering and leaching zones and dissolution fracture-cavity high-quality reservoirs. Factors Controlling the Distribution of High-Quality Reservoirs Reservoir studies indicate that the longitudinal and planar distributions of highquality reservoirs in the buried hill zone have similarities and differences compared to other buried hill zones. Multiple factors control the formation and development of high-quality reservoirs. For example, the top surface of the Baobab C buried hill is relatively gentle, with small undulations of ancient landform and widespread development of small faults. High-quality reservoirs are generally continuous, with wide planar and longitudinal depth distribution. The reservoirs in the fracture-cavity developed zone of well Baobab C-2 are up to 850 m below the surface of the buried hill. Seismic profiles show that the depths of some buried hills are up to 200–600 m below the surface of the buried hill, with a large distribution range (Fig. 8.25). In the Phoenix buried hill belt—which resembles high mountains and deep valleys with

8.3 Reservoir Prediction Technology for Basement Rock Buried Hills Fig. 8.22 Longitudinal analysis of high-quality reservoirs in the buried hills of the Phoenix area

405 0

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Raphia S 8A

Mimosa E 2

Phoenix S 3

Raphia S 10

Fused attribute values 0

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Raphia S 8A

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Plane graph of fused attributes in 50 100m of the top of the buried hill 0

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50

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c Plane graph of fused attributes in 100 150m of the top of the buried hill

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Phoenix S 3

Impedance values of P wave

Phoenix 2 800 900 1000 1100

ms

1200

20000 18000 16000 14000 12000 10000

1300

8000

1400 1500 1600 1700 1800 1900 2000 2100

Fig. 8.23 Inversion profile of impedance through well Phoenix-2 and well Raphia S-10. The black curve next to the well is the wave impedance curve. The green low-impedance area is the development area of high-quality reservoirs

600

Baobab C1 1

Baobab C 5

Basement B

700 800

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Basement C

Baobab SE 3 Impedance values of P wave

Baobab C 2 500

20000 18000 16000 14000 12000 10000 8000 Mimosa Prosopis Basement C

1400 1500 1600 1700 1800 1900 2000

Fig. 8.24 Inversion profile of impedance through well Baobab C-2 and well Baobab SE-3. The black curves next to the wells are the wave impedance curves. The green low-impedance areas are the development areas of high-quality reservoirs

large, undulating ancient landforms—the distribution of high-quality reservoirs is generally limited to the relatively gentle areas in the high parts of the buried hill. They may also be developed at the toe of the slope of the buried hill (which has not yet been drilled), but not well developed on the steep slope, and distributed longitudinally 100–300 m below the surface of the buried hill. Previous studies have shown that burial times have a crucial influence on the spatial distribution of high-quality reservoirs in the evolution of buried hills and their topographic features. The horizon-flattening profile of the top of the P Formation (Fig. 8.25b) shows that the overall shapes and local hilltops of the Baobab buried hill zone are comparatively

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Baobab C 2

M Fm.

P Fm. Top basement

Baobab C 2

a Before horizon flattening

P Fm. Top basement

Bottom boundary of fracture cavity developd zone (B) b

After horizon flattening

Fig. 8.25 Comparison of seismic profiles before and after horizon flattening with the top of Formation P in the Baobab buried hill zone

gentle. During the early deposition of the P Formation, the buried hill was exposed to the water surface, suffering long-term leaching. During the late deposition of the formation, the upper member was uniformly covered, preserving the weathering crust formed by long-term weathering, leaching, and corrosion of the fracture zone. The Phoenix buried hill zone is mainly composed of cuesta controlled by N-dipping faults. The top of the buried hill is sharp or small-scale, and gentle platforms are developed, which is not conducive to preserving weathering crust and the deep and large-scale corrosion of fracture zones. The high-quality reservoirs that have been confirmed by drilling are mainly found on the relatively gentle parts at the top of the buried hill (Fig. 8.26).

8.3.3 Seismic Fracture Prediction Technology Reservoir fracture prediction is a geological problem that has consistently affected the characterization of fractured reservoirs or oil reservoirs. It is a technical problem for which a solution has long been sought in seismic data interpretation technology. However, it remains a reality that cannot be avoided in developing fractured reservoirs and bringing them into production. In crystalline basement rock buried hills,

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Fig. 8.26 Thickness of high-quality reservoirs in buried hills in the Phoenix area

there is no matrix pores like those found in carbonate rocks since fractures are the primary (or even the only) reservoir spaces and oil and gas flow channels. Consequently, identification and characterization of fractures are vital in the exploration and development of buried hill oil and gas in the Bongor Basin. Seismic data with ‘wideazimuth, broadband and high-density’ is better for revealing information related to fractures in the interiors of buried hills, and lays a foundation for the investigation and application of new technologies for fracture prediction using seismic data and thus for the prediction of buried hill fracture reservoirs. It also offers the possibility of a breakthrough in predicting fractures in basement rock buried hills across the entire area. Basis for Seismic Fracture Prediction Superimposition analysis of results from regional structural interpretation and research on drilling fractures shows that the strikes of fractures have a high consistency with the strikes of main faults (Fig. 8.27). That is, the fractures identified by FMI logging are mainly structural fractures. The degree of development and the direction of extension are controlled by tectonic activity. In the Baobab C, Raphia, Daniela, and Lanea E buried hill belts, where two sets of faults are developed, there are also two sets of fractures. In the Mimosa buried hill belt, controlled by a single fault, only a set of WNW-ESE-trending fractures is relatively well developed, while the NE-SW-trending fractures are underdeveloped (Table 8.2).

