Handbook of Underground Gas Storages and Technology in China [1st ed. 2022] 9813347333, 9789813347335

Table of contents :
Foreword
Preface
Contents
About the Editor
Contributors
1 General Situation of Underground Gas Storage Around the World
Introduction
Present Situation of Underground Gas Storage Construction Around the World
Development History of Underground Gas Storage
Distributions of the Working Gas Volume of Underground Gas Storage Facilities in Different Regions
Proportion of the Working Gas Volume Accounted for by the Various Types of Underground Gas Storage
Peak Daily Gas Production Rate Per Unit of the Various Types of Underground Gas Storage
Future Development Plan for Underground Gas Storage Around the World
Development History of Underground Gas Storage Around the World
Forces Driving the Increasing Demand for Gas
Forces Driving the Increasing Demand for Underground Gas Storage
Analysis of the Demand in Different Regions
Main Development Trend
The Construction and Development of Underground Gas Storage Facilities Around the world
Underground Gas Storage Facilities in Typical Countries and Regions
The United States
Current Status of Underground Gas Storage in the United States
Analysis of the Development of the Gas Storage Capacity in the United States
Russia
European Union
England
Supply and Demand Status of Natural Gas
Current Status of Natural Gas Reserves
Germany
Supply and Demand Status of Natural Gas
Status of Natural Gas Reserves
France
Supply and Demand Status of Natural Gas
Status of Natural Gas Reserves
Conclusions
References
2 Banqiao Reservoir Geology and Storage Design
Introduction
Geological Overview
Stratigraphic Characteristics
Structural Characteristics
Dazhangtuo
Ban876
Central North Banqiao
Central South Banqiao
Ban808
Ban828
Trap Sealing Conditions
Dazhangtuo
Ban876
Central North Banqiao
Central South Banqiao
Ban808
Ban828
Reservoir Characteristics
Gas Reservoir Development Characteristics
Gas Reservoir Characteristics
Dazhangtuo
Ban876
Central North Banqiao
Central South Banqiao
Ban808
Ban828
Development Process
Dazhangtuo
Ban876
Central North Banqiao
Central South Banqiao
Ban808
Ban828
Dynamic Reserves
Construction Scheme of Gas Storage
Conclusion
3 Banqiao Storage Group Multi-cycle Operation
Introduction
Operation Pressure of Multi-cycle Operation
Operation Pressure
The Possibility of Large-Scale Leakage of Gas Storage Is Small
Implemented Volume of Gas-Bearing Pores
Banqiao Storage Capacity
Working Gas Analysis
Division of the Capacity Expansion Stages
Rapid Capacity Expansion Stage
Stable Capacity Expansion Stage
Stagnant Capacity Expansion Stage
Characteristics of the Technical Indicators
Usable Pore Volume
Storage Capacity and Working Gas Volume
Space Utilization Efficiency
Law of Cushion Gas Depletion
High Depletion Period
Depletion Reduction Period
Low Depletion Period
Law of Well Pattern Space
Conclusion
4 Suqiao Gas Storage Group Geology
Introduction
Stratigraphic Characteristics
Characteristics of the Ordovician Strata
Characteristics of the Carboniferous-Permian Strata
Structural Features
Su 1
Su 20
Su 4
Su 49
Guxinzhuang
Sealing Conditions
Reservoir Features
Su1
Su 20
Su 4
Su 49
Guxinzhuang
Types of Gas Reservoirs
Su1
Su 20
Su 4
Su 49
Guxinzhuang
Geologic Model
Modeling Principle
Modeling Process
Reserveverification
Su1
Su 20
Su4
Su 49
Guxinzhuang
Conclusions
5 Suqiao Reservoir Development and Storage Design
Introduction
Characteristics of Gas Reservoir Development
Development History
Su 1 Gas Reservoir
Su 4 Gas Reservoir
Su 49 Gas Reservoir
Su 20 Gas Reservoir
Guxinzhuang Gas Reservoir
Water Invasion State
Su 1
Su 4
Su 49
Guxinzhuang
Production Reserves
Numerical Modeling
Model Establishment
History Fitting
Reserves Fitting
Production History Fitting
Scheme for Building Gas Storage Facilities
Geologic Scheme
Principle of Scheme Design
Gas Storage Capacity
Working Gas Volume
Cushion Gas
Operation Cycle
Design Scheme
Drilling and Completion
Wellbore Structure
Drilling Fluid System
Oil Tube
Surface Engineering
Brief Introduction to the Cyclic Operation
Conclusion
6 Jing 58 Underground Gas Storage Group Reconstructed from a Sandstone Oil Reservoir with a Gas Cap
Introduction
Geological Background
Stratigraphic Characteristics
Structural Characteristics
Sealing Conditions
Cap Rock
Faults
Reservoir Characteristics
Gas Reservoir Development Characteristics
Development History
Jing 58 Underground Gas Storage
Natural Energy Development Stage (March 1989-June 1991)
Full-Scale Water Flooding Development Stage (July 1991-December 1995)
Water Production Control and Oil Production Stabilization Stage (January 1996-July 2002)
Production Decline Stage (August 2002-January 2008)
Yong 22 Underground Gas Storage
Production Reserves
Storage Building Scheme
Geological Scheme
Operation Pressure
Storage Capacity Parameter Design
Well Pattern Design
Drilled Wells
Casing Program
Surface Engineering
Cyclic Injection and Production
Conclusions
7 Shuang 6 Multilayer Sandstone Reservoir Geology
Introduction
Stratigraphic Characteristics
Structural Characteristics
Sealing Conditions
Sealing of the Caprock
Macroscopic Evaluation
Microscopic Evaluation
Sealing Ability of Fault
Depositional Characteristics
Characteristics of the Sedimentary Facies
Sedimentary Facies
Characteristics of Sedimentary Facies in the Shuang 6 Block
Reservoir Characteristics
Lithological and Petrophysical Characteristics
Macroscopic Distribution Characteristics
Heterogeneous Characteristics
Development of Compartments and Interlayers
Development of Compartments
Compartments Between the Oil Units
Compartments Between the Sandstone Units
Development of Interlayers
Types of Gas Reservoirs
Verification of the Reserves
Determination of Reserve Parameters
Reserve Calculation Results
Reasons for Reserve Changes
Conclusions
8 Shuang 6 Reservoir Development and Storage Design
Introduction
Development Characteristics of the Shuang 6 Gas Reservoir
Development History
Water Invasion Status
Production Reserves
Material Balance Method
Numerical Simulation Method
Comparison of the Calculation Results of the Different Methods
Construction Plan for Gas Storage
Geological Plan
Determination of the Operating Pressure
Calculation of the Storage Capacity Parameters
Basic Cushion Gas Volume
Additional Cushion Gas Volume
Effective Working Gas Volume
Maximum Storage Capacity
Gas Injection and Production Capacity of a Single Well
Operation Mode
Operation Cycle
Scheme Design
Well Completion
Wellbore Structure
Drilling Fluid
Wellhead Equipment
Surface Engineering
Brief Introduction to the Periodic Injection-Production Operation
Conclusions
9 Hutubi Gas Storage Facility
Introduction
Geological Overview
Geological Location
Stratigraphic Characteristics
Structural Characteristics
Sealing Conditions
Sealing Performance of the Cap Rock
Macroscopic Evaluation
Microscopic Evaluation
Sealing Performance of the Fault
Longitudinal Sealing Performance
Lateral Sealing Performance
Sedimentary Characteristics
Profile Characteristics of the Sedimentary Facies
Planar Characteristics of the Sedimentary Facies
Reservoir Characteristics
Lithology and Physical Characteristics
Macroscopic Distribution Characteristics
Gas Reservoir Types
Fluid Properties
Development Characteristics of the Gas Reservoir
Development History
Production Reserves
Construction Plan for Gas Storage
Geology of the Gas Storage
Capacity Parameters of the Gas Storage
Well Pattern Deployment
Drilling and Completion
Well Bore Structure
Well Cementing
Well Completion
Drilling Fluid
Christmas Tree at the Wellhead
Old Well Treatment
Ground Engineering
Construction Scale
Overall Process
Running Brief of the Periodic Injection and Production
Running Brief of the Injection and Production
Effect Evaluation of the Injection and Production
Conclusion
10 Shaan224 Reservoir Geology and Development
Introduction
Stratigraphic Characteristics
Trap Sealing Evaluation
Sealing Properties of Caprock
Sealing Performance of Base Plate
Boundary Sealing
Trenches Are Developed Based on Seismic Data
Limited Well Block Supply Due to Low-Pressure Recovery
Lateral Lithologic Shielding
Reservoir and Fluid
Reservoir Characteristics
Rock Type
Physical Characteristics
Types of Reservoir Structures and Characteristics of Pore Structures
Reservoir Space Type
Pore Structure Characteristics
Fracture-Solution Vug Type
Pore Type
Intergranular Micropore-Fracture Type
Fluid Properties
Geological Reserves
Development History of Gas Reservoir
Macroscopic Characteristics of Gas Reservoir Development
Trap Type
Physical Characteristics of Reservoir
Driving Type of Gas Reservoir
Gas Composition Characteristics
Formation Pressure Characteristics
Dynamic Geological Reserves
Single-Well Pressure Drop Method
Production Uncertainty Analysis
Block-Integral Pressure Drop Method
Conclusion
11 Shaan224 Storage Design Program and Operations
Introduction
Geologic Design Program
Storage Capacity
Upper Pressure Limit
Storage Capacity
Lower Pressure Limit and Volume of Working Gas
Injection/Production Wells
Gas Storage Program
Mode of Operations
Operation Cycle of Gas Storage
Drilling and Completion Operations
Casing Program
Casing Program of Horizontal Wells
Casing Program of Vertical Wells
Drilling Fluid System
Identification of Optimal Anticollapsing Drilling Fluid
Selection of Optimal Drilling Fluids for Reservoir Protection
Principles for Shielding and Temporary Plugging
Identification of Optimal Plugging Agents
Properties of Anticollapsing and Plugging Drilling Fluids
Casing and Tubing Materials
Corrosion Protection and Reservoir Stimulation
Surface Engineering
Overall Process Flow of Gas Storage
Injection/Production Engineering
Injection, Production, Gathering, and Transmission Processes
Hydrate Inhibition Process
Separation Process
Dehydration Process
Pressurization Process
Well Site
Horizontal Wells for Injection/Production Operations
SCK-8 Test Well for Gas Injection/Production
Standby Vertical Wells and Existing Wells
Gathering Station
Pipeline Network
Gas Injection Pipelines
Gas Production Pipelines
Two-Way Gas Transmission Pipelines
Tie-Lines
Storage Operations
Conclusion
12 Geology and Development of the Xiangguosi Dolomite Storage
Introduction
Geological Overview
Stratigraphic Characteristics
Structural Characteristics
Sealing Conditions
Sealing Properties of Caprock
Fault Sealing
Reservoir Characteristics
Lithological, Mineralogical, and Physical Characteristics
Macroscopic Distribution Characteristics
Type of Gas Reservoir
Development Characteristics of the Gas Reservoir
Development History
The Gas Reservoirs Have a Long-Term, High, Stable Production and a High Recovery
The Gas Wells in the Gas Reservoir Have Good Connectivity, Balanced Production, and No Obvious Pressure Drop Funnel
The Gas Wells Have Large, Stable Productivities
The Edge Water of the Gas Reservoir is Inactive, Which Does Not Have a Significant Impact on the Production of the Gas Reservo...
Reserves in Development
Technical Recoverable Reserves
Conclusions
13 Xiangguosi Gas Storage Design and Operation
Introduction
Construction Geology of the Gas Storage Project
Drilling and Completion
Wellbore Structure
Cementing
Cement Casing Selection and Strength Check
Cementing Method and Casing String Structure Scheme
Formulation Scheme of the Cement Slurry System
Completion
Drilling Fluid
Wellhead Christmas Tree
Old Well Treatment
Ground Engineering
Injection-Production Operation
Conclusion
14 Jintan Complex Layered Salt Rock Gas Storage
Introduction
Geological Overview
Stratigraphic Characteristics
Structural Characteristics
Analysis of the Salt Rock Bed and Caprock Conditions
Depositional Environment
Physical Properties of the Salt Bed and Its Interbeds
Development Characteristics
Development Characteristics
Utilized Reserves
Construction Design for the Gas Storage Facility
Deployment of the Wellsites
Design of Single Cavity Morphology and Cavity Construction Project
Operating Pressure Design
Drilling Engineering Design
Engineering Design for gas Injection and Brine Production
Aboveground Engineering Design
Engineering Construction Analysis
Overview of the Periodic Injection-Production
Overview of Project Construction
Analysis of the Injection and Poduction
Conclusions
15 Liuzhuang Multilayer Complex Lithologic Gas Storage with Oil Rim
Introduction
Geologic Setting
Stratigraphic Characteristics
Structural Characteristics
Sealing Conditions
Sealing Performance of Caprock
Sealing Performance of Faults
Sedimentary Facies
Reservoir Features
Lithological and Physical Properties
Macroscopic Distribution
Development of Barrier Layers and Interbeds
Types of Gas Reservoirs
Reserve Verification
Layered Verification and Calculation of Geological Reserves
Volumetric Method
Numerical Simulation Method
Analysis of Gas Reserve Calculations
Calculation of the Dynamic Gas Reserves
Evaluation of Geological Gas Reserves
Development Characteristics of Gas Reservoirs
Overview
Development Characteristics
UGS Design
Geologic Plan
Drilling and Completion Plan
Ground Engineering Plan
Periodic Injection and Production
Brief Introduction
Effect of Injection-Production Operation
Conclusions
16 Wen96 Storage with Multilayer, Low Condensate Oil
Introduction
Geology
Stratigraphic Characteristics
Structural Features
Sealing Conditions
Reservoir Characteristics
Sedimentary Facies
Rock-Mineral Characteristics
Physical Property Characteristics
Gas Reservoir Type
Development Characteristics of the Gas Reservoir
Overview of the Development
Development Characteristics
Production Reserves
Gas Storage Construction Program
Geologic Plan
Drilling and Completion Program
Drilling and Completion
Casing Program
Drilling Fluid
Completion of the Injector-Producer
Perforation Completion
String
Pipe Selection
Wellhead Assembly
Surface Works
Gas Injection Process
Gas Recovery Process
Compressor
Dew Point Control Process
Brief Introduction of the Multicycle Injection-Production Operation
Conclusions
17 Market Demand for Underground Gas Storage in China
Introduction
Natural Gas Market Demand
Distribution of Natural Gas Pipeline Networks
Resource Preparation and Sales Planning
Method of Calculating the Peak-Shaving Demand
Regional Climate and Peak Regulation Characteristics
Gas Structure
Nonuniformity
Result of Peak-Shaving Demand
Gas Storage Demand
Technical Preparations for Gas Storage Facility Construction
Conclusions
18 Potential Reservoir Candidates for the Construction of UGS Facilities in Northeastern and Southeastern China
Introduction
Daqing Oil Region
Medium-Shallow Gas Fields
Deep Gas Fields
Jilin Oil Region
Liaohe Oil Region
Yangtze River Delta Region
Southeastern Coastal Region
Guangdong Province
Guangxi Province
Conclusions
19 Potential Reservoir Candidates for the Construction of UGS Facilities in the Circum-Bohai Sea Region
Introduction
Dagang Oil Region
Huabei Oil Region
Jidong Oil Region
Shengli Oil Region
Conclusions
References
20 Potential Reservoir Candidates for the Construction of UGS Facilities in Central and Western China
Introduction
Central-Southern China
Zhongyuan Oil Region
Henan Oil Region
Jianghan Oil Region
Southwestern China
Northwestern China
Qinghai Gas Region
Tarim Gas Region
Tuha Gas Region
Central-Western China
Conclusions
21 Features of Gas Storage Facilities Constructed from Gas Reservoirs in China
Introduction
Main Features of Gas Storage Facilities Constructed from Gas Reservoirs
Geology and Gas Reservoir Techniques
Drilling and Completion Techniques
Surface Engineering Technology
Conclusions
22 Geological Evaluation for Gas Storage Construction in Reservoirs
Introduction
Gas Storage Structure
High Precision Depiction of Traps
Detection of Faults and Fractures
Research on Micro-Small Faults
Sealing Property of Traps
Static Sealing Property of Faults
Lithologic Sealing Property
Mechanical Characteristics of Fault Plane
Properties of Fluids on the Two Sides of a Fault
Fluid Inclusions
Static Sealing Property of Caprocks
Microscopic Sealing Property
Macroscopic Sealing Property
Logging Data
Reservoir Spaces
Microscopic Pore Structure Characteristics
Evaluation of Effective Storage Spaces
Evaluation of Fluid Seepage Capability
Trap Modeling
Determination of the Trap Modeling Range
Fine Geologic Modeling Requirements
Reservoir Fracture System Characterization
Calculation of Effective Spaces of Reservoirs
Conclusion
References
23 Design of the Storage Capacity Parameters of Underground Gas Storage Facilities in China
Introduction
Factors Controlling the Pore Space Utilization
Physical Properties and Heterogeneity of Reservoirs
Formation Water Invasion
Stress Sensitivity
Changes in the Fluid Properties After Gas Injection
Effective Pore Volume During Gas Storage Construction
Basic Principle
Simplified Model of a Gas Storage Space
Effective Pore Volume During Gas Storage Construction
Original Gas-Bearing Pore Volume of the Gas Reservoir
Unavailable Pore Volume in the Water-Flooded Zone
Unavailable Pore Volume in the Transition Zone
Unavailable Pore Volume in the Gas-Driven Pure Gas Zone
Reservoir Stress-Sensitive Plastic Deformation
Decrease in Pore Volume Due to Retrograde Condensation of Condensate Oil
Volume Affected by Secondary Saturation, Dissolution, and Separation of the Remaining in-Place Oil
Upper Pressure Limit
Basic Principle
Design Method
Caprock
Fault
Spill Point
Sealing Property of the Boundary Strata
Upper Pressure Limit Value Selection
Lower Pressure Limit
Basic Principles
Design Method
Storage Capacity
Basic Principles
Effective Pore Volume of the Gas Storage Construction
Constant-Volume Gas Reservoir
Weak-Medium Water-Invasion Sandstone Gas Reservoir
Sandstone Gas Reservoir with an Oil Rim
Storage Capacity Calculation
Cushion Gas Volume and Working Gas Volume
Cushion Gas Volume
Working Gas Volume
Additional Cushion Gas Volume
Conclusions
References
24 Design of Geologic Scheme for Gas Storage Construction
Introduction
Scheme Design Principle
Basic Principle
Market Demand and Functional Orientation
Technical Economy
Safety and Environmental Protection
Operation Mode
Operation Cycle
Injection and Production Operation Scheme
Injection and Production Series of Strata
Main Considerations
Analysis of Injection-Production Series of Strata Design
Scheme Design of Injection and Production Series of Strata
Analysis of the Technical Indexes of the Basic Scheme
Analysis of the Technical Indexes of Scheme 2 (Commingled Injection and Production)
Analysis of the Technical Indexes of Scheme 3 (Separate Layer Injection and Production)
Optimization of the Technical Indexes of the Comparison Schemes
Design of the Gas Injection and Production Capacity of Single Wells
Gas Well Productivity Equation
Comprehensive Analysis of Node Pressure
IPR&OPR Equation of Gas Production Wells
IPR&OPR Equation of Gas Injection Wells
Comprehensive Analysis of Gas Injection and Production Node Pressure
Injection-Production Well Pattern Design
Main Considerations
Design of Reasonable Well-Pattern Density
Optimal Design of the Injection and Production Operation Scheme
Scheme Design Process
Prediction Methods for Injection and Production Indexes
Suggestions on the Deployment and Implementation of the Geologic Scheme for Gas Storage Construction
Geologic Scheme Deployment
Drilling Arrangement and Deployment
Scheme Implementation Requirements
Monitoring Scheme
Gas Storage Monitoring System
Gas Storage Monitoring Mode
Well Engineering Monitoring
Trap Sealing Property Monitoring
Internal Operation Dynamics Monitoring
Gas Storage Monitoring Content and Requirements
Conclusion
References
25 Methodology of Inventory Management
Introduction
Operation Monitoring and Data Management
Dynamic Monitoring and Data Acquisition
Data Management and Analysis
Inventory Management and Evaluation
Concept of Inventory
Analysis of Operation Curves
Analysis and Prediction of the Technical Inventory Indexes
Definition of the Technical Inventory Indexes
Analysis and Prediction of the Inventory Indexes
Injection and Production Operation Evaluation
Prediction of the Capacity
Prediction of the Injection and Production Capacity of a Single Gas Storage
Optimization of the Production Allocation and Injection Allocation of a Gas Storage Group
Preparation of the Cyclic Injection and Production Scheme
Inventory Concepts and Model
Multicycle Operation Curve
Ideal Curve
Stable Curve
Operation Curve of a Constant-Volume Gas Reservoir
Operation Curve of a Water-Invasion Gas Reservoir
Capacity Expansion and Realization Curve
Leakage Analysis of a Water-Invasion Gas Reservoir
Leakage Mechanism
Leakage Type
Leakage Operation Curve
Conclusions
References
26 Methodology of Inventory and Deliverability Prediction
Introduction
Basic Principle of the Inventory Prediction Model
Mathematical Model
Available Inventory
Available Gas-Bearing Pore Volume
Available Storage Capacity
Available Cushion Gas Volume
Working Gas Volume
Total Cushion Gas Volume
Total Storage Capacity
Cushion Gas Variation
Cushion Gas Loss Rate
Evaluation of the Multicycle Gas Injection and Production Capacity
Gas Injection Capacity Prediction Model
Gas Production Capacity Prediction Model
Evaluation of the Gas Injection and Production Capacity in a Cycle
Theoretical Models
Statistical Models
Gas Reservoir Engineering Method for Optimizing the Production Allocation
Basic Principle
Basic Principles for Optimizing the Production Allocation
Mathematical Model for Production Allocation Optimization
Target Conditions for Production Allocation Optimization
Constraints on Production Allocation Optimization
Mathematical Model for Production Allocation Optimization
Solution Process of the Production Allocation Optimization
Optimized Production Allocation Scheme
Gas Reservoir Engineering Method for Optimizing the Injection Allocation
Basic Principle
Assumptions
Mathematical Model for Injection Allocation Optimization
Target Conditions for Injection Allocation Optimization
Constraints for Injection Allocation Optimization
Mathematical Model for Injection Allocation Optimization
Solution Process of the Injection Allocation Optimization
Optimized Injection Allocation Scheme
Conclusion
References
27 Design of Hole Structure and Casing String in UGS Drilling
Introduction
Drilling Design for Gas Storage Facilities
Drilling Design Principles
Drilling Mode Optimization
Analysis of the Advantages and Disadvantages of Vertical Well Drilling
Analysis of the Advantages and Disadvantages of Directional Well Drilling
Selection of Well Completion Methods for Gas Storage Facilities
Completion Requirements for Injection and Production Wells
Factors to be Considered When Selecting a Completion Method
Completion Method Selection
Completion Method Determination
Open Hole Completion
Perforation Completion
Hole Structure Design of Injection and Production Wells in Gas Storage Facilities
Hole Structure Design Principles for Injection and Production Wells
Hole Structure Design Principle
Hydrostatic Fluid Column Pressure
Overburden Pressure
Formation Pressure
Formation Fracture Pressure
Formation Collapse Pressure
Pressure System in a Wellbore
Equivalent Gradient Distribution in a Liquid Pressure System
Hole Structure Design Methods and Steps
Determination of the Casing Size and Hole Size
Casing String Strength Design and Material Optimization
Technical Requirements for the Casing String
Technical Requirements for Threads
Drilling Fluid Technology
Drilling Fluid Property Requirements
Drilling Fluid System Optimization
Introduction to Drilling Fluid Systems Used in Gas Storage Construction
Composition
Performance Characteristics
Composition of the Organosilicon Antisloughing Drilling Fluid System