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Fig. 8.27 Superimposition showing the top surface structure of the buried hill in the Northern Slope and the fracture azimuth by logging Table 8.2 Statistics of the elements of attitude of the buried hill fractures Well

Well section (m)

Lanea E-4

970 –1300

Lanea SE-1

810 –1290

Raphia S-10

1560 –1900

Mimosa E-1

1070 –1400

Baobab SE-3

2170 –2270

Dip

Strike

Dip angle (°)

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Fig. 8.28 Schematic diagram of the principle of seismic fracture prediction

When seismic waves propagate in anisotropic media (HTI), the travel time of longitudinal waves is shortest, and their attenuation weakest when propagating along the fracture strike. As the angle between the propagation direction of the seismic wave and the fracture strike increases, travel time and attenuation increase. Travel time is longest and energy attenuation fastest when the direction of wave propagation is perpendicular to the fracture strike. Azimuthal anisotropy analysis technology can be used to predict fracture zones (Fig. 8.28). Pre-stack Seismic Fracture Prediction Technology in OVT Domain Attribute Characteristics of OVT Domain In OVT trace gathers, each seismic trace’s geophone offset and azimuth are roughly the same. After pre-stack migration in the OVT domain, many OVG trace gathers are generated. The energy consistency of OVG trace gathers is preferable, regardless of whether they are in the range of near, medium, or far geophone offset. The amplitude change of trace gathers in the OVT domain, therefore, includes geophone offset and azimuth information, and azimuthal anisotropy analysis based on OVG trace gathers better for analyzing the travel times, velocities, amplitudes, frequencies, and phase differences of seismic waves propagating in anisotropic media. The change features of seismic information in the abscissa (X), ordinate (Y), time-domain (TWT), geophone offset, and azimuth (Zhan et al. 2015) are optimized for prestack fracture prediction. The maturity of day-to-day OVT domain processing technology allows processing massive volumes of high-quality wide-azimuth seismic information obtained from high-density and wide-azimuth seismic exploration.

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Technical Process of Fracture Prediction in the OVG Domain We developed a new pre-stack seismic fracture prediction approach based on ‘wideazimuth, broadband and high-density’ seismic data and the new processing and interpretation technology for the OVT domain (Fig. 8.29). This approach applies the change characteristics and laws of the ‘five-dimensional’ attributes of diverse azimuth angles in analyzing and predicting the extension direction and degree of development of fractures, and identifies the spatial and planar distribution characteristics of the fracture-developed zone. The core of the technique is the processing and interpretation technology of OVG trace gathered in the OVT domain. This technology analyzes and determines anisotropy in basement rock buried hills by analyzing variations in seismic attributes such as amplitude spectrum, frequency, and velocity with geophone offset and azimuth in the OVG trace gathers. Combining the results with data from drilling and coring, FMI, and DST data supports the prediction of the degree of fracture development. The technology, therefore, reveals the extension direction of fractures, evaluates fracture effectiveness, and delineates the development zones of fractured reservoirs. Key Technology: OVG Trace Gather Analysis OVG trace gather is a unique recording and display method using ‘wide-azimuth, broadband and high-density’ seismic data. It preserves variations in conventional seismic reflections with geophone offset and provides more detailed information on changes in seismic reflection characteristics with azimuth (Fig. 8.30). Using this approach, we could determine the extension direction or azimuth of fractures according to periodic changes in the azimuth domain of the seismic attributes and

Fig. 8.29 Flow chart of fracture prediction in the OVT domain

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TWT

ms

412 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400

240.776

1265.61

2022.04

2487.786

Azimuth offset

Fig. 8.30 Snail trace gather in the Baobab C 3D area

reflection time. This method also helps formulate technical processes in the OVT domain and provides a basis for parameter optimizations. Comparative analysis of OVG trace gather data, combined with the geological characteristics of the target, allowed us to optimize the geophone offset parameter with seismic data with high signal-to-noise ratios, determine the range of pre-stack trace gathers used for fracture prediction, analyze variations in seismic attributes with geophone offset and azimuth, and select the optimum azimuth to reflect the characteristics of fracture development. Conjoint Analysis of Geophone Offset-Azimuth Parameters for Fracture Prediction The strikes of high-angle fractures related to a structure are usually parallel to the fault or intersect at a small angle. They are distributed in strips on both sides of the fault in the plane, with a relatively clear distribution law and a certain scale. The development of such fractures is contiguous, large scale, and with favorable connectivity. Interconnection and communication of multiple sets of fractures create the most favorable areas for forming large oil reservoirs in massive buried hills. We analyzed the geophone offset of OVG trace gathers and, according to the target depth, selected seismic data with high signal-to-noise ratios, small residual static correction, and small impact from the processing of mute parameters in the range of geophone offset to carry out fracture prediction. Comparison of simulation results of the amplitude changes and azimuth characteristics of various geophone

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413

offsets (Fig. 8.31) found that the fitting effect of the trace gather with 900–2300 geophone offset is similar to that of the trace gather with 0–3000 geophone offset and that the amplitudes of the samples are concentrated near the ellipse of the curve. The fitting effect of trace gathers with 0–900 and 2300–3000 m geophone offset is quite different from that of the trace gather with 0–3000 m offset, so it is impossible to reflect the fitting features of a full geophone offset. Figure 8.31, the upper figure shows the 0–3000 m trace gathers of diverse geophone offsets. The figure below shows amplitude distributions with varying azimuth and amplitude distributions between 0 and 3000 m. The reliability of the fracture simulation results is very sensitive to changes in the range of geophone offset. In the amplitude simulation results, the more evenly the sample points are distributed on or near the elliptical curve, the more reliable the simulation results and the more reliable the prediction results. Logging-Seismic Cooperative Fracture Prediction Technology Using core data, FMI logging, dip and conventional logging data, and well testing and early production test data, we adopted a multidisciplinary approach to well-seismic cooperative fracture prediction and achieved significantly improved prediction accuracy. In well Phoenix S-3 in the Phoenix area (Fig. 8.32), the signal-to-noise ratio of the seismic data is high within a geophone offset range of 800–1640 m. The extension direction of fractures identified by FMI logging corresponds best with variations in seismic amplitude (Fig. 8.32a). The seismic prediction results of fracture azimuth (Fig. 8.32b) and the appearance of fracture azimuth in imaging logging (Fig. 8.32c) both show the development of two sets of NE and NW-trending fractures, with a high level of consistency between the two, confirming the feasibility of fracture prediction technology in the OVT domain and the reliability of prediction results. Azimuth 90