Performance Characteristics of the Organosilicon Antisloughing Drilling Fluid System
Composition of the Solid-Free KCl Polymer Drilling Fluid System
Performance Characteristics of the Solid-Free KCl Polymer Drilling Fluid System
Performance Evaluation of the Solid-Free KCl Polymer Drilling Fluid System
Determination of the Drilling Fluid Parameters and the Maintenance of the Drilling Fluid Properties
Determination of the Drilling Fluid´s Density
Drilling Fluid Solid Control
Conclusions
28 Reservoir Protection and Cementing Techniques
Introduction
Reservoir Protection Technique
Reservoir Damage Factors During Drilling and Completion
Internal Gas Reservoir Damage Factors
Engineering Factors for Gas Reservoir Damage
Reservoir Protection Measures for Drilling and Completion Engineering
Reservoir Protection Measures During Cementing
Reservoir Protection Measures During Perforation
Complete Sets of Pressure Sealing Techniques for Gas Storage Construction
Research on the Pressure Sealing Mechanism
Occurrence Mechanism of Formation Fracturing (Low Pressure Bearing Capacity)
Causes of Formation Fracturing or Low Pressure Bearing Capacity (Failure to Bear Pressure)
Natural Vertical Fractures, Micro-fractures, and Induced Fractures
Wellbore Strengthening Technique
Selection of Circulation Loss Materials
Cementing Technique for Gas Storage Facilities Constructed from Depleted Gas Reservoirs
Particularity of and Difficulties Involved in the Cementing of Gas Storage Facilities Constructed from Depleted Gas Reservoirs
Tough Cement
Complete Sets of Cementing Techniques for the Construction of Gas Storage Facilities from Depleted Gas Reservoirs
Formulation of the Cementing Technique Specifications and Quality Evaluation Specifications for Gas Storage Facilities
Conclusions
29 Technical Measures for Ensuring Storage Wellbore Integrity
Introduction
Hermetic Seal Test Equipment for Tubing and Casing Threads
Technical Background
Technique Principles and Equipment Composition
Technical Breakthroughs
Technological Measures for Running Casing
Identification of the Risks During Casing RIH
Technological Guarantee Measures for Casing RIH
The Efficiency of the Tubing and Casing RIH Operations Should be Improved
Completion Tool RIH and Wireline Operations
Annulus Protection Fluid Injection
Packer Setting Through the Wireline Operation
Analysis and Evaluation of the Sealing Integrity of the Cement Sheath
Gas Storage Well Operation Characteristics and Requirements for the Sealing Property of the Cement Sheath
Analysis and Evaluation of the Sealing Integrity of the Cement Sheaths in Gas Storage Wells
Post-cementing Quality Evaluation
Wellbore Safety Pressure Test Technology
Wellhead Equipment Optimization
Wellhead Equipment
Wellhead Safety Control System
Anticorrosion of the Tubing and Casing
Conclusions
30 Treatment and Utilization of Existing Old Wells Legacy
Introduction
Basic Principles for the Evaluation and Treatment of Old Wells
Data Required for Evaluation
Basic Principles for the Evaluation and Treatment of Old Wells
Old Well Evaluation Content and Methods
Old Well Utilization Technology
Old Well Utilization Principles
Reutilization Technology for Old Well Workover
Old Well Plugging Technique
Specific Method and Parameter Optimization
Old Well Treatment Construction Process
Old Well Plugging Construction Techniques
Old Well Plugging Construction Steps
Optimization of the Parameters of Old Well Plugging Techniques
Conclusions
31 Injection and Production String Design
Introduction
Design of the Injection and Production Parameters
Basic Principles
Injection and Production Capacity Optimization
Calculation of the Restricted Flow Rate
Minimum liquid-carrying flow rate
Maximum erosion flow rate
Reasonable Flow Rate and Tubing Size
Gas production stage
Gas injection stage
Tubing Size Optimization
Tubing Design
Functional Requirements for the Injection and Production String
Selection of the tubing threads
Tubing Material Selection
Tubing Strength Checking
Optimization of the Downhole Supporting Tools
Downhole Safety Valve
Circulating Sliding Sleeve
Packer
Setting Nipple and Blanking Plug
Conclusions
32 Wellhead Equipment and Production String RIH
Introduction
Completion Technology for Injection and Production Wells
Perforation Technology
Combined Operation Technology
Wellhead Equipment Requirements
Technical Requirements and Testing of the Casing Heads
Technical Requirements and the Selection of the Christmas Tree
Basic Requirements
Optimization of the Technical Parameters
Wellhead Safety Control System
Main Equipment
Connection Method
Production String RIH
Production String Preparation and Inspection
Improving the Efficiency of the RIH Operations
Completion Tool RIH and Wireline Operations
Pipe Scraping and Drifting
Running Completion Tools
Injection-Production Wellhead Installation
Reverse Circulation Well Cleanout
Annular Protective Fluid Injection
Packer Setting Through the Wireline Operation
Measures for Ensuring the Sealing Integrity of the String
Conclusions
33 Wellbore Monitoring and Tubing-Casing Annulus Protection
Introduction
Tubing-Casing Annulus Protection
Analysis of the Corrosion Factors
DO Corrosion
Dissolved Salt Corrosion
Microbiological Corrosion
Evaluation of the Corrosion Resistance of the Protective Fluid
Monitoring of the Injection and Production Well Parameters
Routine Patrol Inspection and Monitoring
Temporary Monitoring
Real Time Monitoring
Pressure Measuring Device with Capillary
Pressure Measuring Device with an Electronic Pressure Gauge
Pressure Measuring Device with Optical Fibers
Sealing Property Testing of Injection and Production Wells
Sealing Property Testing Conditions
Maximum Allowable Annulus Pressure
Risk Division Based on Annulus Pressure
Wellbore Sealing Property Testing Conditions
Annulus Pressure Relief/Buildup Test
Diagnosis after the Pressure Relief/Buildup Test
Analysis of the Returned Fluids
Tubing Leakage Positioning
Production Logging, Pressure Interference Testing, and Temperature Logging
Mechanical Integrity Testing
Analysis of the Pressure Relief and Buildup Characteristics
Wellbore Sealing Integrity Testing
Chinese and Foreign Integrity Testing Regulations
Sealing Integrity Testing Method
Conclusions
34 Gathering and Transportation Processes for Storage Surface Engineering
Introduction
Design Principles for the Surface Engineering of Gas Storage Facilities
General Layout
Optimization Principles for the General Layout
Station Site Selection Principles
Example of the Optimization of the General Layout
Injection and Production Wellhead
Injection and Production Valve Group or Gathering and Distribution Station
Conclusions
35 Pipe Network and Gathering Station
Introduction
Injection and Production Pipe Network
Injection and Production Pipe Network Setting
Injection and Production Pipeline Material Selection
Gas Injection System
Selection of the Gas Injection Compressor Units
Filtration and Separation
Cyclone Separators
High-Efficiency Filter Separator
Treatment of the Produced Gas
Produced Gas Pressurization
Venting System Design
Venting Concept
Scale of the Venting System of the Gathering and Injection Station
Setting of the High- and Low-Pressure Venting Systems
Suggestions for Setting up the High- and Low-Pressure Venting Systems
Conclusions
36 Measurement and Public Auxiliary System
Introduction
Transportation System and Oil and Water Treatment
Measurement
Basic Requirements
Measurement Grading and Accuracy
Instrumentation and Automatic Control System
Water Supply and Drainage System and Fire Protection System
Communication
General Provisions
Communication Mode
Electric Power and Building Structure
Conclusions
37 Potential Salt Candidates for Storage in Central and Southern China
Introduction
Henan Pingdingshan Salt Mine
Distribution Characteristics of the Saliferous Strata
Mineral Composition
Stability of the Saliferous Strata
Hubei Yunying Salt Mine
Distribution Characteristics of the Saliferous Strata
Mineral Composition
Stability of the Saliferous Strata
Hubei Huangchang Salt Mine
Distribution Characteristics of the Saliferous Strata
Mineral Composition
Stability of the Saliferous Strata
Hunan Xiangheng Salt Mine
Distribution Characteristics of the Saliferous Strata
Mineral Composition
Stability of the Saliferous Strata
Anhui Dingyuan Dongxing Salt Mine
Distribution Characteristics of the Saliferous Strata
Mineral Composition
Stability of the Saliferous Strata
Jiangxi Qingjiang Salt Mine
Distribution Characteristics of the Saliferous Strata
Mineral Composition
Stability of the Saliferous Strata
Conclusions
38 Potential Salt Candidates for Storage in Other Parts of China
Introduction
Basic Information on the Salt Mines
Salt Mines in the Yangtze River Delta Region
Zhaoji Salt Mine
Distribution Characteristics of the Saliferous Strata
Mineral Composition
Stability of the Saliferous Strata
Huai´an Salt Mine
Distribution Characteristics of the Saliferous Strata
Mineral Composition
Stability of the Saliferous Strata
Salt Mines in Southwestern China
Distribution Characteristics of the Saliferous Strata
Mineral Composition
Stability of the Saliferous Strata
Salt Mines in the Southeastern Coastal Region
Conclusions
39 Geologic Evaluation of Salt Layers in China
Introduction
Basic Elements of Construction of Salt Cavern Gas Storage Facilities
Gas Storage Site Determination
Gas Storage Construction Scheme Design
Gas Storage Construction
Basic Characteristics of the Construction of Salt Cavern Gas Storage Facilities
Complex Geologic Conditions and Large Difficulties in Gas Storage Construction
Complex Gas Storage Construction Process and Long Gas Storage Construction Period
Large Gas Storage Construction Difficulty and High Construction Investment
Difference between Domestic and Foreign Salt Cavern Gas Storage Construction Techniques
Geological Conditions for Gas Storage Construction
Factors Influencing Cavern Construction
Salt Cavern Detection
Structural Analysis of Saliferous Strata
Structure Exploration Deployment and Fine Interpretation
Structure Exploration Deployment
Fine Scale Interpretation
Evaluation of Structures and Faults
Structure Evaluation
Fault Evaluation
Evaluation of the Sealing Properties of Caprocks
Macroscopic Evaluation of the Sealing Properties of Caprocks
Lithologic Evaluation of the Caprocks
Evaluation of the Thickness and Distribution Range of the Caprocks
Microscopic Evaluation of the Sealing Properties of Caprocks
Lithologic Components of Caprocks and Mineral Components of the Main Lithology
Micropore Diameter and Adsorption Capacity of the Caprocks
Caprock Permeability and Formation Breakthrough Pressure
Diffusion Capacity of the Caprocks
Geologic Analysis of the Saliferous Strata
Fine Division and Correlation of the Strata
Sedimentary Facies
Distribution of the Salt Layers
Chemical Characteristics of the Salt Rocks
Description and Evaluation of the Interlayers
Analysis of the Petrochemical Characteristics of the Interlayers
Evaluation of the Sealing Properties of the Interlayers
Stability Evaluation of the Saliferous Strata
Impermeability Analysis of the Saliferous Strata
Stability of the Roofs, Floors, and Faults
Conclusions
References
40 Salt Cavern Construction Design in China
Introduction
Cavern Shape Design
Position of the Salt Cavern Within the Salt Layers
Salt Cavern Shape
Cavern Construction Volume and Effective Gas Storage Volume
Design of the Cavern Construction Parameters
Circulation Mode
String Lifting Times
Cavern Construction String Combination
Water Injection Displacement During Cavern Construction
Cushion Roof Protection
Design Principle
Safety Criterion
Stability Criterion
Cavern Construction Period Criterion
Brine Extraction Concentration Criterion
Design Method
Design Example
Design Volume of the Salt Cavern
Effective Cavern Construction Thickness
Determination of the Salt Cavern´s Shape
Conclusions
41 Salt Cavern Stability Evaluation
Introduction
Uniaxial Compression Test
Triaxial Compression Test
Tensile Test
Creep Property Test
Investigation of the Creep Deformation Properties
Long-Term Strength of Salt Rocks Under Triaxial Stress
Salt Cavern Stability Evaluation
Creep Constitutive Model for the Salt Rocks
Stability Evaluation Standards for Salt Cavern Gas Storage Spaces
Criterion 1: The Tensile Stress-Free Criterion
Criterion 2: The Expansion Criterion
Criterion 3: The Creep Strain Criterion
Criterion 4: The Salt Cavern Convergence Criterion
Stability Evaluation Example Analysis
Geological Conditions of the Gas Storage Space
Selection of the Calculation Parameters
Static Stability Evaluation
Stability Evaluation of the Injection and Production Operation
Conclusions
References
42 Salt Cavern Construction Control
Introduction
Controlling the Shape of the Cavern Using the Well Type
Single-Well Single-Cavern
Double-Well Cavern Construction
Double-Vertical Well Cavern Construction
Directional-Butted Well Cavern Construction
Horizontal Well Cavern Construction
Controlling the Shape of the Salt Cavern During Cavern Construction
Circulation Mode
Two-End Distance
Cushion´s Position
Number of Times the String Is Lifted
Research on the Water Solution Mechanism of Thick Interlayers
Numerical Simulation Analysis of Interlayer Collapse
Numerical Model and Parameters
Analysis of the Numerical Simulation Results
Impact of Interlayer Thickness on Collapse
Impact of Interlayer Depth on Collapse
Impact of Interlayer Span on Collapse
Impact of Salt Cavern Height on Collapse
Basic Conclusions from the Numerical Simulation of Interlayer Collapse
Thick Interlayer Collapse Control Technique
Field Test on a Thick Interlayer
Conclusions
References
43 Salt Cavern Detection and Brine Ejection Techniques
Introduction
Testing the Sealing Property of the Wellbore
Salt Cavern Detection During Cavern Construction
Monitoring of Basic Cavern Construction Data
Sonar Detection
OWC Monitoring
Salt Cavern Sealing Property Testing Method
Testing Method
Testing Process
Evaluation Method
Preparation Before Gas Injection and Brine Ejection
Design of the Injection and Production String and the Brine Ejection String
Gas Injection and Brine Ejection Wellhead Equipment
Injection and Production String and Wellhead Safety Control System
Injection and Production Pipe Components and Brine Ejection String Running Procedure
Gas Injection and Brine Ejection Operation
Influencing Factors
Process and Parameters
Example Analysis
Subsequent Operation After Gas Injection and Brine Ejection
Preparation Work
Main Equipment
Brine Ejection String Pulling-Out Steps
Injection and Production Wellhead Equipment Installation
Continue Gas Injection in the Normal Operation Mode of the Gas Storage Facility
Construction Data Acquisition Requirements
Conclusions
44 Salt Cavern Operation Scheme Optimization and Supporting Surface Engineering
Introduction
Content of the Surface Engineering Support Process
Cavern Construction and Brine Extraction Process
Determination of the Cavern Construction and Brine Extraction Station Scale
Cavern Construction and Brine Extraction Station Processes
Main Process Flow
Gas Injection and Production Process
Gas Injection and Production Station Composition
Determination of the Gas Injection and Production Scale
Selection of Compressors
Selection Principles
Compressor Configuration Scheme
Comparative Selection of Compressor Driver Types
Gas Injection and Production Process
Overall Workflow of the Process
Workflow of Each Unit
Gas Injection Equipment
Gas Production Equipment
Thermodynamic Simulation Calculation Method for the Injection and Production Operation
Storage Capacity Calculation
Salt Layer Temperature Field Simulation
Dynamic Simulation of Wellbore Injection and Production
Dynamic Simulation of Salt Cavern Injection and Production
Hydrate Formation Prediction
Operation Scheme Design Method
Design Principle
Design of the Injection and Production Cycle of a Gas Storage Facility
Design of the Daily Peak-Shaving Gas Volume of the Gas Storage Facility
Reasonable Number of Gas Production Wells for a Gas Storage Facility
Operation Scheme Design Method
Winter Peak-Shaving Scheme Design
Emergency Plan Design
Reserve Scheme Design
Operation Mode Optimization
Conclusions
References
45 Reconstruction Technology for Existing Old Caverns
Introduction
Selection of Existing Old Caverns
Selection Principle
Geologic Conditions
Cavern Conditions
Selection Method
Preselection and Evaluation of Old Caverns
Selection and Evaluation Through Sonar Measurements
Drifting
Logging
Sonar Measurements
Stability Evaluation of Existing Old Caverns
Reconstruction of Existing Old Caverns
Reconstruction Principles for Existing Old Caverns
Reconstruction Technique for Existing Old Caverns
Reconstruction Technology Scheme for Existing Old Brine Extraction Caverns
Reconstruction Technology for Existing Old Brine Extraction Caverns
Milling Construction Process [4]
Milling Construction Principles
Sealing Property Testing of Existing Old Caverns
Testing Principle
Evaluation Method and Criteria
Evaluation Method
Evaluation Criteria
Conclusions
References
46 Potential Aquifer Candidates for Gas Storage in the Yangtze River Delta and Southeastern Coastal Regions
Introduction
Aquifers in Jiangsu Province
Reservoir-Caprock Conditions
Gas Storage Construction Potential
Aquifers in Zhejiang Province
Reservoir-Caprock Conditions
Gas Storage Construction Potential
Aquifers in Anhui Province
Aquifers in Guangdong Province
Reservoir-Caprock Conditions
Reservoir Conditions
Caprock Conditions
Gas Storage Construction Potential
Aquifers in Guangxi Province
Shiwandashan Basin
Guizhong Depression
Hepu Basin
Conclusions
47 Potential Aquifer Candidates for Gas Storage in Central-Southern China
Introduction
Aquifers in Hubei Province
Reservoir-Caprock Conditions
Sandstone Reservoirs of the Qianjiang Formation
Sandstone Reservoirs of the Xingouzui Formation
Gas Storage Construction Potential
Aquifers in Hunan Province
Reservoir-Caprock Conditions
Gas Storage Construction Potential
Aquifers in Jiangxi Province
Reservoir-Caprock Conditions
Reservoir Conditions
Clastic Reservoirs
Carbonate Reservoirs
Caprock Conditions
Gas Storage Construction Potential
Conclusions
48 Integrity Management and Risk Control of Gas Storage Facilities
Introduction
Current Integrity Status of Domestic Gas Storage Facilities
Concept Proposal and Development of Gas Storage Integrity
Integrity Management System of Gas Storage Facilities
Integrity Management System for Geological Gas Storage Bodies
Integrity Management System for Gas Storage Wells
The Integrity Management System for Ground Facilities
Integrity Management for Injection-Production Pipeline
Station Integrity Management
Integrity Management Standards for Gas Storage Facilities
Techniques for Insuring the Integrity of Gas Reservoir-Type Gas Storage Facilities
Design Integrity of Gas Reservoir-Type Gas Storage Facilities
Geological Integrity
Integrity of the String Design
Optimization of the Screw Joint for Gas Sealing of the Gas Storage String
Material Selection for the Gas Storage String
Design Method for String Sealing of Gas Storage Wells
Integrity of Surface Facilities
Integrity of Gas Storage Construction
Cementation Design
Casing, Cementation Tools, and Accessories
Selection of Pipe and Thread Type
Selection of Cementation Tools and Accessories
Cementation Preparation
Casing Running and Cementation
Casing Running
Cementation
Techniques for Ensuring the Integrity of Salt Cavern Gas Storage Facilities
Factors Influencing the Stability of Underground Salt Caverns
Fuzzy Comprehensive Evaluation of the Stability of Underground Salt Caverns
Land Subsidence and Prediction of Salt Cavern Gas Storage Spaces
Case Study of Salt Cavern Integrity
Conclusions
References
49 Integrity of Gas Reservoir Storage Facilities During the Operation Phase
Introduction
Gas Storage Monitoring
Technique for Monitoring the Trap-Sealing Ability
Dynamic Wellbore-Monitoring Technique
Dynamic Monitoring of the Internal Operation Conditions
Monitoring of the Surface Facilities
Techniques for Well Integrity Detection and Evaluation of Gas Reservoir Storage Facilities
Techniques for Assessing the Integrity of the Gas Production Tree and Wellhead Equipment
Casing and Tubing Quality Testing Techniques
Gas Storage Wellbore Integrity Evaluation Technique
The Integrity Detection and Evaluation Techniques for Ground Pipelines in Gas Storage Facilities
Surface Pipeline-Testing Techniques
Nondestructive Testing Techniques for Identifying Internal Defects in the Pipeline
External Pipeline Corrosion Detection Techniques
Techniques for Evaluating the Integrity of Gas Storage Ground Facilities
Techniques for Evaluating the Integrity of a Pipeline
Technical System for Evaluating the Integrity of a Station
Remedial Measures for the Failure Treatment of Injection-Production Wells
Remedial Procedures for the Failure Treatment of Injection-Production Wells
High-Pressure Intermittent Discharge and Examples
Annulus Injection of Heavy Brine or Drilling Fluid
Circulation of Heavy Brine or Drilling Fluid and Repair of the Inner Pipe
Cement Squeezing After Perforation or Milling of the Casing
Conclusions
References
50 Foreign Storage Operation and Management
Introduction
Storage Operation and Management in the United States
Gas Storage Regulations in the United States
Federal Regulations
State Regulations
The Gas Storage Operators in the United States
Gas Storage Facilities Operated by Interstate Pipeline Companies
Gas Storage Facilities Operated by State Pipeline Companies and City Gas Companies
Independent Gas Storage Operators
Rate Regulation of Gas Storage in the United States
Management of Gas Storage Contracts in the United States
Storage Operation and Management in Canada
Scale of Gas Storage in Canada
Gas Storage Authority and Jurisdiction in Canada
The History of Gas Storage Legislation in Canada
Maintenance Management System and Operation Mechanism
Separation of Ownership of Gas Storage Facilities from Regulatory Supervision Power
Environmental Supervision Varies Widely
The Gas Storage Rate Is Gradually Being Marketed
The Influence of Gas Storage Construction on the Development of Other Resources Is Strictly Regulated
Storage Operation and Management in the European Union
Supervision of Underground Gas Storage Facilities
The History of Gas Storage Supervision in the European Union
Main Regulatory Requirements
Regulatory Authorities and Methods
Operation Mechanism
Pricing Mechanism
Pricing Principle
Pricing Basis
Charging Method
Storage Operation and Management in Russia
Conclusions
References
51 Domestic Storage Operation and Management
Introduction
Analysis of the Characteristics of Foreign Operation Management
Experience and Enlightenment
The Development of Gas Storage Business Operation Management is to Separate from Pipeline Transportation and to Operate Indepe...
The Independent Operation of the Gas Storage Business Makes the Independent Pricing of the Gas Storage Link Inevitable
The Pricing Mechanism of the Gas Storage Link Should Adapt to the Development of the Domestic Natural Gas Industry
Establishing and Improving the Relevant Laws, Regulations, and Regulatory Policies to Promote the Competition and Regulation o...
Ownership of the Gas Storage Operation and Management
Investment and Pricing Mechanism of Gas Storage
Introduction to Examples of Actual Gas Storage Operation Management
Analysis of the Operation and Management Characteristics of Gas Storage Facilities
Prospects for Gas Storage Operation and Management
Future Development Tendency
Assumption of Operation Management
Recent Assumptions
Medium- and Long-Term Vision
Conclusions
References
Index