Azimuth 180

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90

Azimuth 180

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Azimuth 180

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0

1300

1300

1400

1400

1400

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South a 0 900m

East

West

South b 900 2300m

1500

1700

North

North

East

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90

1600

1700

North

West

TWT ms

1300

TWT ms

1300

TWT ms

TWT ms

0

West

North

East

South c 2300

3000m

Fig. 8.31 Comparison and optimization of different geophone offsets

East

West

South d 0 3000m

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180

800

900

900

1000

1000

TWT ms

TWT ms

800

0

1100

Offset m 1220

800

1640

1100

1200

1200

1300

1300 a

Preferred gathers in the azimuth domain and the offset domain North

West

North 90° 75° 60° 45° East

East

West

South

South b Fractures results of seismic prediction

c

Fracture statistics of FMI

Fig. 8.32 Logging-seismic cooperative fracture simulation of in well Phoenix S-3

Post-stack Seismic Fracture Prediction Technology Post-stack seismic fracture prediction technology uses the seismic data volume (PSTM) after migration stack to analyze and compare spatial changes in seismic traces’ geometric and dynamic parameters through targeted mathematical manipulation. This can be applied to study fractures’ development and spatial distribution characteristics in strata and geological bodies. The practice has shown that the optimal post-stack fracture prediction technologies for basement rock buried hills in the Bongor Basin include coherence cube technology with optimum frequency band, volumetric curvature technology, and ant-tracking volume attribute technology. We combined these techniques to analyze the development of fractures in ancient buried hill landforms, the heterogeneity of inner buried hills, fractures in inner buried hills, etc. Combining these findings with research on regional fault systems and structural evolution, we could effectively predict fracture development and delineate the development areas of fractured reservoirs.

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Coherence Cube Processing and Interpretation Technology with Optimum Frequency Band We optimized the fracture-sensitive frequency band according to the spectral characteristics of seismic data from the buried hills. We applied wavelet decomposition and reconstruction to form a seismic data volume in the optimum frequency band. The data volume was then calculated and processed to form a coherence cube. The data volume with the optimum frequency band has a high overall signal-to-noise ratio, revealing the development of small faults and fracture zones. This has become one of the most common and effective techniques for predicting fractures using post-stack seismic data. In the northern slope of the Bongor Basin, combining horizontal slice and horizonbased attribute analysis technology, applying the coherence cube method (with optimum frequency band) revealed the distribution characteristics and change trend of the fracture-developed zone. For example, coherence cube slices with optimum frequency at various depths in the inner Phoenix basement rock buried hill (Figs. 8.33 and 8.34) reveal the unevenness and spatial variations of the fracture-developed zone. Fractures are mostly developed near large regional faults or in the shallow layers of buried hills. As depth increases, the degree of fracturing decreases. Fractures are most developed in the high structural parts of basement rock buried hills. This feature is also reflected in the coherence attributes of optimal frequency bands extracted along the top surfaces of the buried hills. The development characteristics of fractures revealed by horizon-based coherence attributes on the top surface of buried hills correlate well with statistical results from FMI logging of fractures (Fig. 8.35).

Fig. 8.33 Horizontal slice of coherence cube with optimum frequency in the Phoenix area (1200 ms)

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Fig. 8.34 Horizontal slice of coherence cube with optimum frequency in the Phoenix area (1400 ms)

Fig. 8.35 Planar graph of horizon-based coherence attributes of the top surface of the buried hill in the Phoenix area (time window 50 ms)

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The coherence attribute body of the optimal frequency band reveals the characteristics of fracture development, making it an indispensable technical method for predicting fractured reservoirs in basement rock buried hills. It is characterized by independence from drilling data, rapid calculation speed, and high-quality seismic data. Nevertheless, this technology only qualitatively delineates fracture-developed zones, and does not quantitatively predict fracture strike, density, opening, or other parameters. Volumetric Curvature Processing and Interpretation Technology Volumetric curvature processing and interpretation technology allow quantitative analysis of formation deformation and changes in crustal stress by revealing changes in the curvature of the same seismic reflection interface. The degree of fracture development can then be predicted. This technology is suitable for predicting structural fractures in rigid formations, provided that the greater the formation deformation, the more developed the fractures. The basement rock buried hill of the Bongor Basin is a rigid granitic stratum with a single lithology and stable mineral composition. It is propitious to predict cracks according to the degree of tectonic deformation. We can delineate the fracture-developed zone from the seismic curvature data volume, horizontal slices, and horizon-based curvature attributes (Fig. 8.36), combined with the interpretation of regional structures and core and FMI logging data. On the planar graph of horizon-based curvature attributes of the top of the buried hill in the Phoenix area (Fig. 8.37); the black band with a large absolute curvature shows the distribution of the fault system; the gray band with a medium curvature is a fracture-developed zone; and the white contiguous area is an area with small curvature which has no fractures (a feature which has been confirmed by drilling). Ant-Tracking Technology “Ant” tracking technology is a seismic attribute volume-based (coherence volume, variance cube, and curvature cube) characterization technology based on the analogy of an ‘ant nest’ structure, incorporating the laws governing the activity of ‘worker ants’ and other control factors, and applying them to the development characteristics of fault systems. The basic idea is to discover the range of seismic attributes that predicts the development of fractures in the selected seismic attribute bodies, revealing fractures (including faults), tracking and releasing the seed points of signals—which resemble ants when graphically displayed—to obtain a low-noise, fracture-related attribute volume, and to interpret and characterize the development of fracture space through volume tracing. ‘Wide-azimuth, broadband, and high-density’ seismic data and the processing of data volumes of pre-stack depth migration in the OVT domain not only reveal detailed features of the top surface of the buried hill but also information about inner buried hill fractures and faults. This provides the necessary high-quality basic data for applying ant-tracking technology for fracture prediction and understanding the genetic mechanisms of basement rock buried hills (Fig. 8.37). The plane graph of horizon-based ant attributes of the top surface of buried hills in the Phoenix area (Fig. 8.38) shows that, on slices of the ant-tracking data volume, the relationship