Citation preview

Xinhua Ma Editor

Handbook of Underground Gas Storages and Technology in China

Handbook of Underground Gas Storages and Technology in China

Xinhua Ma Editor

Handbook of Underground Gas Storages and Technology in China With 419 Figures and 254 Tables

Editor Xinhua Ma Research Institute of Petroleum Exploration and Development China National Petroleum Corporation Beijing, China

ISBN 978-981-33-4733-5 ISBN 978-981-33-4734-2 (eBook) ISBN 978-981-33-4735-9 (print and electronic bundle) https://doi.org/10.1007/978-981-33-4734-2 Jointly published with Petroleum Industry Press, Beijing, China The print edition is not for sale in China (Mainland). Customers from China (Mainland) please order the print book from: Petroleum Industry Press. Translation from the language edition: Zhong Guo Di Xia Chu Qi Ku by Xinhua Ma, © Petroleum Industry Press 2018. Published by Petroleum Industry Press. All Rights Reserved. © Petroleum Industry Press 2022 This work is subject to copyright. All rights are reserved 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

Clean energy is the theme of China for purpose of pollution prevention and control at the decisive stage of building a moderately prosperous society in all respects. Natural gas, as a typical efficient and clean energy, is the most realistic option. Since the beginning of the twenty-first century, China’s gas industry has evolved rapidly. The gas consumption rose from 240  108 m3 in 2000 to 2,400  108 m3 in 2017, making China the third largest gas consumer in the world. It is expected to exceed 5,000  108 m3 by 2030, when natural gas will become the main clean energy supporting the green and sustainable development of China. For the healthy development of China’s gas industry, it is inevitable to enhance the gas infrastructures and maintain coordination among production, transmission, storage, and utilization in the entire gas industry chain. Underground gas storage (UGS) is a strategic infrastructure that ensures the efficiency and safety of gas pipelines, the effective seasonal peak-shaving, the emergency response for long-distance pipelines, and the national energy security. Abroad, UGS has been operating for about 100 years, and nearly 700 UGS facilities are in place, which have a total annual working capacity of 3,600  108 m3, approximately accounting for 11% of the world’s annual gas consumption. In the countries/regions where gas is maturely utilized, such as the United States, Russia, and the European Union, the annual working capacity of UGSs reaches 15–20% of their annual gas consumption. UGS has been proved indispensable in the gas supply system dominated by large-scale long-distance pipelines. In China, the UGS construction was remarkable in the past 20 years, and has become a critical solution to peak shaving in winter. UGS has played an important role in China’s gas security. With the increase of gas consumption, demand for UGS will grow fast. It is expected that China’s demand for UGS will exceed 750  108 m3 by 2030. Thus, UGS construction will remain an arduous task. With 4 years effort, Professor Ma Xinhua and his team completed the book Handbook of Underground Gas Storages and Technology in China. This book reviews the achievements and technologies in the past 20 years and proposes the prospects of China’s UGS construction. The readers can get a systematic and

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Foreword

comprehensive knowledge of UGS in China through this masterpiece. I believe this book can be used as a theoretical and technical guidance for UGS construction, thereby contributing to China's UGS industry. Academician of the Chinese Academy of Engineering August 26, 2018

Hu Wenrui

Preface

An underground gas storage (UGS) is a kind of artificial gas field or gas reservoir, which is formed when natural gas is re-injected into natural or artificial underground structures, for example, depleted oil and gas reservoirs, aquifers, salt caverns, and abandoned pits. It is a kind of gas storage facility which integrates the functions of seasonal peak shaving, emergency gas supply, and strategic reserve. There are mainly four types of underground gas storage: oil/gas reservoir UGS, aquifer UGS, salt cavern UGS, and the other types (rock caverns and abandoned mine/pit type). Different types of UGSs are different in terms of gas storage structure, working principle, investment, and reservoir construction engineering technology. In China, site selection of UGS is related to the market demands of natural gas, the locations of the main consumption areas, and the distribution of gas pipelines. It is also closely related to the distribution of domestic oil and gas resources, especially the distribution of gas reservoirs and the reservoir-caprock assemblage conditions in sedimentary basins. For porous reservoir UGSs (including oil/gas reservoir UGSs and aquifer UGSs), it is necessary to select the traps with smaller burial depth, good reservoir physical properties, complete structures, and cap rocks with good sealing capacity to rebuild UGSs. For salt cavern UGSs, it is necessary to select the salt bearing strata with small burial depth, thick salt beds, high salt content, and fewer interbeds to rebuild UGSs. In the major natural gas consumption areas in eastern China, however, the shallow strata suitable for construction of UGS are under the dual influence of tectonic movement and continental sedimentation. Therefore, it is more difficult to select the ideal UGS site. Because of this, UGS site selection and construction in China is obviously different from that abroad. China’s UGSs are characterized most obviously by great burial depth, complex structure, and poor reservoir or salt bed conditions. Due to the complex geological conditions in China, the UGS construction in China will inevitably be unique, which must be in accordance with the complex geological conditions in China on the basis of foreign UGS construction experience. The main challenges in the construction of underground gas storage in China include the following: the complex geological structures, especially the deep burial depth of gas reservoir, the broken structure, and strong heterogeneity of the reservoir. Therefore, it is very difficult for site selection and design. To rebuild a UGS from the depleted gas reservoir, due to the low reservoir pressure and strong alternating load, vii

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Preface

it has high requirements on the drilling and completion engineering of UGS well. There is no key technology and equipment for the surface injection and production under high pressure and at high flow rate, which is suitable for the largedisplacement fast injection and production of UGSs. The long-term safe operation of the UGSs in complex structures is of great risk. In spite of these great challenges, with great efforts by China’s UGS constructors, through continuous exploration and practice, a great number of difficulties have been overcome, and remarkable achievements have been made in the construction of UGS. From 2000, when the first domestic commercial UGS (i.e., Dazhangtuo UGS in Dagang Oilfield) was put into operation, up to the end of 2017, 23 gas reservoir UGSs had been built and 2 salt cavern UGSs had been put into operation in China. The peak shaving capacity of the built UGSs is over 100  108 m3, which play an important role in peak shaving and supply guarantee. After great efforts for 20 years, not only 25 UGSs have been built, but also a complete set of technologies and standard systems have been established for site selection and evaluation, engineering technology, equipment manufacturing, and operation control of UGS in complex geological conditions. From 1996 to 2003, as the deputy director of the Langfang Branch of PetroChina Research Institute of Petroleum Exploration & Development, I took charge of and participated in the site screening of Banqiao UGS in Dagang Oilfield and the site selection design of Jintan UGS for West-to-East Gas Pipeline. Since then, I formed an inextricable relationship with the underground gas storage. In 2010, PetroChina began constructing UGSs in a large scale. As the deputy general manager of PetroChina Exploration & Production Company, I was in charge of PetroChina’s UGS site selection, evaluation, design, and construction. From 2010 to 2014, PetroChina built a series of UGSs successively, for example, Hutubi UGS of Xinjiang Oilfield, Xiangguosi UGS of Southwest Oil & Gasfield, Banqiao UGS of Huabei Oilfield, Shuang 6 UGS of Liaohe Oilfield, Bannan UGS of Dagang Oilfield, and Shaan 224 UGS of Changqing Oilfield, which increases rapidly the working gas volume of UGS for PetroChina. As a witness of China’s UGS construction, with rich experience in UGS site selection, design, and construction in recent years, referring to the development experience of the developed countries in in UGSs, I truly feel that the future UGS demand in China is huge and the construction task is arduous. Therefore, it is necessary to systematically summarize China’s UGS construction technologies and achievements in the last 20 years, so as to provide the reference for future UGS construction in China and promote the development of UGS in China. In this regard, I began the compilation of this book in early 2006. Together with the compilation team, we spent 2 years in investigating a great number of domestic and foreign literatures related to UGS and collecting the data and research achievements of domestic built UGSs. We also summarized the construction technical characteristics of different types of UGSs and analyzed the site resources in the key regions of China, and discussed the future UGS construction scale and operation management model. After summarization and extraction, the main contents of this book were prepared. However, limited by the length of the book, a lot of good management

Preface

ix

experience formed in the process of UGS construction in China could not be introduced in this book. I feel sorry for this. I sincerely hope that this book is able to provide the reference and assistance to personnel working in the field of UGS and those want to know about China’s UGSs. The preface was written by Ma Xinhua. The main contributors of this handbook, which is divided into 51 chapters, are Ma Xinhua, Ding Guosheng, and Tang Ligen, and other contributors are as follows: He Gang, Zheng Dewen, Wang Jieming, Zheng Yali, Zhu Huayin, Wanyan Qiqi, Zhao Kai, Wei Huan, Pei Gen, Li Kang, Song Lina, Zhong Rong, Lai Xin, Zhang Min, Ran Lina, Xu Hongcheng, Zhang Gangxiong, Sun Junchang, Sun Chunliu, Li Chun, Li Dongxu, Qi Honglin, Shi Lei, Qiu Xiaosong, Wu Zhide, Gou Yanxia, Zhao Yanjie, Jiang Huaquan, Wang Chunyan, Qi Fengzhong, Liu Zhuchen, Li Jingcui, Fu Taisen, Sun Jianhua, Zhang Zhe, Wang Zhaohui, Wen Yunhao, Luo Jinhuan, Li Lifeng, Wang Jianjun, and Chen Hongjian. The handbook was compiled and revised by Ma Xinhua, Ding Guosheng, and Tang Ligen. The entire handbook was finally edited by Ma Xinhua. During the compilation of this book, we got the guidance from Zhao Zhengzhang, the director general of China Petroleum Society. We also obtained great assistance from Tang Lin, the deputy general manager of PetroChina Exploration & Production Company, and got help from Mao Yuncai and Ban Xing'an, the director of PetroChina Exploration & Production Company. We also appreciate the abundant precious data provided by CNPC Engineering Technology Research Institute, PetroChina Xinjiang Oilfield Company, PetroChina Southwest Oil & Gasfield Company, PetroChina Huabei Oilfield Company, PetroChina Dagang Oilfield Company, PetroChina Liaohe Oilfield Company, PetroChina Changqing Oilfield Company, PetroChina Beijing Gas Pipeline Co., Ltd., and PetroChina West-East Gas Pipeline Company. UGS is a complex system engineering project, involved with geological exploration, UGS design, engineering construction, pipeline transportation, risk control, peak shaving coordination, and operation management. Therefore, it is inevitable that there will be omissions and improprieties in this book. We are looking forward to comments and correction from readers. May 1, 2021

Xinhua Ma

Contents

Volume 1 1

General Situation of Underground Gas Storage Around the World . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Dewen Zheng, Gangxiong Zhang, and Dongxu Li

1

2

Banqiao Reservoir Geology and Storage Design Xinhua Ma

..............

33

3

Banqiao Storage Group Multi-cycle Operation . . . . . . . . . . . . . . . Xinhua Ma

53

4

Suqiao Gas Storage Group Geology . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Jieming Wang, Xiaosong Qiu, and Junchang Sun

73

5

Suqiao Reservoir Development and Storage Design . . . . . . . . . . . . Xinhua Ma

101

6

Jing 58 Underground Gas Storage Group Reconstructed from a Sandstone Oil Reservoir with a Gas Cap . . . . . . . . . . . . . . Xinhua Ma, Kai Zhao, and Chun Li

121

7

Shuang 6 Multilayer Sandstone Reservoir Geology . . . . . . . . . . . . Xinhua Ma, Yali Zheng, Xin Lai, and Kai Zhao

157

8

Shuang 6 Reservoir Development and Storage Design . . . . . . . . . . Xinhua Ma

189

9

Hutubi Gas Storage Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Gen Pei, Hongcheng Xu, and Lina Song

207

10

Shaan224 Reservoir Geology and Development . . . . . . . . . . . . . . . Xinhua Ma

239

11

Shaan224 Storage Design Program and Operations . . . . . . . . . . . . Xinhua Ma

263

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12

Contents

Geology and Development of the Xiangguosi Dolomite Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Ligen Tang, Huaquan Jiang, and Gen Pei

289

13

Xiangguosi Gas Storage Design and Operation . . . . . . . . . . . . . . . Xinhua Ma

315

14

Jintan Complex Layered Salt Rock Gas Storage . . . . . . . . . . . . . . Xinhua Ma and Guosheng Ding

333

15

Liuzhuang Multilayer Complex Lithologic Gas Storage with Oil Rim . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Rong Zhong, Xin Lai, Chunliu Sun, and Yanjie Zhao

377

16

Wen96 Storage with Multilayer, Low Condensate Oil . . . . . . . . . . Xinhua Ma, Huan Wei, Taisen Fu, and Jianhua Sun

421

17

Market Demand for Underground Gas Storage in China . . . . . . . Xinhua Ma

449

18

Potential Reservoir Candidates for the Construction of UGS Facilities in Northeastern and Southeastern China . . . . . . . . Xinhua Ma and Guosheng Ding

467

Potential Reservoir Candidates for the Construction of UGS Facilities in the Circum-Bohai Sea Region . . . . . . . . . . . . . . . Xinhua Ma

489

Potential Reservoir Candidates for the Construction of UGS Facilities in Central and Western China . . . . . . . . . . . . . . . . Xinhua Ma

511

Features of Gas Storage Facilities Constructed from Gas Reservoirs in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Yali Zheng, Junchang Sun, Rong Zhong, and Lei Shi

529

Geological Evaluation for Gas Storage Construction in Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma

541

Design of the Storage Capacity Parameters of Underground Gas Storage Facilities in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma and Ligen Tang

575

19

20

21

22

23

24

Design of Geologic Scheme for Gas Storage Construction . . . . . . . Xinhua Ma

591

Volume 2 25

Methodology of Inventory Management . . . . . . . . . . . . . . . . . . . . . Xinhua Ma and Gang He

639

Contents

26

Methodology of Inventory and Deliverability Prediction . . . . . . . . Xinhua Ma, Ligen Tang, Huayin Zhu, and Hongcheng Xu

27

Design of Hole Structure and Casing String in UGS Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Guosheng Ding, and Jingcui Li

28

Reservoir Protection and Cementing Techniques . . . . . . . . . . . . . . Xinhua Ma, Guosheng Ding, and Ligen Tang

29

Technical Measures for Ensuring Storage Wellbore Integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma and Guosheng Ding

xiii

657

679 701

725

30

Treatment and Utilization of Existing Old Wells Legacy . . . . . . . . Xinhua Ma, Fengzhong Qi, and Zhuchen Liu

749

31

Injection and Production String Design . . . . . . . . . . . . . . . . . . . . . Xinhua Ma and Zhaohui Wang

763

32

Wellhead Equipment and Production String RIH . . . . . . . . . . . . . Xinhua Ma, Yunhao Wen, and Zhuchen Liu

783

33

Wellbore Monitoring and Tubing-Casing Annulus Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Jinhuan Luo, Lifeng Li, Jianjun Wang, and Hongjian Chen

34

Gathering and Transportation Processes for Storage Surface Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma and Chunyan Wang

799

817

35

Pipe Network and Gathering Station . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma and Guosheng Ding

835

36

Measurement and Public Auxiliary System . . . . . . . . . . . . . . . . . . Xinhua Ma and Guosheng Ding

855

37

Potential Salt Candidates for Storage in Central and Southern China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma

867

Potential Salt Candidates for Storage in Other Parts of China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma

895

38

39

Geologic Evaluation of Salt Layers in China . . . . . . . . . . . . . . . . . Xinhua Ma, Guosheng Ding, Honglin Qi, Yanxia Gou, and Min Zhang

917

40

Salt Cavern Construction Design in China . . . . . . . . . . . . . . . . . . . Xinhua Ma, Qiqi Wanyan, Yanxia Gou, and Kang Li

935

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Contents

41

Salt Cavern Stability Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Guosheng Ding, Zhide Wu, and Lina Ran

953

42

Salt Cavern Construction Control . . . . . . . . . . . . . . . . . . . . . . . . . Xinhua Ma, Guosheng Ding, Qiqi Wanyan, and Kang Li

975

43

Salt Cavern Detection and Brine Ejection Techniques . . . . . . . . . . Xinhua Ma and Guosheng Ding

995

44

Salt Cavern Operation Scheme Optimization and Supporting Surface Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . 1021 Xinhua Ma

45

Reconstruction Technology for Existing Old Caverns . . . . . . . . . . 1043 Xinhua Ma

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Potential Aquifer Candidates for Gas Storage in the Yangtze River Delta and Southeastern Coastal Regions Xinhua Ma

. . . . . . . . 1057

47

Potential Aquifer Candidates for Gas Storage in Central-Southern China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1085 Xinhua Ma

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Integrity Management and Risk Control of Gas Storage Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1115 Xinhua Ma

49

Integrity of Gas Reservoir Storage Facilities During the Operation Phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1145 Xinhua Ma

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Foreign Storage Operation and Management Xinhua Ma

51

Domestic Storage Operation and Management . . . . . . . . . . . . . . . 1195 Xinhua Ma

. . . . . . . . . . . . . . . . 1171

Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1213

About the Editor

Xinhua Ma is a professor-level senior engineer. He is an important figure in promoting the construction of underground gas storage in China and a well-known expert in the field of natural gas. He is in charge of the selection of underground gas storage sites in the BeijingTianjin-Hebei region and along the West-East Gas Pipeline. He established the underground gas storage site selection evaluation index system and methods for use in the complex geological conditions in China, completed a feasibility study of the Jintan Salt Cavern Gas Storage project, and opened up a new field in China, that is, the construction of underground gas storage spaces. He is currently the head of the Research Institute of Petroleum Exploration and Development CNPC, the secretary of the party committee and general manager of Petro China Southwest Oil and Gas Field Company, an executive member of the Chinese Petroleum Society, the director of the Natural Gas Committee of the Chinese Petroleum Society, and the deputy director of the Petroleum Geology Committee of the Geological Society of China. The Professor Ma Xinhua’s technical research team has overcome key technical challenges, such as the efficient injection production in reservoir with strong heterogeneity, dynamic geological body sealing, deep ultra-low pressure reservoir drilling, completion, reservoir protection, and efficient treatment of large ground flow. This makes the underground gas storage site selection and construction technologies the most appropriate for the complex geological conditions in China and elsewhere in the world.

xv

Contributors

Xinhua Ma Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Guosheng Ding Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Ligen Tang Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Gang He China National Petroleum Corporation, Beijing, China Dewen Zheng Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Jieming Wang Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Qiqi Wanyan Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Yali Zheng Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Huayin Zhu Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Gen Pei Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Huan Wei Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Min Zhang Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Lina Ran Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China xvii

xviii

Contributors

Kai Zhao Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Rong Zhong Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Kang Li Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Lina Song Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Hongcheng Xu Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Gangxiong Zhang Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Honglin Qi Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Xiaosong Qiu Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Xin Lai Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Chun Li Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Junchang Sun Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Zhide Wu Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Chunliu Sun China National Petroleum Corporation, Beijing, China Yanxia Gou Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Yanjie Zhao China National Petroleum Corporation, Beijing, China Lei Shi Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Dongxu Li Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China Huaquan Jiang China National Petroleum Corporation, Beijing, China Jinhuan Luo China National Petroleum Corporation, xi’an, China Zhuchen Liu China National Petroleum Corporation, Beijing, China

Contributors

Jingcui Li China National Petroleum Corporation, Beijing, China Lifeng Li China National Petroleum Corporation, xi’an, China Fengzhong Qi China National Petroleum Corporation, Beijing, China Hongjian Chen China National Petroleum Corporation, Beijing, China Chunyan Wang China National Petroleum Corporation, Beijing, China Jianjun Wang China National Petroleum Corporation, Beijing, China Zhaohui Wang China National Petroleum Corporation, Beijing, China Yunhao Wen China National Petroleum Corporation, Beijing, China Jianhua Sun PipeChina West East Gas Pipeline Company, Beijing, China Taisen Fu PipeChina West East Gas Pipeline Company, Beijing, China

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General Situation of Underground Gas Storage Around the World Xinhua Ma, Dewen Zheng, Gangxiong Zhang, and Dongxu Li

Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Present Situation of Underground Gas Storage Construction Around the World . . . . . . . . . . . . . . . Development History of Underground Gas Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributions of the Working Gas Volume of Underground Gas Storage Facilities in Different Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proportion of the Working Gas Volume Accounted for by the Various Types of Underground Gas Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Peak Daily Gas Production Rate Per Unit of the Various Types of Underground Gas Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future Development Plan for Underground Gas Storage Around the World . . . . . . . . . . . . . . . Development History of Underground Gas Storage Around the World . . . . . . . . . . . . . . . . . . . . . . . . Forces Driving the Increasing Demand for Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forces Driving the Increasing Demand for Underground Gas Storage . . . . . . . . . . . . . . . . . . . . . . Analysis of the Demand in Different Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Main Development Trend . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . The Construction and Development of Underground Gas Storage Facilities Around the world . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Underground Gas Storage Facilities in Typical Countries and Regions . . . . . . . . . . . . . . . . . . . . . . . . The United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Russia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . European Union . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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X. Ma (*) · D. Zheng · G. Zhang · D. Li Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China e-mail: [email protected]; [email protected]; [email protected]; [email protected]; [email protected]; [email protected] © Petroleum Industry Press 2022 X. Ma (ed.), Handbook of Underground Gas Storages and Technology in China, https://doi.org/10.1007/978-981-33-4734-2_11

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Abstract

This chapter introduces the current status of gas storage around the world, including the development history, distribution of pipeline networks, working gas scale, and peak day gas production capacity. When analyzing the development of gas storage, this chapter focuses on the demand and driving forces of natural gas and the actual situation in the main consumption areas. Based on this, we obtain the following conclusions: gas storage is an important link in the natural gas industry chain, a certain scale must be reserved to ensure the safe supply of natural gas, oil and gas reservoirs are the main type of gas storage reconstruction, and the construction and production cycle is indeed very long. Finally, this chapter introduces the specific situation of gas storage operations in North America, European countries, the Commonwealth of Independent States (CIS) region, and emerging markets represented by China. Keywords

Underground gas storage · General situation · Development · Gas industry chain · Gas storage distribution

Introduction The century-long underground gas storage construction history worldwide shows that as an important link in the natural gas industry chain, underground gas storage is of great significance to ensuring regional energy security. In order to ensure the safety and supply of natural gas, the development history of the world’s gas storage operations, the distribution of gas storage facilities, whether there will be a market demand in the future, what are the main construction types, and which regions have growth potential were analyzed. This chapter describes the current situation, development trend, inspiration, and distribution of gas storage in the major natural gas consuming countries.

Present Situation of Underground Gas Storage Construction Around the World Development History of Underground Gas Storage The construction of the earliest underground gas storage in the world can be traced back to the beginning of the twentieth century, beginning a more than 100-year development history. In 1915, the first gas storage experiment was carried out in the Welland Gas Field in Ontario, Canada. In 1916, the United States used a gas zone to build underground gas storage in the Zoar Gas Field, a depleted gas field near Buffalo, New York. In 1954, the United States used an oil field to store gas for the

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General Situation of Underground Gas Storage Around the World

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first time in the CALG Gas Field in New York City. In 1958, the United States used an aquifer to store gas for the first time in Kentucky. In 1959, the Soviet Union built the first salt bed underground gas storage. In 1961, the United States used a salt cavern to store gas for the first time. In 1963, the United States used an abandoned mine to store gas for the first time near Denver, Colorado. Based on the development characteristics of underground gas storage around the world, the construction of underground gas storage can be divided into three stages: the early development stage, the rapid development stage, and the steady development stage (Figs. 1 and 2). The early development stage mainly occurred before the 1950s. Limited by the technical level of underground gas storage construction, the development of underground gas storage worldwide was relatively slow in this stage. There were only 75 underground gas storage facilities by 1945, and the type of storage was simple. Most of the underground gas storage facilities were formed through the reconstruction of depleted gas reservoirs. After the 1950s, the construction of underground gas storage entered the rapid development stage. Due to the development of the gas market, the gas production rate, and the development of pipelines, the types and quantity of underground gas storage facilities developed rapidly, and the construction of various types of underground gas storage facilities reached its peak during 1970–1980, by which time 120 underground gas storage facilities had been constructed. Since the 1990s, the working gas volume of global underground gas storage facilities has declined, the peak gas production rate has remained the same, and the construction of underground gas storage facilities has entered a steady development stage (Fig. 3). According to the latest statistics from the International Gas Union (IGU) [1], there are a total of 689 underground gas storage facilities around the world at present, with

Fig. 1 Construction history and scale of underground gas storage facilities around the world [1]

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Fig. 2 Variations in the global working gas volume [1]

Fig. 3 Development history of the working gas volume and peak gas production rate [1]

a total working gas volume of 4165.3
108 m3, accounting for about 11% of the total global gas consumption (35,429
108 m3). This is a 232
108 m3 increase in the working gas volume compared with the 3933
108 m3 working gas volume in 2015. The absolute increase was the highest in North America, about 140
108 m3,

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General Situation of Underground Gas Storage Around the World

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followed by Asia (mainly in China, the same in the following), about 57
108 m3, the Middle East (mainly in Iran and the United Arab Emirates, the same in the following), about 33
108 m3, and the Asia-Pacific region (mainly in Australia and Japan, the same in the following), about 21
108 m3. The peak gas production rate of underground gas storage facilities around the world is about 7166
106 m3/d, i.e., 510
106 m3/d greater than in 2015. The increase was the highest in North America (551
106 m3/d), followed by the Commonwealth of Independent States (45
106 m3/d), Asia (11
106 m3/d), and the Middle East (4.4
106 m3/d).

Distributions of the Working Gas Volume of Underground Gas Storage Facilities in Different Regions The total working gas volumes of the underground gas storage facilities in North America, the Commonwealth of Independent States, and the European Union account for 39% (1627
108 m3), 28% (1186
108 m3), and 26% (1088
108 m3) of the global volume, respectively (Fig. 4, Table 1). The average proportion of the annual gas consumption accounted for by the annual working gas volume of the underground gas storage facilities in the above three regions is 14%. The number and working gas volumes of the underground gas storage facilities in the United States are the largest in the world, with 393 underground gas storage facilities and a working gas volume of 1360.8
108 m3, accounting for 17.48% of the annual gas consumption. The proportion of the annual gas consumption accounted for by the working gas volume is 18.38% in Russia, followed by the Ukraine and Canada (Table 2) (note: the working gas volume is defined as the sum of the gas production of the underground gas storage within 1 year). In recent years, the working gas volumes of the underground gas storage facilities in various regions of the world have increased significantly, with the highest increase

Fig. 4 Proportion of the working gas volume of underground gas storage facilities in different parts of the world

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Table 1 Type and working gas volume of underground gas storage facilities in seven regions of the world [1] Region Asia

Asia-Pacific Commonwealth of Independent States

European Union

Latin America Middle East North America

Total

Type Gas reservoir Oil reservoir Salt cavern Subtotal Gas reservoir Gas reservoir Aquifer Oil reservoir Salt cavern Subtotal Gas reservoir Oil reservoir Salt cavern Aquifer Rock cavity Abandoned pit Subtotal Gas reservoir Gas reservoir Gas reservoir Oil reservoir Salt cavern Aquifer Rock cavity Subtotal

Number 18 1 3 22 10 30 13 2 3 48 71 4 47 21 2 1 146 1 3 330 34 48 46 1 459 689

Working gas volume (108 m3) 99 2 5 105 64 954 192 35 5 1186 710 11 198 168 1 0 1088 2 93 1162 207 147 111 0 1627 4165

occurring in the United States, followed by Russia, Ukraine, Canada, and Germany. The main factors affecting these increases differ somewhat from country to country. The increases in the working gas volumes in the United States and Canada are mainly due to reaching the capacities of and expanding the capacities of established underground gas storage facilities. In Iran, Holland, Germany, and Poland, the increases in the working gas volumes are mainly due to the commissioning and operation of new underground gas storage facilities (Fig. 5).

Proportion of the Working Gas Volume Accounted for by the Various Types of Underground Gas Storage Of the total working gas volume of the underground gas storage facilities around the world, 74% (3084
108 m3), 11% (471
108 m3), 9% (355
108 m3), and 6%

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General Situation of Underground Gas Storage Around the World

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Table 2 Working gas volume of underground gas storage facilities around the world [1, 2]

Country United States Russia Ukraine Canada Germany Italy Holland France Austria Iran Hungary Uzbekistan England China Kazakstan Azerbaijan Czech Spain Slovakia United Arab Emirates Romania Australia Poland Turkey Latvia Japan White Russia Denmark Belgium Croatia Bulgaria Serbia New Zealand Portugal Argentina Armenia Sweden Total

Gas consumption (108 m3) 7786 3909 290 999 805 645 336 426 87 2008 89 514 767 2103 134 104 78 280 44 766

Number of underground gas storage facilities 393 23 13 66 49 12 5 16 8 2 5 2 8 22 3 3 9 4 3 1

Working gas volume (108 m3) 1360.8 718.5 321.8 265.8 238.3 173.6 123.8 129.8 81.2 60 61 40 15.3 105.4 46.5 47 35.4 33.7 35.8 33

Peak gas production rate (106 m3/d) 3460.58 798.44 264.38 266.34 690.41 243.72 277.82 224.23 92.71 28.68 75.77 47.42 111.9 145.85 34.37 14.5 75.63 31.49 44.18 4.4

Proportion of working gas volume (%) 17.48 18.38 110.97 26.61 29.60 26.91 36.85 30.47 93.33 2.99 68.54 7.78 1.99 5.01 34.70 45.19 45.38 12.04 81.36 4.31

106 411 173 421 – 1112 170 32 154 – 30 – 47 52 496 – 9 25,383

7 7 9 2 1 2 3 2 1 1 1 1 1 1 1 1 1 689

31.3 60.3 32.3 38.6 23 1.3 10.8 10.2 7 5.6 5.5 4.5 2.7 2.4 1.5 1.6 0.1 4165.3

32.4 10.74 51.54 57.54 30 1.54 30.98 25.2 15 5.76 4.2 5.04 1.2 7.2 1.92 6 0.96 7166.04

29.53 14.67 18.61 9.17 – 0.12 6.35 31.88 4.55 – 18.33 – 5.74 4.62 0.30 – 1.11 16.41

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Fig. 5 Increase in the working gas volume of the underground gas storage facilities around the world during 2015–2018

Fig. 6 Distribution of the working gas volumes of different types of underground gas storage facilities

(255
108 m3) are stored in gas reservoirs, aquifers, salt caverns, and oil reservoirs, respectively, and the working gas volume accounted for by the other types of underground gas storage, such as gas storage constructed from rock cavities and abandoned mines is negligible (Fig. 6). There are two underground gas storage facilities constructed from rock cavities in the world, which are used to store gaseous natural gas: one is the Haje underground gas storage in Czech, which has a working gas volume of 7500
104 m3; and the other is the underground gas storage reconstructed in a rock cavity lined with a steel tube in Sweden, which has a working gas volume of 900
104 m3. There is only one underground gas storage reconstructed in an abandoned pit, which is located in Germany and has a working gas volume of 340
104 m3.

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General Situation of Underground Gas Storage Around the World

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Peak Daily Gas Production Rate Per Unit of the Various Types of Underground Gas Storage The working gas volume of underground gas storage reconstructed from gas reservoirs is the highest, accounting for about 74% (3084
108 m3), but the peak daily gas production rate accounts for only 56%, and the gas supply capacity is low. This indicates that most of the gas reservoir underground gas storage facilities are used for seasonal peak shaving. The working gas volume of salt cavern underground gas storage accounts for 9% (355
108 m3), but the peak daily gas production rate is 27%, giving it the most obvious flexibility in peak shaving. Therefore, salt cavern underground gas storage is suitable for daily peak shaving (Table 3). From the point of view of the peak daily gas production rate per unit, the gas supply capacities of the different types of underground gas storage are significantly different. For gas reservoir underground gas storage, the average peak daily gas production rate per unit is 130
104 m3/(d·108 m3), and those of aquifers and oil reservoir underground gas storage facilities are 170
104 m3/(d·108 m3) and 160
104 m3/(d·108 m3), respectively. Meanwhile, that of salt cavern underground gas storage is 550
104 m3/(d·108 m3), which is 3–4 times that of pore type underground gas storage, giving it a high gas supply capacity (Fig. 7). Peak daily gas production rate per unit ¼ peak daily gas production rate/working gas volume (104 m3/(d·108 m3)). The higher the peak daily gas production rate per unit, the higher the gas supply capacity of the underground gas storage, and vice versa. The distribution of the working gas volume of pore type and salt cavern underground gas storage facilities in different countries suggest that the peak daily gas production rate per unit is higher in countries with salt cavern underground gas storage (Figs. 8 and 9), but the storage capacity is limited.

Future Development Plan for Underground Gas Storage Around the World In addition to the 689 underground gas storage facilities currently in operation, it is planned that 133 more underground gas storage facilities will be expanded or newly Table 3 Working gas volume and peak gas production of different types of underground gas storage facilities

Type Gas reservoir Salt cavern Aquifer Oil reservoir Total

Working gas volume (108 m3) 3084 255 471 255 4165

Proportion of working gas volume (%) 74 9 11 6 100

Peak daily gas production rate (108 m3/d) 40.35 19.13 8.03 4.08 71.59

Proportion of peak daily gas production rate (%) 56 27 11 6 100

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Fig. 7 Unit peak daily gas production rates of the different types of underground gas storage facilities

Fig. 8 Working gas volume and peak daily gas production rate per unit in countries with working gas volumes exceeding 35
108 m3

constructed around the world, among which, the capacities of 46 underground gas storage facilities will be expanded, accounting for 35%, and 87 underground gas storage facilities will be newly constructed, accounting for 65%. The 133 underground gas storage facilities will have working gas volumes of 640
108 m3. Combined with the 689 currently operating underground gas storage facilities, the number of underground gas storage facilities will reach 822, and their working gas volume will exceed 4805
108 m3 (Table 4).

General Situation of Underground Gas Storage Around the World 40

11 120

Salt cavern type

Pore type

Peak daily gas production rate per unit

35 Working gas volume (108m3)

100 30 80 25 20

60

15 40 10 20

Peak daily gas production rate per unit [104m3 / (d • 108m3)]

1

5 0 S N ew erb Ze ia al an Po d rtu g Ar al m en Ar i ge a nt in a Ja pa n Sw ed en

ia

ia ar lg

Bu

m

at

iu lg

Be

C ro

k

a

ar

D en

m

d te

R us

si

ia

an gl

En

hi W

ia

tv

an

R om

La

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ak

ai U ni

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ab

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Fig. 9 Working gas volume and peak daily gas production rate per unit in countries with working gas volumes of less than 35
108 m3 Table 4 Underground gas storage facilities to be expanded and newly constructed worldwide Project Underground gas storage facilities to be expanded

Underground gas storage facilities to be newly constructed

Total

Type Gas reservoir Salt cavern Aquifer Subtotal Gas reservoir Salt cavern Aquifer Oil reservoir Subtotal

Number 27 18 1 46 36 44 6 1 87 133

Working gas volume (108 m3) 174 103 5 282 127 128 100 3 358 640

Development History of Underground Gas Storage Around the World The development of underground gas storage facilities in Europe and the United States shows that underground gas storage has had a positive effect in terms of promoting the natural gas trade and ensuring the stability of the gas supply. As the demand for natural gas and the diversification of trade around the world increase, the demand for and construction of underground gas storage facilities will continue to

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increase, and this development will exhibit relatively obvious regional characteristics. In addition, the change in the relationship between the market supply and demand, the utilization of unconventional natural gas, and the research and development of new techniques will also result in new demands on and challenges to the future development of underground gas storage facilities.