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Fig. 8.36 Comparison of seismic data in the Phoenix area

Fig. 8.37 Planar graph of horizon-based curvature attributes of the top surface of buried hills in the Phoenix area (time window 50 ms)

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Fig. 8.38 Planar graph of horizon-based ant attributes of the top surface of buried hills in the Phoenix area (time window 50 ms)

between fracture strike, development degree, and the structural change trend is very clear. They correlate well with the FMI fracture identification results, indicating that ant-tracking technology is effective for fracture prediction. Reliability Evaluation of Fracture Prediction Results Reliability of results is the primary difficulty in fracture prediction and the main research topic in fracture prediction. At present, evaluation is still based on the macro-qualitative evaluation. The key evaluation points include the rationality of geological origin and the consistency of observation data (core, FMI, dip logging, productivity, Etc.). Pre-stack fracture prediction in the OVT domain is the most recently developed technology for seismic prediction of fractured reservoirs, thanks to the increasing availability of wide-azimuth, broadband, and high-density seismic data with high signal-to-noise ratios, strong penetration, and 360° observation. We used this technology to predict fractures in the northern buried hill in the Bongor Basin, improving the reliability of previous prediction results significantly. Fracture Prediction Results in Typical Well Fields Consistency between seismic fracture prediction results and results from FMI fracture research is the most direct and effective method for confirming the reliability of prediction results. We compared the predicted fracture orientation and intensity in

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the basement rock of five well fields with the results of FMI data and interpretation. The comparison confirms that the seismic fracture prediction results are consistent with the fracture directions identified by FMI logging, with a macro-qualitative coincidence rate of 100%. To reflect the application value of these fracture prediction results in oil and gas exploration and development, we compared the fracture intensity predicted in a single well field with the results of well testing and early production test. We confirmed that the test productivity of areas with large predicted fracture intensity is high. For example, the test productivity of well Phoenix S-3 in the highly fractured area is 595 m3 /d (Fig. 8.39), while that of well Mimosa E-2 in the low fractured area is only 0.73 m3 /d (Fig. 8.40). The coincidence rate between predicted intensity and actual productivity in the test is about 80%, indicating that the prediction results of pre-stack seismic fractures in the OVT domain are highly reliable and offer a practical means to meet the basic needs of oil and gas exploration and development in basement rock buried hills in the basin. Planar Distribution of Fractures The study of the plane distribution of fractures includes the characteristics of dominant fracture strike, development strength, the effectiveness of fractures, and the spatial distribution of the effective fracture-developed zone. The geological cause of the fractures must also be established and the formation stage and effectiveness of the fractures evaluated. Reliability analysis of the prediction results includes the dominant fracture trend, the relationship with the fracture system, the development strength, the structural location, etc. The better the consistency of the fracture strike with the fracture system, the higher the development of superimposition and structural deformation of fractures, and the more reliable the fracture prediction results. Predicted fracture distribution is closely related to faults (Younnes AI 1998). Comprehensive research reveals two groups of fractures in the basement rock of the Bongor Basin. One group is NE–SW–trending, and the other is WNW–ESE– trending, consistent with the orientation of the regional fault system. The direction of fracture development is parallel, or approximately parallel, too, or intersecting at a small angle with, the strike of the faults. On a planar graph of the developmental strengths of fractures, the red (high) value areas are nearest the faults. The fault strength in the intersection area of the two groups of faults is the greatest, indicating that the predicted fractures are closely associated with structure and fault activity, by the mechanism and geological characteristics of the formation of structural fractures (Fig. 8.27). A study of core, FMI logging, and other data shows that the reservoir in well Raphia S-10 in the Phoenix buried hill zone is a fractured reservoir and that the weathering and leaching zone is not well developed. There is no obvious logging response from the weathering and leaching zone on the logging data. Proceeding on the assumption that this is a typical well, we calculated the productivity index of fractured reservoirs in the well to provide a basis for the distribution of oil layers in other test wells. Division and productivity evaluation of intervals with diverse reservoir types, fracture-developed intervals, and subintervals within each well were carried out to provide a quantitative basis for analyzing the relationship between productivity

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Fig. 8.39 Comprehensive analysis of fracture prediction results in well Phoenix S-3

and fractures. This enabled us to calculate each well’s production distribution and liquid production index (Table 8.3). In the Phoenix buried hill zone, the study of conventional logging interpretation, imaging logging fractures, and oil testing results reveals that the fractures in the basement rock buried hill of well Raphia S-10 are unevenly developed longitudinally, with considerable differences in development density. The strike of the fractures is predominantly NW–SE (330°–150°), followed by an NE–SW strike (30°–210°). The strike of effective fractures in this area is NW–SE, and the high-quality reservoirs are mainly found in the upper and middle sections of the buried hill (Fig. 8.41). The Phoenix S-3 well field (Fig. 8.42) has similar fracture characteristics. Although they belong to two different buried hill structures, both groups of fractures strike NW– SE (330°–150°) and NE-SW (30°–210°). Fractures are vertically developed in the shallow layer, with great variations in development density. High-quality reservoirs (and most liquid hydrocarbon production) are concentrated in the upper reservoir,

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Fig. 8.40 Comprehensive analysis of fracture prediction results in well Mimosa E-2 Table 8.3 Fracture strike in basement rock sections of typical wells and productivity analysis of test wells Well name