Forces Driving the Increasing Demand for Gas As the demand for gas consumption increases, the demand for underground gas storage facilities will increase correspondingly. According to the forecast of the IGU, the global demand for natural gas will increase from 3
1012 m3 in 2005 to 3.7
1012 m3 in 2020 to 4.5
1012 m3 in 2030. Moreover, the working gas volume of the underground gas storage facilities around the world will increase from 3300
108 m3 in 2005 to 5430
108 m3 in 2030. In the future, the increasing demand for underground gas storage facilities will mainly be concentrated in countries and regions such as the European Union, North America, and the Commonwealth of Independent States, where the gas markets are relatively mature. According to the forecast, the working gas volume of the underground gas storage facilities in the European Union, North America, and the Commonwealth of Independent States will increase from 790
108 m3, 1160
108 m3, and 1360
108 m3 in 2005 to 1350
108 m3, 1870
108 m3, and 1770
108 m3 in 2030, respectively. The traditional three major underground gas storage concentration areas will still be the future demand growth point of underground gas storage [3]. In China, which is representative of the Asian gas market, the working gas volume of the underground gas storage facilities will increase from 11
108 m3 in 2005 to 500
108 m3 in 2030, and the proportion of the working gas volume consumed will increase from the current 3% to 10% in 2030.

Forces Driving the Increasing Demand for Underground Gas Storage According to the analysis conducted by the IGU, the main driving forces behind the increasing demand for underground gas storage in the future are as follows. 1. The various countries are paying more attention to strategic reserves of natural gas. For natural gas exporters, such as Russia, they have begun to systematically increase their strategic reserves of natural gas to protect their export security. For natural gas importing countries, there are many factors affecting the steady supply of natural gas. In addition to the factors related to the production system itself, there are also many other factors, such as political, economic, diplomatic, and military factors, which can affect the stable supply of imported gas due to the great risks in the interruption of the gas supply. When the supply of natural gas is interrupted, the lives of residents and the production of plants and mines are

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directly influenced, which has a significant effect on social stability and economic development. Therefore, the establishment of an adequate scale of natural gas reserves is an important measure for improving the security of the natural gas supply. 2. The optimization of gas field production. Due to the peak shaving and trough filling roles performed by underground gas storage facilities, the gas production from gas fields can be relatively stable. This prevents the load factor from increasing due to the fluctuations in the gas consumption market, and thus, the development effect of the gas field will not be influenced. 3. The need for short-term natural gas trade. For short-term trade, it is necessary to use underground gas storage to achieve effective turnover. Due to the rapid development of the liquefied natural gas (LNG) trade and the continuous downturn in oil and gas prices, the form of the global natural gas trade is changing. The long-term gas supply agreement and the contract modes of taking and paying for gas have been increasingly criticized. The short-term trade volume of natural gas has soared, which requires the use of underground gas storage facilities to achieve effective turnover, and it is also an important factor in promoting the construction of underground gas storage facilities in the future. 4. The need of further balance of the pipeline network, including balancing the transport capacity and pressure. As an important part of the gas pipeline transport system, underground gas storage plays an important role in optimizing the development of natural gas infrastructure and improving the transport efficiency of pipelines. At present, the urban gas distribution system and underground gas storage facilities have become inseparable. According to foreign statistics, the use of underground gas storage can significantly reduce the cost of gas production due to the factors that follow. (1) Compared with the system that does not use underground gas storage, in the system that utilizes underground gas storage, the investment in gas pipelines and compressor stations can be decreased by 20–30%, and the number of gas production wells and the power used by the gas transmission compressors can be reduced by 15%. (2) The investment required to construct an underground gas storage facility for use with a preexisting 1000 km long gas pipeline with a throughput capacity of 1000
104 m3 is about 1/10 the investment required to construct a gas pipeline system after an underground gas storage facility is constructed.

Analysis of the Demand in Different Regions The main force driving the demand for underground gas storage differs from region to region. The number of underground gas storage facilities continues to increase in the United States and Russia due to the demand for the development of unconventional natural gas and the demand for the export of natural gas. In Europe, especially Western Europe, the consumption of imported natural gas dominates. Therefore, Europe will be the main growth region for the construction of underground gas storage facilities. In Asia and the Middle East, the demand for underground gas

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storage will increase moderately, but the proportion of the number of facilities and the working gas volume of the underground gas storage facilities will remain low. In North America, the increasing demand for underground gas storage is related to the development of unconventional natural gas. Particularly in the United States, the development of the unconventional natural gas industry and the resulting adjustment of natural gas import and export patterns will be the main driving force behind the construction of underground gas storage facilities in the future. The development of unconventional natural gas, which is represented by shale gas, has not only changed the balance between the supply and demand of natural gas in various regions, but it has also changed the transport direction of the natural gas supply in local areas. It is necessary to construct new underground gas storage facilities to meet the needs of the exploitation and utilization of unconventional natural gas and to meet the needs of peak shaving and to guarantee sufficient gas supply in the regional market after the supply of unconventional natural gas decreases. The construction of underground gas storage facilities in Russia will follow its export-oriented development mode, and the future construction plan is also designed to meet the requirements of the export of natural gas. Most of the underground gas storage facilities planned for and under construction in Russia are on the shore of the Caspian Sea in the southern part of western Siberia, which is directly related to Russia’s plans to export gas to Europe via Turkey and Greece. Moreover, Russia is conducting underground gas storage exploration and site selection in the eastern part of eastern Siberia in preparation for entering the Asia-Pacific gas market. The increasing demand for underground gas storage in Western Europe is mainly due to the increasing dependence of the countries in the region on imported natural gas. The countries with a high dependence on foreign gas must establish an underground gas storage system to ensure that they have sufficient natural gas reserves. Taking the European Union as an example, according to the research conducted by the IGU, once the external dependence on foreign gas reaches and exceeds 30%, the working gas volume of the underground gas storage facilities needs to exceed 12% of the gas consumption. If the external dependence on foreign gas exceeds 50%, the working gas volume of the underground gas storage facilities in most countries need to exceed 20% of the gas consumption, and the working gas volume of the underground gas storage facilities in France and Austria even exceed 30% of their gas consumption. In Western Europe, with the decline of the local gas flow rate and the increase in the dependence on foreign gas in the future, the construction of underground gas storage facilities will become increasingly urgent. In the Asia-Pacific region, the increase in the demand for underground gas storage is mainly concentrated in China, where the gas consumption increased from 300
108 m3 in 2000 to 2373
108 m3 in 2017, with an average annual increase rate of 15%. China has become the third largest gas consuming country in the world. Due to the introduction of a series of relevant national policies in China, new opportunities for the development of the natural gas market will occur, which poses a severe challenge for peak shaving and ensuring the supply from underground gas storage facilities. According to the medium-long term oil and gas pipeline network plan (NDRCF [2017]965), in China, the working gas volume of the

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underground gas storage facilities will reach 300
108 m3 in 2025, which will alleviate the gas supply problem.

Main Development Trend The main function of underground gas storage is to guarantee a stable and safe gas supply in the future. However, due to the increasing gas trade volume and the changes in the trading modes, the supply and demand relationship of the regional market has changed, and the utilization of unconventional natural gas has also changed. New demands will occur in the future, necessitating the development of underground gas storage [3]: 1. Underground gas storage can meet the demands for the development of a more varied gas market. In addition to peak shaving, underground gas storage will play a role in creating more flexible regulation and will play a guaranteed role in regulating regional gas market prices. 2. In addition to meeting the needs of peak shaving, underground gas storage will serve as one of the tools in the regional gas common market. 3. The commercial profit mode of underground gas storage will be an important aspect in the development of this process, and the commercial profit of underground gas storage based on the seasonal price differences in natural gas will be gradually reflected in the development process of underground gas storage. 4. Underground gas storage services are more transparent and comprehensive, and all types of gas users, including interruptible and uninterruptible gas users, should be treated equally. 5. Underground gas storage technologies will be widely used in non-gas storage fields, such as compressed air energy storage, hydrogen storage, gas hydrate storage, and the coordinated operation of underground gas storage and LNG storage. Many underground gas storage facilities in Europe and America have been in operation for many years. Nowadays, the development of underground gas storage technologies is mainly focused on prolonging the service life of underground gas storage facilities, reducing the influence of underground gas storage on the environment, and enhancing the flexibility of underground gas storage operations. This mainly includes the following advancements. 1. The flexible adaptability of underground gas storage. Underground gas storage no longer only meets seasonal peak shaving through injection in summer and production in winter, but it is also widely used for injection-production regulation. 2. The optimization of the operation of existing underground gas storage facilities, improving the flexibility of underground gas storage facilities, and meeting the development needs for the liberalization of the natural gas market.

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3. The construction of super large salt cavern and horizontal salt cavern underground gas storage facilities, especially the construction and operation of horizontal dissolved cavern underground gas storage facilities. 4. The large-scale application of welded strings. 5. The development of horizontal and multilateral wells to increase the deliverability of underground gas storage facilities. 6. The construction of an above ground-underground integrated operation management model to improve the operation optimization and integrity of the management. 7. Strengthening the management of the underground part of the system, including increasing the operating pressure interval, improving the gas injection-production capacity, implementing inside and outside monitoring of the casing in the gas well, evaluating and optimizing the cement, and using an intelligent gas production wellbore. 8. Application of new ground dehydration technology and new model compressor.

The Construction and Development of Underground Gas Storage Facilities Around the world The development of underground gas storage facilities in typical countries and regions around the world conforms to the development trend of the natural gas industry, and its development generally involves three stages: the early stage of development, the rapid development stage, and the steady development stage. The characteristics of each development stage are determined by the level of dependence on natural gas and the conditions of the country. The factors driving the rapid development of underground gas storage mainly include demand, resources, technology, policy, and price. The century-long underground gas storage construction history around the world has shown that it is an important link in the natural gas industry chain, and underground gas storage is of great significance to ensuring regional energy security. 1. Underground gas storage has become an important link in the natural gas industry chain. In developed countries, such as Europe and the United States, underground gas storage occupies an important position in the natural gas industry chain, and it is an indispensable and important link in pipeline companies, gas distribution companies, and consumer markets. The underground gas storage in these countries is characterized by a large gas storage capacity and a low cost, and it is the main method of seasonal peak shaving and of ensuring the safety of the natural gas supply. Furthermore, it plays an important role in optimizing gas field production and in improving pipeline efficiency. Under the conditions of a market economy, the main purpose of underground gas storage has gradually transitioned from ensuring gas supply security to a profit-making tool. In addition, underground gas storage also has a political value that the market cannot reflect, that is, under

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extreme weather conditions and during the interruption of the natural gas supply, underground gas storage facilities can guarantee a continuous supply of gas. 2. Only when the working gas volume of the underground gas storage accounts for more than 10% of the annual gas consumption can gas supply security be guaranteed. The construction of underground gas storage facilities in developed countries has generally involved three stages: the early stage of development, the rapid development stage, and the steady development stage. The early stage of development generally lasted for 13–30 years, and the rapid development stage generally lasted for 18–46 years. During the three development stages, the proportions the annual gas consumption accounted for by the working gas volume of the underground gas storage facilities are 2–4%, 4–9%, and greater than 10%, respectively. Only when the working gas volume is greater than 10% of the gas consumption, can peak shaving and a safe and stable gas supply be effectively guaranteed. 3. Gas reservoir underground gas storage was the first type of underground gas storage constructed, followed by salt cavern and aquifer type underground gas storage. According to the experiences constructing underground gas storage facilities worldwide, depleted gas reservoirs were the first spaces to be used for constructing underground gas storage facilities, followed by salt caverns, oil reservoirs, and aquifers. Among the above types of underground gas storage facilities, the gas reservoir underground gas storage facilities have the largest working gas volume; while the salt cavern underground gas storage facilities have the maximum peak daily gas production capacity, the highest gas supply capacity, and a relatively obvious peak shaving flexibility. In terms of the underground gas storage construction scale, when the pipeline network is mature and optimized, medium and small gas reservoirs (less than 5
108 m3) are the main targets for constructing underground gas storage facilities. 4. The location of underground gas storage sites has high requirements in terms of geological conditions, and it is also restricted by the market, resources, and preexisting pipeline networks. Compared with other peak shaving methods, underground gas storage has advantages, such as large capacity, small climate impact, high safety and reliability, obvious peak shaving and trough filling capabilities, balanced gas field production, and effective improvement of the operation efficiency of pipeline networks. However, the geological condition requirements for the construction of an underground gas storage facility are also high, i.e., the injected natural gas can be sealed and produced, the structure is known, and the burial depth is moderate. The reservoir has good physical properties, a good sealing property, and a certain gas storage capability. The experience attained while constructing underground gas storage facilities worldwide have shown that the location of the underground gas storage facility is determined by the distribution of resources, the capacity and size of the pipeline network, the geographical location, the population density, and the level of economic development. Moreover, other peak shaving methods,

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such as LNG receiving stations and pipelines, should also be taken into consideration. The reasonable location of an underground gas storage facility is beneficial to maximizing peak shaving and ensuring the supply benefits. 5. The construction and capacity-reaching period of an underground gas storage facility is relatively long and generally lasts for more than 10 years or even several decades. The construction of underground gas storage facilities generally consists of the following stages: project approval, early evaluation, design, construction, and cyclic operation and production achievement. It takes about 2–5 years to progress from the project approval stage to the design stage. The larger the scale of the project, the longer the construction period. The construction and capacityreaching period differs for the different types of underground gas storage facilities. For depleted gas reservoir and salt cavern underground gas storage facilities, it generally takes more than 5 years and 8 years, respectively. For aquifer and watered gas reservoir underground gas storage facilities, it takes more than 10 years or even several decades. Therefore, considering the development of the natural gas industry, the optimization of the pipeline network, the complex geological conditions required for underground gas storage construction, the differences in the construction periods of the different types of underground gas storage facilities, and the capacity-reaching and peak shaving capability in the later stage, underground gas storage facilities should be planned, studied, and constructed as early as possible to achieve operation as early as possible.

Underground Gas Storage Facilities in Typical Countries and Regions This section focuses on analyzing the construction history, type, proportion of working gas volume, and distribution characteristics of underground gas storage facilities in the United States, Russia, and the European Union, with the goal of providing a reference for the construction of underground gas storage facilities in China in the future.

The United States Current Status of Underground Gas Storage in the United States According to a report published by the IGU, the number of underground gas storage facilities in the United States is the highest in the world, with a total of 393 underground gas storage facilities. Their total working gas volume is 1360.8
108 m3 [1], accounting for 17.48% of the annual gas consumption. According to the statistics provided by the Energy Information Administration (EIA), in 2016, the working gas volume produced from underground gas storage facilities accounted for 12.13% of the annual gas consumption in the United States (Fig. 10). Depleted reservoir underground gas storage is the most widely used type of underground gas storage, and it has low operating costs. More than 80% of the

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Fig. 10 Variation in the gas consumption and working gas volume of underground gas storage facilities in the United States

underground gas storage facilities in the United States were constructed using depleted reservoirs (depleted gas reservoirs account for about 71%), while aquifer and salt cavern underground gas storage facilities account for 8.5% and 8.5%, respectively (Fig. 11). The existing underground gas storage facilities are mainly distributed in the northeast and southern gas provinces, closer to the end users of the natural gas. Nearly 50% of the underground gas storage facilities are located in the northeastern part of the United States, which is a major gas consumption region. Texas and Louisiana have abundant gas production, and they also contain many underground gas storage facilities. The salt cavern underground gas storage facilities are mainly located in Texas, where rock formations and salt domes are well developed [4].

Analysis of the Development of the Gas Storage Capacity in the United States wThe first underground gas storage facility in the United States was constructed in 1916 using the Zoar depleted gas reservoir in New York. It was the second underground gas storage facility constructed in the world and is still in operation. According to the relevant data, the development of underground gas storage construction in the United States can be divided into three stages: the preliminary construction, rapid development, and supplementary improvement stages. 1. Preliminary Construction Stage (1916–1950). In this stage, the construction of underground gas storage facilities in North America was mainly concentrated in the United States. This was also the early stage of the development of the natural gas industry in the United States. In the

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Fig. 11 Working gas volumes of the different types of underground gas storage facilities in the United States

late 1920s, with the development of pipeline transport technology, the construction of long-distance gas pipelines came to fruition. From 1927 to 1931, a total of 12 gas transmission trunk lines were built in the United States, setting off the first high tide of gas pipeline construction. Meanwhile, the gas consumption increased rapidly, reaching 345
108 m3 in 1930. Due to the availability of long-distance transport, increases in gas consumption, and the fluctuation of seasonal gas consumption, it was urgent to ensure a safe and stable gas supply at this time. Underground gas storage for peak shaving was the most effective way to ensure a safe and stable gas supply. Therefore, the construction of underground gas storage facilities was rapidly developed. The construction of underground gas storage facilities occurred almost simultaneously with the construction of the gas pipeline network. From 1931 to 1950, 78 underground gas storage facilities were constructed. In this stage, the type of underground gas storage was dominated by depleted reservoirs, and the engineering technologies for underground gas storage were continuously improving. The first aquifer underground gas storage facility, the Doe Run Upper facility, was constructed in Kentucky. 2. Rapid Development Stage (1951–1980). In this stage, the natural gas industry developed rapidly in North America, the gas consumption, reserves, and production increased quickly, and the construction of the natural gas pipeline network was sped up. An optimized pipeline network system had been constructed, and underground gas storage facilities were rapidly constructed in locations convenient to the pipeline network. The construction of underground gas storage facilities increased in Canada. From 1951 to1980, a total of 234 underground gas storage facilities were built in the United States.

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The technologies of the underground gas storage construction were rapidly developed, and relevant industry standards were successively established. The construction of underground gas storage facilities developed from the construction of a single depleted reservoir underground gas storage facility to the construction of joint aquifer and salt cavern underground gas storage facilities. 3. Supplementary Improvement Stage (after 1981). After the gas market transitioned from the rapid development stage to the mature stage in North America, the natural gas gathering pipeline network was gradually optimized, and the pipeline construction entered the of smooth development stage. Therefore, the construction of underground gas storage facilities also entered into a stage of smooth development. 4. Developmental characteristics of underground gas storage in the United States after the implementation of Federal Energy Regulatory Commission (FERC) order 636. Since the implementation of FERC order 636 in 1993, the opening of underground gas storage facilities has become a statutory requirement. Finding a way to improve the economic benefit of gas storage services has become the basic requirement for owners of underground gas storage facilities. Due to the increasing underground gas storage capacity in the United States between 1998 and 2005, third party access became permissible, and the profitability of the underground gas storage industry in the United States increased significantly. This fully demonstrates that as a profitable tool in the gas market, underground gas storage is beneficial to promoting rapid development, and it has two main characteristics. First, the working gas volume increased significantly. According to statistics, the working gas volume increased from 1073
108 m3 in 1998 to 1136
108 m3 in 2005, i.e., by about 6%. This increase mainly reflects the increase in the number of salt cavern underground gas storage facilities and the upgrading of a large number of depleted reservoir underground gas storages facilities. Along with the development of efficient operational technologies, they are one of the main reasons for the substantial increase in the working gas volume. Second, the gas production capacity significantly improved. Since 1998, the average annual growth rate of the gas production capacity of the underground gas storage facilities in the United States has been 2%, and the total gas production capacity increased from 21
108 m3/d in 1998 to 24
108 m3/d in 2005, i.e., by about 13%. The gas production capacity was increased significantly by drilling horizontal wells in existing depleted reservoir underground gas storage facilities and through the continuous expansion of existing salt cavern underground gas storage facilities by adding new salt caverns. From the point of view of the three different types of underground gas storage facilities, the daily gas production capacity of the depleted reservoir and salt cavern underground gas storage facilities has increased significantly, while the number of new and expanded aquifer underground gas storage facilities has been relatively small (Fig. 12).

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Fig. 12 Variations in the proportions of the daily gas production capacities of salt caverns, aquifers, and depleted reservoir underground gas storages. (Source: Beijing Kingzone General Oil & Gas Consulting CO., LTD. (Kingzone); and Investigation report on the operation mechanism of foreign natural gas strategic reserves and peak shaving underground gas storage, 2017)

The underground gas storage market in the United States is dominated by depleted reservoir underground gas storage facilities. In 1998–2005, the increase in the working gas volume of the depleted reservoir underground gas storage facilities (38.7
108 m3) was the highest among the three types of underground gas storage facilities. However, although the average working gas volume of the newly constructed depleted reservoir underground gas storage facilities was as high as 1.6
108 m3, the average increase in the working gas volume of each facility was the lowest of the three types of underground gas storage facilities. Moreover, the majority of the increase was due to small-scale equipment upgrades, computational changes in the cushion gas volume and the working gas volume, and the periodic reappraisal of the gas field. During this period, due to the expansion of depleted reservoir underground gas storage facilities, the average gas production capacity increased, and the average working gas volume of this type of underground gas storage simultaneously increased by about 14%. The working gas volume and gas production capacity of the salt cavern underground gas storage facilities was increased by expanding the existing facilities, and the increase was higher than the increases of the other two types of underground gas storage. From 1998 to the end of 2005, the average working gas volume and the average daily gas production of the salt cavern underground gas storage facilities increased by 44% and 43%, respectively. In contrast, aquifer underground gas storage experienced the least capacity expansion. During this period, only one new aquifer underground gas storage facility was constructed, while the other six facilities were expanded, with a maximum

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increase of 4.5
108 m3. Although the increase in the number of facilities was limited, the average working gas volume and the average daily gas production increased by 20% and 16%, respectively. The above situation shows that the depleted reservoir and salt cavern underground gas storage facilities were developed rapidly in the United States in order to meet the requirements necessary to open the market and to make higher profits.

Russia At present, Russia is the second largest gas producer and consumer in the world, and it is also the country with the largest gas reserve volume. The underground gas storage facilities in Russia are mainly distributed in the gas consumption area, and they function as indivisible parts of the unified gas supply system in Russia. The construction of underground gas storage facilities in Russia began in the late 1950s, and it was dominated by depleted gas reservoir and aquifer underground gas storage facilities. The 1960s–1970s was the rapid development stage of the construction of underground gas storage facilities, the number of underground gas storage facilities increased from two to ten, and the total working gas volume reached 405
108 m3, accounting for 6–9% of the annual gas consumption. Since the 1980s, Russia has constructed a total of 23 underground gas storage facilities, with a working gas volume of 718.5
108 m3 (excluding strategic reserves), accounting for 18.38% of its gas consumption. As a natural gas exporter, Russia mainly constructs large underground gas storage facilities near the gas export pipeline to ensure the safety of the gas export. These underground gas storage facilities are mainly distributed in two regions. One is from the Baltic Sea in the north to the coast of the Black Sea, with ten underground gas storage facilities located near the six gas pipelines that Russia uses to export natural gas to Europe. The other is along the Caspian Sea in the southern part of western Siberia, with 12 underground gas storage facilities located near the trunk of the pipeline network and the branch lines that Russia uses to export natural gas to Central Asia [5–7]. Most of Russia’s underground gas storage facilities were constructed through direct investment of the state during the Soviet period. After the break-up of the Soviet Union, the unified gas supply system and the associated underground gas storage facilities in Russia were all owned by Gazprom. In addition to meeting the domestic demand for peak-shaving, the construction of underground gas storage facilities in Russia plays two additional important roles: to guarantee stable export (the reserve volume is generally 15% of the exported gas volume) and to maintain long-term, strategic reserves (the data from the IGU shows that Russia has a longterm strategic reserve of 380
108 m3). Compared with other countries, the scale of the underground gas storage in Russia is relatively large, and the number of drilled wells in Russia is also larger.

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European Union The working gas volume of the underground gas storage facilities in the European Union is second only to that in North America and the Commonwealth of Independent States. A total of 145 underground gas storage facilities have been constructed, with a total working gas volume of 1088
108 m3, accounting for about 20% of the annual gas sales in the European Union. Germany, Italy, France, Austria, and Hungary are the traditional underground gas storage powers in the European Union, with working gas volumes of 238.3
108 m3, 173.6
108 m3, 129.8
108 m3, 81.2
108 m3, and 61
108 m3, respectively, accounting for 29.6%, 26.9%, 30.47%, 93.3%, and 68.5% of the annual gas consumption, respectively. The working gas volume of the underground gas storage facilities in Germany, Italy, and France exceeds 100
108 m3 (Fig. 13). As an important region of natural gas reserves, the development of underground gas storage in Germany was relatively rapid. As of 2016, the number of underground gas storage facilities in Germany had reached 49, which is the highest in the European Union, and the average working gas volume of a single underground gas storage facility in Germany was 4.9
108 m3. There are five underground gas storage facilities in Holland, and the average working gas volume of these facilities is the largest, as high as 25.8
108 m3. Among the underground gas storage facilities in the European Union countries, depleted reservoir underground gas storage is the main type, with the working gas volume of this type of facility accounting for about 66.3% of the total working gas volume of the underground gas storage facilities in these countries. The proportion accounted for by salt cavern and aquifer underground gas storage facilities is also very large (Fig. 14). There are more salt cavern underground gas storage facilities in Germany, while France is dominated by aquifer underground gas storage facilities. Overall, the underground gas storage facilities in the European Union have a sufficient storage capacity, and many countries have a larger storage capacity than

Fig. 13 Distribution of the working gas volumes of the different European Union countries

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Fig. 14 Working gas volumes and the proportions of the different types of the underground gas storage facilities in the European Union

they need; therefore, the surplus working gas volume can be provided to other countries via the interconnected gas pipeline networks. Before 2015, as the demand for gas in the European Union gradually recovered from the financial crisis in 2008, and as domestic gas production fell (England, Holland, and Denmark), the dependence on foreign gas continued to increase, and the working gas volume of the underground gas storage facilities in the European Union increased continuously. However, in the past 3 years, although several new underground gas storage facilities were put into operation, and the working gas volume increased by nearly 40
108 m3, the shortfall resulting from the change of the British Rough underground gas storage to a production gas field was still not compensated for in this area. Moreover, several small underground gas storage facilities are facing abandonment. Therefore, the working gas volume of the underground gas storage facilities in the European Union has remained stable over the past 3 years, with little increasing (Fig. 15).

England Supply and Demand Status of Natural Gas England is also an important producer and consumer of natural gas, with a gas production of 410
108 m3 and a gas consumption of 767
108 m3 in 2016. England is a net importer of natural gas, with a net gas import of 357
108 m3 in 2016, accounting for 46.5% of the gas consumption in that year, of which, the net imports of pipeline gas and LNG were 211
108 m3 and 146
108 m3, respectively (Fig. 16).

Current Status of Natural Gas Reserves The natural gas reserve mode in England is dominated by underground gas storage, followed by LNG reserves. As of 2016, there were a total of ten underground gas

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Fig. 15 Variations in the working gas volumes of the underground gas storage facilities in the European Union

storage facilities (including underground gas storage facilities under construction) in England, with a total working gas volume of 48
108 m3; and 2 LNG peak-shaving stations, with a total working gas volume of 1.61
108 m3. At present, the total working gas volume of the natural gas reserves in England is 49.62
108 m3, accounting for 6.47% of the total gas consumption in 2016, which is equivalent to the amount of gas consumed in 31 days in England (Table 5). The ten underground gas storage facilities include one offshore depleted oil reservoir, two depleted gas reservoirs, and seven salt cavern underground gas storage facilities, with working gas volumes of 33.91
108 m3, 4.06
108 m3, and 10.04
108 m3, respectively.

Germany Supply and Demand Status of Natural Gas In Germany, Natural gas resources are scarce, and natural gas production is very limited. The gas consumption of the country is almost completely dependent on gas imported through a pipeline. In 2016, the natural gas production in Germany was 66
108 m3, the gas consumption was 805
108 m3, and the net natural gas imports were 739
108 m3, with a foreign dependence of up to 89% (Fig. 17). Status of Natural Gas Reserves The natural gas reserve mode in Germany is dominated by underground gas storage, with the main purpose being seasonal peak shaving and emergency reserves to ensure a safe and stable gas supply. Germany has the largest and most diverse number of underground gas reservoirs in the European Union. As of 2016, there were a total of 64 underground gas storage

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Fig. 16 Gas supply and demand in England during 2006–2016. (Source: HIS database)

Table 5 Natural gas reserve scale for England

Type LNG peak shaving Offshore depleted oil reservoirs Salt caverns Depleted gas reservoirs Total

Number 2 1

Working gas volume (108 m3) 1.61 33.91

Daily gas flow rate (108 m3) 0.13 0.45

Daily gas injection rate (108 m3) 0.002 0.28

7 2 12

10.04 4.06 49.62

1.16 0.09 1.83

0.96 0.11 1.35

facilities (including underground gas storage facilities under construction) in Germany, with a total working gas volume of 251
108 m3; and one ground LNG peak shaving station, with a working gas volume of 0.14
108 m3. The total working gas volume of the natural gas reserves in Germany is 251.14
108 m3, accounting for 31% of the total gas consumption in 2016, which is equivalent to the amount of gas consumed in 127 days in Germany (Table 6). The 64 underground gas storage facilities include 46 salt cavern, 6 aquifer, 11 depleted gas reservoir, and 1 depleted oil reservoir underground gas storage facilities, with working gas volumes of 159.26
108 m3, 4.2
108 m3, 83.1
108 m3, and 4.43
108 m3, respectively. Thus, salt cavern underground gas storage facilities are the main type of underground gas storage.

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Fig. 17 Gas supply and demand in Germany during 2006–2016. (Source: HIS database)

Table 6 Natural gas reserve scale for Germany

Type LNG peak shaving Depleted oil reservoirs Salt caverns Depleted gas reservoirs Aquifers Total

Number 1 1 46 11 6 65

Working gas volume (108 m3) 0.14 4.43 159.26 83.1 4.2 251.14

Daily gas flow rate (108 m3) 0.02 0.07 5.07 1.23 0.14 6.53

Daily gas injection rate (108 m3) 0.0027 0.05 2.78 0.82 0.06 3.71

Source: GIE database

France Supply and Demand Status of Natural Gas In France, at present, the gas consumption is almost completely dependent on gas imports. In 2016, the gas consumption was 426
108 m3 in France, whereas the net natural gas imports were 425.5
108 m3, of which the net imports of pipeline gas and LNG were 354.2
108 m3 and 71.3
108 m3, respectively (Fig. 18). Status of Natural Gas Reserves The natural gas reserves in France are mainly used for seasonal peak shaving and emergency reserves to ensure a safe and stable gas supply. The French government

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Fig. 18 Gas supply and demand in France during 2006–2016. (Source: HIS database)

put forward the concept of strategic reserves in the 1970s, but it did not make a clear distinction between strategic reserves and peak shaving reserves at the specific operation level. There are three types natural gas storage in France. The first is to convert a depleted reservoir into an underground gas storage facility, the second is to convert an aquifer or salt cavern into an underground gas storage facility, and the third is the use LNG storage tanks. The natural gas storage facilities, which consist of underground salt caverns, aquifers, and LNG storage tanks, are owned by GDF (gaz de France) Suez and the TIGF (total infrastructure gaz France). GDF Suez owns 16 of the natural gas storage facilities, including 9 aquifer underground gas storage facilities in the Paris Basin, 3 underground gas storage facilities reconstructed from salt caverns, and 2 LNG receiving stations. The TIGF owns two aquifer underground gas storage facilities in southeastern France (Table 7). Construction of the first underground gas storage facility in France began in 1956, and it was put into operation in 1965. The type for natural gas storage was dominated by underground gas storage, especially aquifer underground gas storage. By the end of 1991, Gaz de France had put 11 underground gas storage facilities into operation, with a total storage capacity of 169.14
108 m3. Nine of these facilities were aquifer underground gas storage facilities, with a total storage capacity of 158.76
108 m3. The Chemery underground gas storage facility was the largest aquifer underground gas storage facility, which was put into operation in 1968, with a storage capacity of 69.25
108 m3, a burial depth of 1120 m, and an effective working gas volume of 32.8
108 m3. As of 2005, a total of 15 aquifer and salt cavern underground gas

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Table 7 Main natural gas storage facilities owned by GDF Suez and the TIGF

Name of storage facility Beynes superieur GerviUe-Velaine Lussagnet St Uliers Chemeiy Tersanne Fos Tonkin Beynes Profond COurnay Sur Around St Clair sur Epte Etre2 Montoir de Bretagne Soings Izaute Ceimigny Cere la Ronde Manosque Fas Cavaou

Type Aquifer UGS Aquifer UGS Aquifer UGS Aquifer UGS Aquifer UGS Salt cavern UGS LNG storage tank Aquifer UGS Aquifer UGS Aquifer UGS Salt cavern UGS LNG storage tank Aquifer UGS Aquifer UGS Aquifer UGS Aquifer UGS Salt cavern UGS LNG storage tank

Operator GDF Suez GDF Suez TIGF GDF Suez GDF Suez GDF Suez GDF Suez GDF Suez GDF Suez GDF Suez GDF Suez GDF Suez GDF Suez TIGF GDF Suez GDF Suez GDF Suez GDF Suez

Commissioning date 1956 1956 1957 1965 1968 1970 1972 1975 1976 1979 1979 1980 1981 1981 1982 1993 1993 2009

Working gas volume (104 m3) 2200 6600 10,200 4200 36,100 2400 800 4000 11,400 3700 9100 2000 2400 13,500 7500 2900 8800 1800

Maximum gas production (104 m3/d) 600.3 849.5 2299.3 2101.1 6000.4 2200.2 2027.5 1200.1 2429.6 501.2 2698.6 2894 201.1 1098.7 900.5 1500.8 501.2 2390.3

Note: UGS – underground gas storage Source: GIE database

Table 8 Current status of underground gas storage facilities in France Type Aquifers Salt caverns Oil reservoirs Total

Number 16 4 1 21

Working gas volume (108 m3) 114.3 10.73 – 125.03

Daily gas flow rate (108 m3) 1.7 0.53 – 2.23

Daily gas injection rate (108 m3) 1.04 0.094 – 1.134

Source: GIE database

storage facilities had been built in France, with a total reserve volume of greater than 100
108 m3, which accounted for 25% of the annual gas consumption in France and allowed France to supply gas to neighboring Switzerland. As of 2016, there were a total of 21 underground gas storage facilities in France, with a total working gas volume of 125.03
108 m3, accounting for 29% of the gas consumption in that year, which is equivalent to the gas consumed in 125 days in France (Table 8). The natural gas storage facilities include 16 aquifer underground gas storage facilities, with a working gas volume of 114.3
108 m3, accounting for 91% of the total working gas volume of the natural gas reserves in France; 4 salt

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General Situation of Underground Gas Storage Around the World

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cavern underground gas storage facilities, with a working gas volume of 10.73
108 m3, accounting for 9% of the total working gas volume of the natural gas reserves; and 4 LNG receiving stations, with a gas storage capacity of 87.6
104 m3.

Conclusions Gas storage is a very important part of the world’s natural gas industry chain. Global gas storage will increase further as gas consumption increases, mainly in North America, Europe, and emerging markets. With the development of technology, more and more oil and gas reservoirs and salt caverns in high gas consumption areas will be converted to gas storage facilities in the future.

References 1. 27th World Gas Conference. Triennium Work Report June 2018. Storage Committee. Study Group 1. UGS Database [R]. 27th World Gas Conference, Washington DC (2018) 2. BP Statistical Review of World Energy – 2017 – Full report [R] (2017), pp. 20–23 3. D. Guosheng, Demand and Challenges for China’s Underground Gas Storage [J]. Nat. Gas Ind. 31(12), 90–93 (2011) 4. D. Guosheng, Development tendency and driving force of underground gas storages in the world [J]. Nat. Gas Ind. 30(8), 59–61 (2010) 5. L. Wei, Y. Yu, X. Zhengbin, et al., Construction of underground gas storages in the United States and reflection on it [J]. Nat. Gas Technol. 4(6), 3–5 (2010) 6. P. Nan, Current status and prospect of underground gas storages in America, Europe, Russia and Ukraine [J]. Int. Petrol. Econ. 24(7), 80–92 (2016) 7. Tang Ligen, Zhu Weiyao, Zhu Huayin. Monitoring well pattern deployment in China gas storage and its initial success rate [J]. J. Energy Stor. https://doi.org/10.1016/j.est.2020.101950

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Banqiao Reservoir Geology and Storage Design Xinhua Ma

Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geological Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stratigraphic Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Structural Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Trap Sealing Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas Reservoir Development Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dynamic Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Construction Scheme of Gas Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

34 34 34 34 38 40 41 41 44 48 49 51

Abstract

The Banqiao Gas Storage Group is located in the Dagang Oilfield, Binhai New District, Tianjin, which is more than 100 km from Beijing and 40 km from Tianjin. The Banqiao Gas Storage Group is a supporting facility for the Shaanxi-Beijing Gas Transmission Pipeline System. The Gangqing Line and the Gangqing Composite Line are connected to the Shaanxi-Beijing Line 1 to the Shaanxi-Beijing Line 3 at Yongqing Station and are principally responsible for winter peak regulation tasks related to downstream users of the ShaanxiBeijing Gas Pipeline System. In the 1990s, PetroChina began target selection for the storage site and construction project by applying evaluation technologies for establishing the storage capacity parameters of complex water-invaded sandstone gas reservoirs and for multi-cycle operation optimization. The Dazhangtuo gas storage facility was the first to be established in China, becoming operational in X. Ma Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China e-mail: [email protected]; [email protected]; [email protected] © Petroleum Industry Press 2022 X. Ma (ed.), Handbook of Underground Gas Storages and Technology in China, https://doi.org/10.1007/978-981-33-4734-2_2

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2000, and a series of gas storage facilities including Ban876, Central North Banqiao, Central South Banqiao, Ban808, and Ban828 were successively established in 2007, forming the first batch of commercial gas storage groups in China. This has greatly eased the tight situation of gas supply and consumption in the Bohai Rim region and has ensured the security of natural gas supply. Keywords

Banqiao storage · Sandstone reservoirs · Water invasion · China first storage · Beijing peaking-shaving

Introduction Because there is an urgent need for peak adjustment in the Bohai Rim region, the best efforts are directed to building the working gas volume of slab bridge gas storage. However, the working gas quantity of a gas reservoir is controlled by the original reserves, its original pressure, and its operating pressure. Therefore, it is necessary to understand the geological characteristics and development trends of the Banqiao reservoir. In this chapter, the sequence, structure, trap sealing, and development dynamics, among other factors, which determine the operational scheme of a gas reservoir, are introduced.

Geological Overview Stratigraphic Characteristics The Banqiao Storage Group is generally located in the middle and south of the Qianmiqiao Structural Belt in the Dagang Oilfield. Dazhangtuo and the other five gas storage facilities are all formed by the reconstruction of flooded and depleted sandstone gas reservoirs. The reservoirs are the four sets of petroliferous strata in the Shahejie Formation of the Lower Tertiary (Sha 1 middle Submember, Sha 1 lower Submember, Sha 2 Member, and Sha 3 Member). The strata from the upper part of the Sha 1 Member to the Sha 3 Member are the main pay layers. The Ban II oil group in the Sha 1 lower Submember is primarily a condensate oil and gas layer, with a burial depth of 2660–2960 m. The target layer for reservoir construction is mainly the main gas-bearing layer in this area – the sandstone reservoir of the Ban II oil group in the lower Submember of the Lower Tertiary (Fig. 1).

Structural Characteristics The storage group is located at the northeast dipping end of the Beidagang secondary structural belt, bordering the Banqiao Sag in the west, connected to the central

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Fig. 1 Stratigraphic column of Ban876 fault block

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Fig. 2 Plane distribution of Banqiao storage group

Dagang development zone by the North Binhai Fault to the south, and separated from the Baishuitou Fault block in the east by faults (Fig. 2). There are three NE-trending faults in the area – at Banqiao, Dazhangtuo and Baishuitou – which divide the structure into five natural blocks: North Banqiao, Central Banqiao, South Banqiao, the Baishuitou fault block, and the Dazhangtuo nasal structure. The North Banqiao block is a descending fault block in the north of the Banqiao Fault; the Central Banqiao block is located between the Banqiao Fault and the Dazhangtuo Fault and is composed of two structural highs in the south and north. The South Banqiao block is located between the southern part of the Dazhangtuo fault and the eastern fault in the Central Banqiao block. Structurally, the eastern part is the Baishuitou fault block and the western part is the Dazhangtuo nasal structure.

Dazhangtuo Structurally, Dazhangtuo is located on the central uplift belt in the middle area of the Huanghua Depression, at the southwest end of the Changlu-Banqiao extrusion fault structural belt, with the Banqiao Sag located in the northwest and the Beidagang buried hill structural belt in the southeast. The Ban 53 fault block in the downthrown wall of the Dazhangtuo Fault is a part of the Banqiao oil and gas field.

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The Dazhangtuo condensate oil and gas reservoir is a nose-like structure, which is a fault lithologic composite trap formed by fault occlusion and sandstone pinchingout. The top structure of the Ban II oil group has a burial depth of 2565 m, a spill point of 2800 m, a structural range of 235 m, a length of 5 km from east to west, a width of 3 km from north to south, and a trap area of 12 km2. The structural high point is located in the south of Well Ku5, and the stratum is inclined to the northeast, with a dip of 5°–6°. The northeast direction is connected to the northern and southern high points of the central fault blocks in the Banqiao oil and gas fields through a saddle water body. The structure is characterized by a simple structural pattern in the west, with slightly dipping strata, and gentle strata in the east. There is a small high point around Well 1 (also encompassing Well 2). Wells 53 and 4 are relatively low areas. Well 9 is a small saddle between Wells 8 and 10.