Well section (m) Main strike of fracture Test output Note

Raphia S-10 1620 –1890

Mainly NW–SE

High

Uneven distribution of pay

Phoenix S-3 1000 –1230 Lanea E-2

Baobab C-3

Mainly NW–SE

High

Even pay

1230 –1500

NE-SW

Low

Sporadic pay

835 –920

NW–SE

High

Pay mainly concentrated on the top

920 –1160

NE-SW

Low

Sporadic pay

1445 –1490

NW–SE

High

Even pay

1490 –2000

NE-SW

Medium

Sporadic pay

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423

Fig. 8.41 Analysis of the relationship between productivity and fractures in well Raphia S-10

where the fracture strike is predominantly NW–SE. Productivity of the lower well section, with NE–SW fracture strike, is comparatively low (Xie et al. 2012). Analysis of multiple data indicates that the liquid production index of the interval with two sets of fractures—NW–SE and ENE–SW–trending—is more than ten times higher than the reservoir section with only NE–SW–trending fractures. The liquid production capacity of NW–SE–trending fractures is much higher than that of NE– SW–trending fractures. This understanding provides a technical basis for designing well trajectories for cluster wells or horizontal well development.

8.3.4 Evaluation of Favorable Reservoirs Using Logging-Seismic Synergy The key to logging-seismic synergy is combining wellbore information with highquality seismic data. Rich and accurate information from well points is extended to generate full three-dimensional seismic coverage of the area, from point to surface to volume. For example, joint research on FMI and DST has determined the strike and distribution characteristics of favorable fractures in reservoirs with higher liquid

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Fig. 8.42 Analysis of the relationship between productivity and fractures in well Phoenix S-3

production capacity, which has guided the formulation of seismic fracture prediction technical solutions, optimization of geophone offset, azimuth and other parameters, and supported the comprehensive evaluation of reservoirs (in addition to other essential work). Multi-information joint research is an effective technical approach for fracture prediction and fractured reservoir evaluation. In particular, the application of wideazimuth, broadband and high-density seismic acquisition technology, OVT domain processing technology, and pre-stack fracture prediction technology have improved prediction of spatial variations in fractures and reservoir properties. It has also made it clear that NW–SE–trending fractures in the basement rock of the Northern Slope are the main direction of fluid movement in the reservoir and contribute most to the productivity of oil wells; an understanding that provides a basis for optimization of high-yield fractures. Pre-stack fracture prediction results in the OVT domain, post-stack fracture attributes, and FMI and DST research determine favorable fracture strikes and provide a basis for understanding the distribution of high-yield enriched areas and the selection of high-yield wells in basement rock oil reservoirs. In the Baobab 3D zone,

8.3 Reservoir Prediction Technology for Basement Rock Buried Hills

425 0

Raphia S 10

1000

Well Location Structural contour m Fault

2km

Type I fracture developed zone Type II fracture developed zone

Fig. 8.43 Comprehensive evaluation of buried hill reservoirs in Baobab area

ninety-three fracture-developed zones have been identified (Fig. 8.43), with a total area of 39.3 km2 . We used well-seismic coordinated fracture evaluation technology for evaluation and classification. Among these zones are seventy Type I fracturedeveloped zones, with an area of 30 km2 , and twenty-three Type II fracture-developed zones, with an area of 9.3 km2 . Similarly, in the Phoenix 3D seismic zone, sixtynine fracture-developed zones have been identified by fracture prediction (Fig. 8.44), covering an area of 31 km2 . Of these, twenty-five is Type I fracture-developed zones with an area of 16.3 km2 , and forty-four are Type II fracture-developed zones, with an area of 14.7 km2 .

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0

Raphia S 10

1000

Well Location Structural contour m Fault

2km

Type I fracture developed zone Type II fracture developed zone

Fig. 8.44 Comprehensive evaluation of buried hill reservoirs in the Phoenix area

References Achiat R, Guttormsen J, Waworuntu R. Complex geomodeling: Dayung field a fractured pre-tertiary reservoir in the southern Sumatra Basin, Indonesia. Indonesian Petroleum Association, 33th Annual Convention & Exhibition, 2009 Al-Chalabi M, Rosenkranz PL. Velocity-depth and time-depth relationships for a decompacted uplifted unit. Geophys Prospect. 2002;50(6):661–4. Chen S, Zhang CG, Fan SS. Apllication of dual laterolog range dfferences in evaluation fracture parameters to oilfield. Chinese J Eng Geophys. 2012;01:114–8. Cuong TX, Warren JK. Bach Ho field, a fractured granitic basement reservoir, Cuu Dank Long Basin, offshore SE vietnam: a “Buried-hill” play. J Pet Geol. 2009;32(2):129–56. Dou LR, Wei XD, Wang JC, et al. Characteristics of granitic basement rock buried-hill reservoir in Bongor Basin, Chad. Acta Petrol Sin. 2015;08:897–904. Hillis RR. Quantification of tertiary exhumation in the United Kingdom southern North Sea using sonic velocity data. AAPG Bull. 1995;79(1):130–52. Hu JY, Tong XG, Xu SB. Regional distribution of buried hill oil reservoirs in Bohai Bay Basin. Pet Explor Dev. 1981;05:1–9. Koning T. Oil and gas production from basement reservoirs: examples from Indonesia, USA and Venezuela. Geol Soc, London, Spec Publ. 2003;214(1):83–92. Nelson RA, Moldovanyi EP, Matcek CC, et al. Production characteristics of the fractured reservoirs of the La Paz field, Maracaibo basin, Venezuela. AAPG Bull. 2000;84(11):1791–809. Nguyen TBN, Bae W, Nguyen LA, et al. A new method for building porosity and permeability models of a fractured granite basement reservoir. Pet Sci Technol. 2014;32(15):1886–97. Nur A, Mavko G, Dvorkin J, et al. Critical porosity: a key to relating physical properties to porosity in rocks. Lead Edge. 1998;17(3):357–62.