Ban876 The Ban876 gas reservoir is located in the upthrown wall of the Dazhangtuo fault, which is located in a fault block enclosed by the fault and is an anticline trap. The structural high point of the fault block is located near Well Banshen 30-1, with a burial depth of 2220 m, a structural amplitude of 30 m, a long axis length of 4.7 km, and a short axis width of 2.5 km at the high point’s burial depth. The fault block area is 8.5 km2, the primary gas-water interface is 2244 m, and the height of gas column is 24 m. The structure of the Ban876 gas reservoir is simple, with no developed faults. The upper parts of the upper and middle submembers of the Sha 1 Member have a total thickness of about 200 m. These directly cover the gas reservoir of the Ban II oil group and are ideal caprocks, providing a good seal. Central North Banqiao The Central North Banqiao fault block has an incomplete anticline profile, and the condensate oil reservoir at the north high point in the Central North Banqiao fault block is a semi-anticline structure. The structure is connected in an up-dipping direction to the adjacent gas reservoir through oil rings and water bodies, providing a typical fault sealing trap. There are few faults in the gas reservoir, and the structure is relatively simple. The northern boundary of the gas reservoir is the Banqiao fault, which is a syn-depositional fault with large fault displacement and long extension. The fault controls the deposition and distribution of oil and gas. The Well Ban 816 Fault is located in the northwestern part of the structure and is a second-level fault derived from the Banqiao Fault, forming an angle of about 30° with the Banqiao fault and exerting a discernible control effect on the distribution of oil and gas. A small late fault is developed near Well 817 in the gas reservoir, which has a marked sealing effect on the oil and gas. Central South Banqiao The Central South Banqiao fault block is an anticline structure, and the southern boundary of the gas reservoir is the Dazhangtuo Fault. This fault is a syn-depositional fault with large fault displacement and long extension. It controls both sedimentation

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and oil and gas distribution. The down-dipping direction of the structure communicates with water bodies and adjacent gas reservoirs through the oil ring. Five small late faults are developed inside the gas reservoir, which have a marked sealing effect on oil and gas seepage. The fault in Well Ban 844 cuts the high point of the anticline. The structural high point of this area is located near Well Banxinzhong 11. The high point has a burial depth of 2596 m, a structural range of 140 m, a length of 4.2 km from east to west, and a width of 2.0 km from north to south. The stratum is relatively gentle, with a dip of 3–6° in the main part of the structure.

Ban808 The Ban808 fault block is located in the Central Banqiao fault block and is the upthrown wall of the Banqiao Fault, adjacent to the Banqiao Sag. The southwest of the block is located at the high point of the Central North Banqiao fault. In the north, it is bounded by the Banqiao Fault and is a south-dipping semi-anticline structure occluded by the Banqiao Fault. Ban828 The Ban828 fault block in the north section of Banqiao is located in the fault rise of Well Banshen 15. It is a broken nose structure sandwiched by the faults of Well Ban 834 and the faults of Well Banshen 15. The structure is relatively complete. The upper oil group of Ban IV is high in the southeast direction and low in the northwest direction. The structural high point is near Well Ban 828-1. The upper oil group of Ban IV has a burial depth at the top boundary of 3140 m, a structural range of about 200 m, and a structural area of 3.05 km2. Two small faults are developed in the fault block (the fault crossing Well Ban 852-4 and the fault between Wells Ban 852 and 828-1), with a fault displacement of 20 m and short extension distance, which only control oil and gas reservoirs locally.

Trap Sealing Conditions Dazhangtuo There are seven faults in Dazhangtuo, of which the Dazhangtuo Fault in the east is a long-term syn-depositional normal fault, which controls structural formation, sedimentary strata, and oil and gas distribution. The fault has a displacement of 200– 770 m and the characteristics of corresponding lithologies and oil- and gas-bearing properties are evidently different in the hanging wall and footwall, displaying strong sealing properties. The remaining six faults are all internal faults derived from the Dazhangtuo Fault, relatively small in size and striking NE or EW. The fault has a displacement of 15–30 m and does not control the distribution of oil and gas. The caprock in the Dazhangtuo area is the upper and middle parts of the Sha 1 Member of the Ban II oil formation, with a total thickness of 400–800 m. The Ban-0 oil group in the middle of the Sha 1 Member is dominated by dark mudstone with a thickness of more than 200 m. The mercury displacement method was used to determine the displacement pressure, revealing a median saturation pressure of

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greater than 99.55 MPa. The displacement pressure of mudstone samples in the adjacent Ban II oil group is 3.70–11.00 MPa, and the median saturation pressure is 24.46–61.94 MPa, showing strong sealing capacity.

Ban876 The structure in the Ban876 block is simple and complete, with a total of five faults, of which the Dazhangtuo Fault in the north is a controlling fault striking NE with a dip of 35°–53° and a fault displacement of 200–770 m. The Ban21-1 fault in the east strikes EW and trends north, with a fault displacement of greater than 100 m. The Banshen30, Ban887, and Ban882 north faults all strike nearly NE and trend SE, with fault displacements of less than 50 m. According to rupture pressure experiments and production dynamics, the fault in this area provides good sealing. The caprock in this area and in the Dazhangtuo area both belong to the same regional caprock, providing good sealing capacity. Central North Banqiao The Central North Banqiao controlling faults are the Banqiao Fault in the north and the Dazhangtuo Fault in the south. The Banqiao Fault strikes NE with a fault displacement of 50–300 m. The Dazhangtuo Fault is a NNE-trending controlling fault with a dip of 35°–53° and a fault displacement of 200–770 m. All the faults display good sealing capacity. The faults in Wells 816 and 818 are both derived from the Banqiao Fault, but are smaller in size and trend NNE, intersecting on a dip of 35°–45° with the Banqiao Fault. The fault has an extension length of 1.5–3.5 km, and fault displacement is 15–30 m. It has a noticeable local sealing effect on fluid seepage, but has little effect on oil and gas seepage from the entire gas reservoir. The caprock layer and the Dazhangtuo Fault belong to the same regional caprock and have good sealing properties. Central South Banqiao The south boundary fault of the gas reservoir in the southern structural highs in Central South Banqiao is the Dazhangtuo Fault alone. The fault displacement in this area is greater than 200 m. The lithology and oil and gas characteristics corresponding to the upper and lower walls are significantly different. The sealing capacity is strong and the possibility of opening and activation is small. There are five internal derived small-scale faults. The fault displacement in Well Ban 844 is relatively large (about 70 m), and the fault controls the distribution of oil and gas. The faults in Wells Banzhong 17 and Banxinzhong 11 are late small faults formed in the late tectonic movement, with extension distances of 1.0 km and fault displacements of less than 15 m. They have a certain sealing effect on local fluid seepage, but have little effect on oil and gas seepage across the entire gas reservoir. The caprock and Dazhangtuo Fault belong to the same regional caprock, providing good sealing capacity. Ban808 The Ban808 Fault block is located in the middle of the Central Banqiao Fault block, adjacent to the Banqiao Depression in the west. The southwestern part is connected

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to the north high point of Central Banqiao and is bordered by the Banqiao Fault. The controlling fault has a good sealing effect. The fault in Well Ban 850-1 derived from the controlling fault is small in scale, extending 0.95 km, with a fault displacement of less than 20 m. The caprock and the Dazhangtuo Fault belong to the same regional caprock, providing good sealing capacity.

Ban828 Two small faults are developed in the fault block, with a fault displacement of 20 m and a short extension distance, and only controlling oil and gas locally. The average total thicknesses of the Ban 2 and Ban 3 oil groups of the lower submember of the upper part of the Ban 4 upper oil group are similar, and they are interbeddings of a large set of mudstone and sandstone. The sand to stratum ratio of the Ban 2 oil group is 0.2 and that of the Ban 2 oil group is 0.1, thereby displaying good sealing capacity.

Reservoir Characteristics The Banqiao Storage Group is a structural oil and gas reservoir. Like Dazhangtuo, the other five gas storage facilities are all formed by the reconstruction of flooded depleted gas reservoirs. These are high-condensate gas reservoirs with normal temperature and pressure systems. The reservoirs are characterized by burial depths of 2200–3200 m, lithology of silt-fine sandstone, and storage space dominated by pores with fractures and fissures. The reservoirs have medium physical properties, with porosities of 14%–26%, averaging 22%, and permeability of 64–809 mD. There are considerable variations in physical properties in the longitudinal direction, and strong heterogeneity of reservoir (Table 1). The condensate oil has the characteristics of “four lows and one high.” Four lows mean low density (0.72–0.78 g/cm3), ground viscosity of less than 2 mPa.s, freezing point below 0 °C, and low initial boiling point (65 °C). One high refers to the high fraction content before 300 °C. Condensate oil content is 407 g/m3. The relative density of natural gas is 0.5802–0.7673 g/cm3, with methane content of 72.59%–95.36%, and the gas contains small amounts of CO2, H2S and N2. Edge water is developed and the reservoir type is weak-middle edge water condensate gas reservoir. Table 1 Reservoir parameters of the Dagang Banqiao storage group

Gas reservoirs Horizon for storage establishment Porosity, % Permeability, mD Heterogeneity

Dazhangtuo Ban II

Ban876 Ban II

Central North Banqiao Ban II

20.5 126.0

18.2 135.6

24.0 240.6

Strong

Strong

Strong

Central South Banqiao Ban II

Ban808 Ban II/IV

Ban828 Ban IV

24.0 189

23.9 346.5

18.0 67

Strong

Strong

Strong

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Gas Reservoir Development Characteristics Gas Reservoir Characteristics Dazhangtuo The Dazhangtuo gas reservoir is a high-condensate reservoir with inactive edge water-in-fault lithologic composite trap. The original formation pressure, measured during oil test in the Ban II oil group in Well Ban 52, was 29.77 MPa (the depth of the middle of the oil layer was 2660 m), with a pressure coefficient of 1.1, static formation temperature of 105 °C, and a geothermal gradient of 3.4 °C/100 m. The relative density of natural gas is 0.679, the relative density of condensate is 0.731 and the condensate content is 630 g/m3. The formation water is NaHCO3 type with an average Cl content of 2868 mg/L, and total mineralization of 6879 mg/L. Ban876 The gas-bearing horizon of the Ban876 gas reservoir is a small layer of the Ban II oil group in the lower part of the Sha 1 Member of the Lower Tertiary. It is a low-condensate reservoir with no oil ring, weak edge water, and a normal temperature and pressure system. There are a total of eight wells in the gas-bearing range of the Ban876 gas reservoir, of which all are interpreted gas layers, concentrated in the No. 1 sandbody in the first layer of the Ban II oil group. On the plane, a small gas layer is distributed and connected, with good connectivity. The gas layer is concentrated in the high part of the structure with effective thickness of 1.2–11.4 m and rolling thickness of 4.6 m. The 11sandbody has a large distribution range, with a maximum effective thickness of 7.2 m and an average effective thickness of 3.2 m, and the 12sandbody has a small distribution range, with a maximum effective thickness of 4.2 m and an average effective thickness of 3.3 m. The strata of the Ban876 gas reservoir display an original pressure of 22.69 MPa, a static temperature of 85 °C, a formation coefficient of 1.0, and a thermal gradient of 3.8 °C/100 m; characteristics of a normal temperature and pressure system. The relative density of natural gas is 0.6264, the relative density of condensate is 0.7268, the condensate content is 72.7 g/m3, the formation water is NaHCO3, and total salinity is 7396 mg/L. It was reported in 1993 that the reservoir has a gas-bearing area of 2.9 km2, natural gas geological reserves of 5.36  108 m3, recoverable reserves of 2.72  108 m3, condensate geological reserves of 13.2  104 t, recoverable reserves of 1.45  104 t, hydrocarbon pore volume of 207.4  104 m3, and edge water volume of 474  104 m3. Central North Banqiao The gas reservoir of the Ban II oil group in the high point of Central Banqiao is a high-condensate oil and gas reservoir with narrow oil ring, weak edge water, and a normal temperature and pressure system. The condensate gas reservoir of the Ban II oil group in the high point of Central Banqiao is divided into six small layers, with

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small layers 1–5 all having oil and gas distribution. The major oil and gas bearing layers are small layers 1, 2, 3, and 4. The sandstone is in stable distribution and has good connectivity in small layers 1 and 2. These are mainly main channel sand and tributary channel sandbodies, showing good physical reservoir properties. The effective thicknesses of the gas layers are 4.7 m and 6.1 m, respectively. Small layers 3 and 4 have a relatively small distribution and are mainly tributary channel sandbodies, with an average effective thickness of gas layer of 4.2 m and 4.4 m, respectively. Each small layer is connected to the Dazhangtuo gas reservoir, the south high point of Banzhong, and the high point of Ban 808-1 through edge water and oil ring. The original formation pressure of the Banzhong North High Point Ban II oil formation is 30.5 MPa, with a pressure coefficient of 1.13, formation temperature of 102 °C, and a geothermal gradient of 3.1 °C/100 m, which represents a normal temperature and pressure system. The relative density of natural gas is 0.5802–0.7673, the density of condensate oil is 0.72–0.78 g/cm3, the content of condensate oil is 407 g/m3, the density of crude oil is 0.8171–0.8284 g/cm3, and the formation water is NaHCO3 with a total salinity of 8755 mg/L. The gas-bearing area is 6.3 km2, with dry gas reserves of 30.13  108 m3 and condensate oil reserves of 109.5  104 t. The oil-bearing area is 1.8 km2 with crude oil reserves of 170  104 t and dissolved gas reserves of 5.13  108 m3.

Central South Banqiao The gas reservoir of the Ban II oil group in the high point of Central South Banqiao is a high-condensate oil and gas reservoir with narrow oil ring, weak edge water, and a normal temperature and pressure system. The condensate gas reservoir of the Ban II oil group in the high point of Central South Banqiao is divided into six small layers, with small layers 1–5 all having oil and gas distribution. The major oil and gas bearing layers are small layers 1 and 2. The sandstone is in stable distribution and has good connectivity in small layers 1 and 2. They are mainly channel sandbodies, showing good physical properties of reservoirs. The effective thickness of the gas layer is 3.8 m and 6.7 m, respectively. Small layers 3, 4, and 5 have relatively small distribution and are mainly tributary channel sandbodies and channel lateral sandbodies, with an average effective thickness of gas layer of 1.7 m, 2.3 m, and 6.3 m, respectively. Each small layer is connected to the Dazhangtuo gas reservoir, the south high point of Banzhong, and the high point of Central North Banqiao through edge water and oil ring. The oil and gas distribution of the Ban II oil group in this area is mainly controlled by structure and lithology, and the characteristics of each small layer are different. The first and second layers are mainly controlled by structure. The gas-oil and oil-water interfaces differ greatly in the east and west wings of the structure. The water interface is deep and the east is shallow. Small layers 3, 4, and 5 are lithologic reservoirs. The original formation pressure of the Ban II oil group in Central South Banqiao is 30.32 MPa, with a pressure coefficient of 1.12, a formation temperature of 101 °C, and a geothermal gradient of 3.1 °C/100 m, representing a normal temperature and

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pressure system. The relative density of natural gas is 0.5864–0.7875, the relative density of condensate oil is 0.72–0.83, and the content of condensate oil is 407 g/m3. The formation water is NaHCO3 with a total salinity of 8755 mg/L. The gas-bearing area is 4.9 km2, with dry gas reserves of 17.29  108 m3, condensate oil reserves of 62.9  104 t. The oil-bearing area is 3.1 km2 with crude oil reserves of 44.0  104 t and dissolved gas reserves of 1.32  108 m3.

Ban808 The oil and gas reservoirs of the Ban II oil group are divided into six small layers, with oil and gas distribution in small layers 1–5. Small layers 1 and 2 are thicker than the other layers. The distribution of sandbodies in each small layer is stable, with good connectivity and good physical reservoir properties. The effective thicknesses of gas layers 1 and 2 are 5.4 m and 5.0 m, respectively; the distribution ranges of gas layers 3, 4, and 5 are slightly smaller, and the average effective thicknesses of these gas layers are 3.1 m, 3.9 m, and 2.9 m, respectively. The oil layers of the oil group of the upper Ban IV group are mainly distributed in layers 3, 4, and 5 (layers 2 and 8 have some wells with oil layers). The oil layers in layer 3 are thinner, with an average effective thickness of 1.8 m. The plane distribution of the oil layer is small and presents lenticular distribution in the vicinity of Wells 829-0 and 28-3. Small oil layers 4 and 5 are relatively thick with a maximum thickness of 7.0 m and an average effective thickness of 4.6 m. The plane distribution of the oil layer is also relatively stable. The oil layers of the oil group of the lower Ban IV group are mainly distributed in layers 1, 3, and 4 (although layer 1 is relatively small), with an average effective thickness of 2.6 m. The oil layers in layer 3 are thinner, with an average effective thickness of 1.8 m. The plane distribution of oil layer is small and presents lenticular distribution in the vicinity of Wells 829-0 and 28-3. Small oil layers 4 and 5 are relatively thick with a maximum thickness of 7.0 m and an average effective thickness of 4.6 m. The plane distribution of the oil layer is also relatively stable. The original formation pressure of the Ban II oil group is 29.05 MPa, with a pressure coefficient of 1.05, a formation temperature of 99 °C, and a geothermal gradient of 3.6 °C/100 m. The original formation pressure of the upper oil group of Ban IV is 32.68 MPa, the pressure coefficient is 1.06, formation temperature is 120 ° C, and the geothermal gradient is 3.6 °C/100 m. The original formation pressure of the oil group of lower Ban IV is 36.58 MPa, with a pressure coefficient of 1.12, a formation temperature of 124 °C, and a geothermal gradient of 3.6 °C/100 m. This represents a normal temperature and pressure system. The formation water in this area is NaHCO3 type, with total salinity of each oil group of 7000–10,000 mg/L and Cl of 1500–2500 mg/L. Ban828 Among the nine small layers in the oil group of upper Ban IV, there is an exception that small layer 6 does not contain oil. The remaining small layers have oil and gas distribution to varying degrees, with average effective thickness of a single well of 15.6 m. Among them, five small layers are thicker, with the average thickness of a

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single layer being up to 10.5 m, and with a maximum of 16.8 m and minimum of 4.2 m in the major small layer. In upper Ban IV of the Ban828 fault block of Dazhangtuo the reservoir type is structural lithologic oil and gas reservoir. There is no uniform oil-gas-water interface in the vertical direction, reflecting the characteristics of layered oil and gas reservoirs. The gas-water interface is at 3170 m and the oil-water interface is at 3200 m. Layers 2 and 3 are pure gas layers, and the gas-water interfaces are at 3225 m and 3250 m, respectively. Layer 4 is a lenticular oil and gas reservoir controlled by lithology. Layer 5 is oil and gas reservoir with oil rim, gas-oil interface at 3280 m and oil-water interface at 3320 m. The original formation pressure of the upper oil group in Ban IV is 38.04 MPa, with a pressure coefficient of 1.1, an average oil layer temperature of 110 °C, and a geothermal gradient of 3.1 °C/100 m, which represents a normal pressure and temperature system. The formation water is NaHCO3 type, with average salinity of 6600 mg/L and Cl content of 1200 mg/L on average. The fault block is mainly composed of 1–5 small layers of the upper oil group on Ban IV, with a proven oil-bearing area of 1.8 km2, petroleum geological reserves of 85  104 t, and dissolved gas reserves of 2.6  108 m3. The proven gas-bearing area is 1.2 km2. The geological reserves of gas in the gas layer are 3.08  108 m3, and the geological reserves of condensate oil are 19.4  104 t.

Development Process Dazhangtuo The Dazhangtuo condensate gas reservoir was discovered by the drilling of Well Ban 52 in May 1975. The well began trial production in June 1994 and experienced two stages of pilot production (June 1994–December 1994) and the development of gas injection to maintain pressure (January 1995–December 1999) (Fig. 3). By the end

250

40

Daily oil yield (t)

30 25

150

20

Daily oil yield 100

15

Daily gas yield

10

50

5 0 94.6

0 94.12

95.6

95.12

96.6

96.12

97.6

97.12

Fig. 3 Dazhangtuo condensate gas reservoir development curve

98.6

98.12

Daily oil yield (×104m3)

35 200

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45

of February 2000, there were five gas production wells and four wells in the entire fault block. Cumulative oil production was 26.2  104 t, with net dry gas production of 1.7  108 m3, and 2.8  104 m3 of water. The formation pressure before the reservoir was 19.55 MPa and the total pressure drop was 5.5 MPa.