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Petford N, McCaffrey K. Hydrocarbons in crystalline rocks: an introduction. Geol Soc London Spec Publ. 2003;214(1):1–5. Sneider RM, Richardson FH, Paynter DD, et al. Predicting reservoir rock geometry and continuity in Pennsylvanian reservoirs, Elk City field, Oklahoma. J Petrol Technol. 1977;29(07):851–66. Sorensen RP. A dynamic model for the Permian Panhandle and Hugoton fields, western Anadarko basin. AAPG Bull. 2005;89(7):921–38. Tan TD. Logging interpretation model and evaluation method for fractured reservoirs. Beijing: Petroleum Industry Press; 1987. Xie WY, Meng WG, Li XG. Basement hydrocarbon reservoir in Liaohe depression. Beijing: Petroleum Industry Press; 2012. Younes AI, Engelder T, Bosworth W. Fracture distribution in faulted basement blocks: Gulf of Suez, Egypt. Geol Soc London Spec Publ. 1998;127(1):167–90.

Chapter 9

Geological Evaluation and Interpretation from Logs

Logging is an essential process in oil and gas exploration. Downhole logging tools, acquisition software, and processing and interpretation technologies have a wide range of useful applications and have developed immensely in recent years (Ou et al. 2001). New concepts, and their resulting new technologies and tools, have shifted reservoir logging processing and interpretation from homogeneous models to heterogeneous models (Li 2008, 2013) and from straightforward reservoir evaluation to comprehensive evaluation of sources, reservoirs, and caps. Better data has led to a move from qualitative to semi-quantitative and quantitative evaluation (Li et al. 1995, 1996). Better technology has allowed more complex lithology identification and reservoir evaluation (including magmatic and metamorphic rocks) rather than being largely limited to sedimentary rocks. This in turn, has supported a progression from simple sedimentary sequence evaluation to a comprehensive evaluation of structural geology. In general, logging applications geology are becoming ever more widespread and complex (Rider and Kennedy 2011). Overseas oil and gas exploration faces many challenges: high-risk, high investment, poor local support conditions, etc (Xue 2014). Minimizing coring operations, making logging data processing and interpretation more efficient, and meeting the needs of international exploration are therefore vital issues in geological research and exploration deployment (Ou et al. 1999). Logging has become an indispensable tool in transnational oil and gas exploration. Logging data has been effectively applied in source rock identification, reservoir evaluation, oil and gas layer identification, and caprock quality evaluation in the Bongor Basin, providing effective approaches for evaluating and optimizing early plays. However, we will not discuss these successful applications of logging technology here. This chapter focuses on the comprehensive logging evaluation of crystalline basement rock reservoirs. Currently, logging evaluation of crystalline basement rock is based on the identification and evaluation of fractures, generally using specialized logging methods such as FMI, array acoustic wave, Elemental Capture Spectroscopy (ECS), and sonic scanning for qualitative and quantitative evaluation (Heasler 1996). Nevertheless, there has been no thorough research on basement rock lithology and oil and gas © Petroleum Industry Press 2023 L. Dou et al., Petroleum Geology and Exploration of the Bongor Basin, https://doi.org/10.1007/978-981-19-2673-0_9

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identification. Lithologies cannot be individually identified using traditional logging methods due to the various minerals and the multiple rock types that make up basement rock strata (Xiao and Fan 2003). New methods such as ECS lack sufficient coring data to offer effective alternatives (Liu et al. 2000). It is consistently difficult to precisely identify the fluids in basement rock reservoirs in oil and gas identification. There are several reasons for this, including small reservoir spaces in basement rock, insensitivity of logging curve responses to fluids, and interference with the accuracy of logging data from borehole slumps caused by fractures. In this chapter, logging evaluation of basement rock reservoirs will be explained in terms of basement rock lithology identification, reservoir identification, oil and gas, and water layer identification, Etc.

9.1 Lithological Identification of Basement Rock Using Logging Data Petrological research has shown that the lithologies of the basement rock in the Bongor Basin can be divided into two major categories—metamorphic rock and magmatic rock—with 14 subcategories and a total of more than 40 different rock types (Hamada et al. 2001). Logging does not reflect the texture and structure of rock, and logging response characteristics are the same or similar for mineral assemblages with thin section authentication and cores with similar mineral contents but diverse rock types (Guo et al. 2009). Logging, therefore cannot differentiate between the multiple rock types. Effective geological analysis of basement rock depends on combining lithologies with similar mineral compositions and logging response characteristics, establishing lithology identification methods using logging, and identifying major lithology sequences (Fu et al. 2007).

9.1.1 Logging Response Mechanism of Lithology Logging responses are the reflections of mineral compositions, pore structures, and the development degree of fractures and pores. The properties of the fluids in the pores of rocks and differences in lithology are the primary causes of diversity in logging responses. The crucial aspect of using logging in interpretating and evaluating strata composed of special lithologies is identifying regional lithologies by differentiating between mineral combinations with diverse lithologies in the logging data. The lithology of basement rock can be roughly divided into light-colored and dark-colored rock-forming minerals according to color and chemical composition. These two types show distinct response characteristics in logging data.

9.1 Lithological Identification of Basement Rock Using Logging Data

431

Light-colored Mineral Series This series consists of colorless or light-colored minerals containing silicon, potassium, and sodium elements. Because these, and the other elements found in the series, generally have low atomic numbers, they return low-density values in conventional logging responses. Feldspar minerals do not contain crystal or constitution water, so neutron values are low. Minerals containing alkaline feldspar are rich in the highly radioactive element K40 , which has a high gamma-ray value. Minerals containing plagioclase do not contain K40 , so their gamma-ray values and photoelectric indices are low (photoelectric indices are usually less than 4). These light-colored minerals are rich in silicon, potassium, sodium, and other elements, returning high values in ECS logging. Dark-colored Mineral Series These series contain iron, magnesium, calcium, titanium, and other elements, with light-colored and dark-colored minerals, including pyroxene, hornblende, olivine, chlorite, Etc. These minerals are comparatively dense and contain elements with high atomic numbers, such as iron, magnesium, calcium, and titanium. They are rich in crystal or constitution water, and there is no K40 . The rocks, such as hornblende, therefore tend to contain more dark minerals, and their logging responses are characterized by high density, high neutron, low gamma-ray, and high photoelectric indices (>4). ECS logging shows high contents of iron, magnesium, calcium, and other elements. In addition, the timing and degree of metamorphism of metamorphic rocks mean they have strong heterogeneity, with logging curves showing drastic ‘sawtooth’ variations, particularly on gamma-ray curves. Magmatic rock has better homogeneity than metamorphic rock, obtaining straight logging curves with little change in amplitude. The characteristics of the curves can therefore be used to distinguish between metamorphic and magmatic rocks roughly. With these marked differences in the density, neutron, gamma-ray, and ECS of the two types of rocks, it is theoretically feasible to use logging data to classify the lithologies of basement rock strata. However, logging values obtained from rocks of the same type are not fixed; they fluctuate. This is because, even for the same kind of rock, the mineral compositions, contents, and rock textures, are not identical. In addition, differences in the logging environment also have a certain impact on logging values. To qualitatively and quantitatively distinguish lithologies, lithology identification uses logging curves (density, neutron, interval transit time, gamma ray, etc.) that are sensitive to lithological responses. This study accordingly focuses on lithologies with similar mineral compositions and consistent logging responses to establish a logging curve classification scheme that meets the requirements for lithology identification and classification. More than forty rock types, identified from thin sections, are divided into six rock categories that their logging responses can identify.

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9.1.2 Qualitative Identification of Logging Lithology The conventional logging curve characteristics and ECS logging responses of diverse rock types were analyzed using thin-section data from cores and the logging response characteristics of various basement rock lithologies. We selected curves sensitive to lithology, such as density, neutron, gamma-ray, and ECS to conduct lithological logging identification. A total of six typical lithologies were distinguished, and their principal mineral components and logging curve characteristics are as follows: Migmatitic Granite The main mineral components of migmatitic granite are quartz, potash feldspar, plagioclase, biotite, hornblende, and other minerals with different contents. The precise mineral contents vary; quartz from 10 to 40%, plagioclase 10–50%, alkaline feldspar 20 –75%, and dark minerals 0–10%. The rocks have granoblastic texture, massive structure, and mineral grain sizes of 0.60–20.00 mm. The logging curves are characterized by the resistivity of tens to ten thousand Ω m. Gamma-ray is more than 50API, generally 80–200API in a zigzag shape curve, density is less than 2.72 g/cm3 , neutron between 0 and 2%, and neutron density has a positive difference. Figure 9.1 shows the logging response characteristics of typical migmatitic granite from well Raphia S-8A. Migmatitic Gneissic Rock The main mineral components of migmatitic gneissic rocks are quartz, alkaline feldspar, plagioclase, and biotite + hornblende. The content of quartz is 5~40%, plagioclase 15–60%, alkaline feldspar 5~65%, and dark minerals 5–20%. The texture

Fig. 9.1 Logging response characteristics of migmatitic granite of well Raphia S-8A

9.1 Lithological Identification of Basement Rock Using Logging Data

433

Fig. 9.2 Logging response characteristics of typical migmatitic gneiss from well Baobab C-2

is granoblastic, and the structure is banded and gneissic, with mineral grain sizes of 0.01–10 mm. Logging curves show the resistivity of tens to tens of thousand Ω m, ‘zigzag’ gamma-ray of more than 60 API, density less than 2.8 g/cm3 , and neutron of 1–9%. Neutron and density have a small negative difference or are entwined. Figure 9.2 shows the logging response characteristics of typical migmatitic gneiss from well Baobab C-2. Gneissic Rock The main mineral components of gneissic rocks are quartz, alkaline feldspar, plagioclase, biotite, and amphibole. The quartz content is 0–30%, alkaline feldspar 0~50%, plagioclase 10–80%, and dark minerals 5–50%. The texture is granoblastic, and the structure gneissic, with mineral grain sizes of 0.1–10 mm. The characteristics of conventional logging curves are resistivity of tens to tens of thousands Ω m, ‘zigzag’ gamma-ray above 40–20 API, density less than 2.87 g/cm3 , and neutron 2–10%. The neutron and density logging curves show small, or slightly larger, negative differences. Figure 9.3 shows the logging response of typical gneiss from well Baobab C-2. Acid Rock Acid rock primarily consists light-colored minerals such as quartz and potassium feldspar. The contents of dark minerals such as biotite, hornblende, and pyroxene are low. The contents of quartz, plagioclase, alkaline feldspar and dark minerals are 15%–50%, 6%–40%, 15%–80%, and less than 10%, respectively. The rocks have granoblastic, porphyritic, subhedral granular texture, massive structure, and mineral grain sizes of 0.1–10 mm. Logging curves show resistivity of tens to tens of thousands Ω m, straight gamma-ray curves with values above 100API, neutron

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9 Geological Evaluation and Interpretation from Logs

Fig. 9.3 Logging response characteristics of gneiss of well Baobab C-2

less than 6%, density less than 2.66 g/cm3 . Neutron and density both display positive differences. Figure 9.4 shows the logging response of typical acid rock from well Baobab C-2. Intermediate Rock

300 200 4 0 150 300

SP mV CL GR API

200 100 14 150 300 450

Depth m

2 2000

LLD Ω m

2000 140 2000000 240

2 2000

LLS Ω m MSFL Ω m

2000 42 2000000 102

2 2000

2000 2 2000000 3

AC μs/ft CN DEN g/cm3

40 140 18 42 3 4

Lithology profile by log interpretation

Intermediate rocks consist primarily of alkaline feldspar and plagioclase, followed by quartz and biotite. The contents of quartz, plagioclase, alkaline feldspar, and dark

FMI Core photo

830

840

850

860

Fig. 9.4 Logging response characteristics of acid rock of well Baobab C-2

0 0

static image

250 255

9.1 Lithological Identification of Basement Rock Using Logging Data

435

Fig. 9.5 Logging response characteristics of intermediate rock of well Baobab C-2

minerals are 2%–20%, 40%–80%, 0–30%, and 5%–20%, respectively. The rocks have subhedral granular texture, massive structure, and mineral grain sizes of 0.20– 5.00 mm. Logging curves show resistivity of tens to tens of thousands Ω m, gammaray of 5–120 API with straight curves, neutron of 3–12%, and density of 2.75– 2.88 g/cm3 . Neutron and density are both rather high, with considerable negative differences. Figure 9.5 shows the logging response of typical intermediate rock from well Baobab C-2. Basite The basite in this area is mainly gabbro. The rocks mainly contain dark minerals (biotite, hornblende) and plagioclase. The dark mineral content is relatively high (30–40%). This lithology is only found in well Raphia S-11 (Fig. 9.6) and shows high density, high neutron, medium–low gamma-ray, and other distinctive characteristics on the logging curve. The density-neutron logging curve shows a large negative difference, with both curves relatively straight. Gamma-ray presents a low-straight curve.

9.1.3 Quantitative Identification of Lithology Using Logging Following core analysis, logging response values sensitive to lithology were selected for lithology identification (Figs. 9.7, 9.8, 9.9, 9.10 and 9.11). We selected and collected logging data from typical intervals with the same lithologies (below and above the core point) at the depths and core points of the cores (including rotary sidewall cores) to extract the typical logging responses of the various lithologies, which

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9 Geological Evaluation and Interpretation from Logs

Fig. 9.6 Logging response characteristics of basic rocks in well Raphia S-11

were displayed on a crossplot chart of the data points in the respective intervals (Table 9.1). The crossplot confirms that distinct types of lithologies can be distinguished by the differences in their conventional logging responses. To avoid the influence of core physical properties, we used neutron and acoustic wave logs to obtain the M and N values of diverse lithologies (Fig. 9.12). This significantly improved the accuracy of lithology identification. In addition, we found that the element content revealed by ECS logging can be used to distinguish different lithologies (Figs. 9.13 and 9.14). The lithology of basement rock can be easily determined from its composition of iron, potassium, and silicon. The ECS responses of potassium and iron are quite distinctive, and, at a certain scale, the combination of potassium, silicon, and iron element curves show positive or negative differences with neutron and density curves. We analyzed the typical characteristics of varying lithologies of buried hills using core thin sections, conventional logging curves, and ECS curves. Figure 9.15 summarizes the results. We verified these new qualitative and quantitative lithology interpretation standards using data from 317 core rock samples from 12 wells. Of these, 268 samples were in line with the new standards, 49 were not, and the coincidence rate was 85%. The discrepancy is that thin section sampling is a small-scale reflection, whereas logging responses result from large-scale reflections.

9.1 Lithological Identification of Basement Rock Using Logging Data

437

Fig. 9.7 Cross-plot of density (DEN) and neutron (CN) of core samples. The rock types are from core analysis, the density and neutron are from loggint data

Fig. 9.8 Cross-plot of density (DEN) and gamma ray (GR) of core samples. The rock types are from core analysis, the density and neutron are from loggint data

9.1.4 Distinguishing Between Felsic and Mafic Rocks Although the six major types of the lithology of basement rock can be distinguished by conventional and ECS logging, it is still difficult to distinguish the six major types of lithology using seismic data and lithology interpretation results and the problems of seismic inversion and geological modeling persist (Han and Wu 2009). Basement rock lithology is a vital controlling factor for developing basement rock reservoirs. Changes in lithology, in addition to their influence on structure and texture, are

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Fig. 9.9 Cross-plot of neutron (DEN) and gamma ray (GR) of different rocks from logging data

Fig. 9.10 Cross-plot of density (DEN) and gamma ray (GR) of different rocks from logging data

essentially changes in the mineral compositions of rocks. Changes in the mineral composition of basement rock are substantial changes in two series of minerals: felsic minerals and mafic minerals. Chapter 5 explains the division of basement rock into two major types of lithology: felsic rocks and mafic rocks. This simplified treatment supports the use of logging technology to obtain continuous felsic and mafic content curves, which can be used to study the correlation between variations in

9.1 Lithological Identification of Basement Rock Using Logging Data

439

Fig. 9.11 Cross-plot of M and N of different rocks from logging data

felsic content and reservoir development. This offers a new basis and method for quantitative identifying reservoirs in the later stages of their development. Significantly, the combination of felsic rock and apparent wave impedance can be used as the basis for seismic inversion and also solves the problems of inversion and geological modeling. Research on a large number of test well sections indicates that the combined use of felsic and resistivity curves can give an excellent indication of the development degree of reservoirs. ECS logging can measure the contents of various elements such as potassium, silicon, and iron. It can also obtain the contents of quartz, potassium feldspar, plagioclase, and dark minerals, determine the contents of felsic and mafic rocks. Using ECS logging data from wells Baobab C-2 and Raphia SW -2, we established an equivalent petrophysical volume model for the basement rock matrix, with the basement rock’s rock volume equivalent to the cumulative felsic, mafic, shale, and pore volumes. The pore volume here only includes matrix pores. Fracture porosity is insignificant, so it can be ignored when calculating the contents of felsic and mafic rocks. The shale content is calculated using the GR curve and calibrated against the core. The calculation of matrix pores will be explained in detail in the section relating to reservoir parameters. The methods for obtaining felsic and mafic contents using conventional logging are as follows: The density curve is corrected for porosity and shale: D E Ncorr =

D E N − ∅ − Vsh × D E Nsh 1 − ∅ − Vsh

(9.1)

The neutron curve is corrected for porosity and shale: C Ncorr =

C N − ∅ − Vsh × C Nsh 1 − ∅ − Vsh

(9.2)