Ban876 The Ban876 gas reservoir was brought into production in March 1979. A total of three wells for gas recovery were drilled and completed. The initial stage of development experienced a high-speed development stage (December 1979– 1987). Formation pressure declined linearly. After 1988, only the Ban 876 gas well remained in operation and producing gas (Fig. 4). By March 1995, all the wells had been shut down, with final cumulative production of 1.45  104 t of condensate, 2.7  108 m3 of gas, and 7387 m3 of water. Central North Banqiao The Central North Banqiao gas reservoir has been in production since December 1973 and was developed in 1978. It has experienced three development stages: capacity construction (January 1974–December 1978), stable production (January 1979–December 1981), and decline (January 1982–December 1997) (Fig. 5). A total of 18 oil and gas wells were drilled. By the end of 1997, cumulative oil recovery was 68.76  104 t, with gas production of 20.8  108 m3, oil recovery degree of 24.6%, and gas recovery degree of 61%. Formation pressure before storage construction was 11.5 MPa. Central South Banqiao The Central South Banqiao gas reservoir has been in production since November 1974 and was developed in 1977. It has experienced capacity construction (November 1974–December 1979), stable production (January 1980–December

Fig. 4 Development curve of 876 fault block

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Fig. 5 Development curve of Central North Banqiao fault block

Fig. 6 Development curve of the Central South Banqiao fault block

1982), and decreasing production (1983). A total of 20 oil and gas wells were drilled, including 17 gas wells and 3 oil wells, with cumulative oil recovery in four phases (Fig. 6), water injection development (March 2001–July 2004) of 19.67  104 t, and gas recovery of 7.4  108 m3. The oil recovery degree was 18% and gas recovery 39%. The formation pressure before construction of the storage facility was 22 MPa.

Ban808 The Ban808 fault block and the Block 2 oil group were brought into production in August 1974. Between 1974 and 1982, the fault block was mainly engaged in oil production. After 1982, gas production predominated. A total of 10 wells were drilled, including 4 gas wells and 6 oil wells (Figs. 7 and 8). By February 2005, total oil production was 13.50  104 t, with an oil recovery degree of 10.8%. Total

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Fig. 7 Annual gas production diagram of the No. 2 oil layer in the Ban 808 fault block

Fig. 8 Annual oil production diagram of the No. 2 oil layer in the Ban 808 fault block

gas production was 5.6  108 m3, with a gas recovery degree of 70.7%. Cumulative water production was 26.4  108 m3.

Ban828 The No. 4 upper oil group in the Ban828 fault block was brought into production and development in 1979 and experienced two stages: natural energy depletion mining (February 1979–December 2000) and water injection development (January 2001– February 2005) (Fig. 9). By the end of February 2005, a total of eight oil wells had

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Fig. 9 Production history curve of the No. 4 oil group of the Ban 828 fault block

Table 2 Reserves calculation results of the Banqiao fault block

Gas storage Dazhangtuo Ban876 Central north Banqiao Central south Banqiao Ban808 Ban828 Total

Horizon Ban II Ban II Ban II

Original pressure (MPa) 29.77 22.5 29.77

Natural gas reservoirs (108 m3) Volumetric Pressure drop method method 14.87 15.50 5.36 4.29 28.89 29.94

Ban II

30.32

17.29

Ban II/IV Ban II

29.09

4.62

4.44

38.04

5.08 76.11

6.84 71.31

10.3

been drilled, with cumulative oil production of 9.5  104 t, gas production of 3.7  108 m3, and water production of 4.9  104 m3.

Dynamic Reserves The entire storage group is a weak-medium edge water fault block condensate gas reservoir, and geological reserves of natural gas have been obtained by the volume and pressure drop methods (Table 2). The geological reserves of natural gas of the

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storage group obtained by applying the volume method were 76.11  108 m3, and the geological reserves obtained by the pressure drop method were 71.31  108 m3. Among these, the natural gas geological reserves of Dazhangtuo, Ban876, Central South, Central North, Ban808 and Ban828 were 14.87  108 m3, 5.36  108 m3, 28.89  108 m3, 17.29  108 m3, 4.62  108 m3, 5.08  108 m3, respectively. Dynamic geological reserves were 15.50  108 m3, 4.29  108 m3, 29.94  108 m3, 10.3  108 m3, 4.44  108 m3, 6.84  108 m3, respectively.

Construction Scheme of Gas Storage Dazhangtuo was brought into production and operation in 2000, and all six storage groups were in operation by 2007. By the end of gas production in March 2018, the Banqiao gas storage group was safely operating 18 injection-production cycles, with cumulative gas injection of 235.78  108 m3, cumulative gas production of 209.14  108 m3, maximum daily gas injection volume of 1644  104 m3, and maximum daily gas production volume of 2459  104 m3. The Banqiao storage group was brought into production in 2000. In the initial stage, Dazhangtuo alone was operated using injection and mining, with a stock volume of 10.89  108 m3. In the process of multi-cycle injection and production operations, as gas storage has been successively completed and brought into operation and the capacity of existing storage has been expanded, the inventory has shown a rapid increasing trend (Table 3). The designed capacity of the storage facility is 68.98  108 m3, but the practical capacity has reached 73.41  108 m3, which exceeds the design capacity of the scheme. The storage group is still in the stage of capacity expansion, and gas injection and production capacity has been constantly improving. With implementation of the capacity reaching project, the capacity of the Banqiao storage group will be further increased. The Banqiao Storage group was formed by the reconstruction of water-invaded sandstone gas reservoirs. Due to the complex seepage mechanisms of strongly heterogeneous water-flooded reservoirs and multi-period injection and production operations, the utilization rate of pore space has been low. At the end of gas injection, the gas phase is mainly distributed in medium-sized pores, with the fine throat mainly occupied by bound water. The gas expansion capacity of the gas drive is low and there is a dead gas area. Some of the stored gas volume is not effectively involved in the gas production process, which reduces overall operating efficiency, and the liquid discharge and expansion cycle is long. The working volume is a long and slow process. According to the characteristics of strong injection and strong production, and the injection-production cycle of underground gas storage, it is necessary when adjusting the layout of the gas storage to highlight the requirements of short-term strong injection and strong production. Reservoir development is relatively poor, and areas have been flooded to expand the efficiency of gas flooding and increase the utilization of reservoir capacity. Taking the Central South Banqiao gas storage as a typical example, an injection-production well pattern was deployed in the form of

Cycle (Year) Designed 2000–2001 2001–2002 2002–2003 2003–2004 2004–2005 2005–2006 2006–2007 2007–2008 2008–2009 2009–2010 2010–2011 2011–2012 2012–2013 2013–2014 2014–2015 2015–2016 2016–2017 2017–2018

Storage volume(108 m3) Dazhangtuo Ban876 17.81 4.65 7.56 10.89 11.50 2.95 11.81 3.35 12.01 3.63 12.05 3.84 12.19 3.90 12.18 4.00 12.36 3.93 12.60 4.06 12.65 4.07 12.80 4.12 13.03 4.19 13.05 4.29 13.25 4.44 13.44 4.60 13.39 4.64 13.44 4.64 Central South Banqiao 9.71

6.31 7.11 8.10 9.09 10.22 10.62 10.95 11.50 11.87 12.13 12.34 12.67 12.77

Central North Banqiao 24.48

11.47 15.07 16.34 17.85 19.07 19.94 20.11 20.82 21.95 23.21 24.37 25.65 25.71 25.89 26.30

Table 3 Banqiao gas storage end-of-injection inventory

3.63 5.71 7.43 8.59 9.18 9.27 9.11 9.64 10.09 10.85 11.02 11.39

Ban808 7.64

4.39 4.75 5.00 4.94 4.94 4.90 4.85 4.96 5.05 4.96 4.87

Ban828 4.69

Storage group 68.98 7.56 10.89 14.45 26.63 30.71 38.54 44.68 53.46 57.51 60.58 62.28 64.02 65.93 68.07 70.53 71.98 72.56 73.41

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two well groups in areas where sandbodies are developed and the reservoirs have good physical properties. The reservoir has relatively poor physical properties and poor control of non-main parts. The injection and production well pattern system has poor control over the storage volume and it is difficult to meet the requirements of regular efficient peak gas production.

Conclusion This chapter introduces geological and reservoir characteristics of Banqiao Gas Storage Group. The Banqiao Gas Storage Group is located in the Dagang Oilfield, Binhai New District, Tianjin, which is more than 100 km from Beijing and 40 km from Tianjin. The Dazhangtuo gas storage facility was the first to be established in China, becoming operational in 2000, and a series of gas storage facilities including Ban876, Central North Banqiao, Central South Banqiao, Ban808, and Ban828 were successively established in 2007, forming the first batch of commercial gas storage groups in China.

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Banqiao Storage Group Multi-cycle Operation Xinhua Ma

Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operation Pressure of Multi-cycle Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operation Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . The Possibility of Large-Scale Leakage of Gas Storage Is Small . . . . . . . . . . . . . . . . . . . . . . . . . . . Implemented Volume of Gas-Bearing Pores . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Banqiao Storage Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Working Gas Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Division of the Capacity Expansion Stages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Characteristics of the Technical Indicators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Usable Pore Volume . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Storage Capacity and Working Gas Volume . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Law of Cushion Gas Depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . High Depletion Period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depletion Reduction Period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Low Depletion Period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Law of Well Pattern Space . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

54 54 54 57 58 61 62 65 66 66 67 68 70 70 71 71 72

Abstract

This chapter introduces the operation efficiency and operation effect of six gas storage facilities in the Dagang area. Among them, the Dazhangtuo facility has reached the designed working gas volume after 18 cycles of operation. Its working gas ratio is high, and the operation effect is good. The Ban 876 gas storage facility has not reached the designed working gas volume, and its operating efficiency is low. After four new infill wells were drilled, the capacity expansion effect gradually became more prominent in the subsequent cycle. The main operation technical indicators increase, and the operation efficiency is X. Ma Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China e-mail: [email protected]; [email protected]; [email protected] © Petroleum Industry Press 2022 X. Ma (ed.), Handbook of Underground Gas Storages and Technology in China, https://doi.org/10.1007/978-981-33-4734-2_3

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improved. The Central North Banqiao gas storage facility has accelerated the capacity reaching and expansion project goal. Six new injection and production wells were drilled, and the capacity expansion effect was gradually observed in subsequent cycles. Apart from the Dazhangtuo gas storage facility, the capacities of the other five gas storage facilities have reached or even exceeded their design indexes. However, the working gas volume is far from the design program, with low working gas ratios. The current expansion rate is reduced, the major storage technical indicators increase slowly, and there is little room for improvement. Keywords

Banqiao storage · Infill wells · Capacity expansion · Working gas ratio · Dazhangtuo · Small gas leakage

Introduction A large amount of natural gas has been injected into the ground at the Banqiao facility, the first commercial gas storage project in China. Concerns about management issues have arisen regarding the possibility of leakage or gas loss, and whether the operational condition of gas storage meets expectations. Therefore, it is necessary to analyze and track the operational status of the plate bridge since it was put into operation. In this chapter, a specific analysis is conducted from the aspects of operational pressure, gas-bearing pore volume, storage capacity, technical parameters, and cushion gas loss.

Operation Pressure of Multi-cycle Operation Operation Pressure The practical operation pressure range of the Dagang gas storage facility is shown in Table 1. The operation pressure range of the Dazhangtuo facility is 31.37– 11.89 MPa, with a pressure coefficient of 1.18–0.45. The operation pressure range of the Ban 876 facility is 27.24–12.75 MPa, with a pressure coefficient of 1.22–0.57. The operation pressure range of the Central North Banqiao facility is 31.87– 12.23 MPa, with a pressure coefficient of 1.18–0.45. The operation pressure range of the Central South Banqiao facility is 31.53–15.43 MPa, with a pressure coefficient of 1.17–0.57. The operation pressure range of the Ban oil group of the Ban 808 facility is 31.48–18.14 MPa, with a pressure coefficient of 1.15–0.66. The operation pressure range of the Ban 828 facility is 36.29–21.35 MPa, with a pressure coefficient of 1.05–0.62. Based on the actual maximum operation pressure of the Ban II oil group (Fig. 1), the maximum operation pressure of the Central North Banqiao facility is the largest, reaching 31.87 MPa. The maximum operation pressure of the Ban IV oil group is

Multiple operation pressure of the gas storage facility (MPa) Dazhangtuo Ban 876 Central North Banqiao Injection Production Injection Production Injection Production end end end end end end Gas (upper (lower (upper (lower (upper (lower storage limit) limit) limit) limit) limit) limit) Designed 30.5 13 26.5 13 30.5 13 00–01 20.00 17.21 01–02 30.64 24.57 02–03 30.50 15.49 24.63 13.40 03–04 31.20 13.09 26.48 13.58 21.45 13.8 04–05 31.37 11.89 26.61 13.60 30.8 12.23 05–06 31.26 25.91 27.24 24.91 31.08 24.65 06–07 31.00 18.30 26.80 16.80 29.81 17.67 07–08 30.17 15.78 26.88 14.80 30.65 14.22 08–09 30.35 15.37 25.50 15.18 31.35 15.26 09–10 30.60 15.73 26.73 14.38 31.5 15.36 10–11 30.61 17.58 26.87 14.55 31.61 17.03 11–12 30.40 15.30 26.32 13.25 31.44 15.75 12–13 30.71 12.91 25.91 12.75 30.14 13. 10 13–14 31.16 18.20 26.45 14.48 31.40 17.36 14–15 31.02 22.50 27.00 16.97 31.30 21.30 15–16 31.12 16.16 26.60 13.99 31.46 16.18 16–17 30.94 15.92 26.75 14.37 31.30 18.06 17–18 31.40 15.85 26.54 14.12 31.27 15.90

Table 1 Multi-period operation pressure range of the gas storage facility

19.25 18.95 18.14 19.88 18.39 19.60 20.71 25.59 18.20 19.15 20.40

28.36 30.18 31.37 31.48 30.78 30.20 30.73 30.86 30.99 31.04 31.26

29.10 28.20 29.50 30.90 31.53 30.89 30.6 30.29 30.80 30.84 30.73 30.60 31.22

17.40 15.90 15.40 16.00 15.69 18.72 19.08 15.50 19.40 22.30 18.95 19.14 18.14

Ban 808 (Ban II) Injection Production end end (upper (lower limit) limit) 30.5/37 13/15

Central South Banqiao Injection Production end end (upper (lower limit) limit) 30.5 13

34.42 35.87 36.29 36.02 36.07 35.55 35.75 35.95 36.13 36.03 36.00

Ban 828 Injection end (upper limit) 37

24.45 22.80 21.35 21.86 25.83 22.25 24.00 28.31 22.65 24.03 24.00

Production end (lower limit) 15

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Fig. 1 Upper pressure limit of the Dagang gas storage operation

36.29 MPa (the Ban 828 gas storage facility). Apart from the Ban 828 gas storage facility, the actual maximum operation pressures of the other five underground gas storage facilities all exceed the designed upper pressure limit, and the ratio to the designed value is about 1.04, which is higher than the designed value of 0.74– 1.11 MPa. This is 1.11 MPa greater than the maximum. The actual maximum operation pressure coefficient of each gas storage facility is within the range of 1.05–1.22, which is also slightly higher than the original formation pressure. The gas injection pressure of the Ban 828 gas storage facility is limited by the ground injection compressor, which is unable to meet the designed upper pressure limit requirements. The actual maximum operation pressure is slightly lower than the designed upper pressure limit. Based on the lower limit of the operation pressure (Fig. 2), except for the Dazhangtuo, Ban876, and Central North Banqiao facilities, the lower limit of the operation pressures of the other three gas storage facilities is higher than the designed value, and the ratio to the design value is 1.02–1.42 with a difference of 0.25–6.35 MPa. The Ban 808 and Ban 828 facilities are affected by strong edge water energy and complex distributions of oil, gas, and water. The actual lower limit of the operation pressure is much higher than the initial designed value. Although the Dazhangtuo, Ban 876, and Central North Banqiao facilities actually met the lower limit of the operation pressure, which is lower than the designed lower limit pressure, the edge water quickly invaded the gas storage at the end of gas production, and the gas production capacities of the gas wells decreased. Furthermore, the intrusion of the edge water had a greater impact on the pore space of the reservoir, which is not

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Banqiao Storage Group Multi-cycle Operation

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Fig. 2 Minimum operation pressure of the Dagang gas storage operation

conducive to the improvement of the operation efficiency of the gas storage facilities. Therefore, during the injection and production operation, the minimum operation pressure of the gas storage should not be lower than the designed lower pressure limit.

The Possibility of Large-Scale Leakage of Gas Storage Is Small The gas channeling phenomenon has been successively deployed in the Dagang gas storage facility. To ensure the safety of the gas storage facility, it was completely blocked at the same time. Furthermore, it has not been used for the corresponding observations, such as water overflow points, caprock sealing, and fault sealing. There is no available operating data to analyze the leakage of the gas storage. At present, the actual operation curve of the gas storage is mainly used to determine the leakage of the gas storage. That is, for stable gas storage without leakage, if the gas measurement is accurate, the relationship between the apparent formation pressure and the storage volume basically changes in the same area. In the case of water invasion or measurement errors, the relationship curve between the pressure and the storage volume will shift to the left. Otherwise, the relationship curve of the apparent formation pressure and the inventory will shift to the right, and natural gas may be lost or the capacity of the gas storage may be expanded. In this case, if the increase in the unit pressure difference of the gas storage is increasing year by year, the gas storage is expanding. Otherwise, there may be a leakage in gas storage.

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From the current injection and production operation dynamics, we can see that except for the Central North Banqiao and Central South Banqiao gas storage facilities, the curves of the other gas storage facilities shift to the right to varying degrees depending on the relationship between the formation pressure and storage, and their storage pressure and storage volume depend on the formation pressure. The volume increase curves also exhibit increasing trends with different magnitudes. The operation curve shows that there is evidently no large-scale gas leakage under the current operation status of the gas storage facilities. In particular, the operation curve of the Central North gas storage facility shifts to the right, and the storage capacity incremental curve is basically stable, with typical leakage characteristics. In addition, the dynamic monitoring of the Ban 816 fault and the comparison of the gas sample compositions also indicate that the storage is leaking. Therefore, further migration and fault sealing monitoring are needed to provide a basis for the next step of optimization and adjustment. In short, although no leakage or safety accidents involving injected gas have occurred, the maximum operation pressure is basically within the normal pressure range, but an excessively high maximum operation pressure has the risk of trap sealing failure, and the injected gas may leak along the caprock and fault, thereby causing greater insidious dangers to the safe operation of the gas storage facility. Therefore, it is necessary to improve the sealing monitoring of the gas storage facility in the future to provide a basis for scientifically and rationally determining the upper pressure limit.

Implemented Volume of Gas-Bearing Pores The Dagang gas storage group has been in operation since 2000. In the initial stage, the injection and production operation was only conducted in the unexhausted Dazhangtuo reservoir, with an implemented gas storage volume of 6.98– 10.05  108 m3. Due to the relatively good geological conditions, no invasion of edge water, and a reasonable well pattern, the utilization rate of the stored gas is high. The other five gas storage facilities were constructed and put into operation successively in 2002, and the overall utilization of the storage group showed a rapidly increasing trend. In 2016, the utilization of the gas storage reached 44.51  108 m3 (Table 2). However, because the five gas storage facilities that were subsequently put into production were all converted from water-invaded gas reservoirs, with strong reservoir heterogeneity and poor physical properties, the gas injection displacement efficiency was greatly reduced, resulting in a low utilization rate of about 60–65%. According to the calculated utilized gas storage and the gas state equation, the utilized gas storage can be converted into the underground gas-bearing pore volume, that is, the gas-bearing pore volume. The results for the multi-period utilization of gas-bearing pore volume of the Dagang storage group are shown in Table 3. In the initial stage, only the Dazhangtuo injection-production operation was utilized, and the volume of the gas-bearing pores reached 380.7  104 m3, which is 93.5% of the original gas-bearing pore volume. This indicates that the original gas-bearing pore

Production and injection cycle 00–01 01–02 02–03 03–04 04–05 05–06 06–07 07–08 08–09 09–10 10–11 11–12 12–13 13–14 14–15 15–16 16–17 17–18

Storage group 6.98 10.05 12.39 15.64 20.12 22.24 25.22 32.18 35.85 38.48 39.60 40.50 41.72 41.98 42.78 43.90 44.51 43.84

Ban Dazhangtuo 876 6.98 10.05 10.46 1.93 10.64 2.14 10.84 2.24 10.90 2.37 11.01 2.42 10.98 2.47 11.09 2.39 11.32 2.50 11.33 2.50 11.47 2.53 11.69 2.60 11.65 2.67 11.80 2.80 11.88 2.87 11.92 2.90 11.88 2.91

Gas storage utilization (108 m3)

1.40 2.20 2.47 2.66 3.39 3.40 3.45 3.88 3.90 3.92 4.16 4.55 4.35

2.86 7.04 7.57 9.00 10.58 11.49 11.71 12.40 12.91 13.33 13.48 13.61 13.80 13.86 13.65 0.59 3.19 5.25 6.29 6.67 6.78 6.75 6.96 7.23 7.67 7.85 7.67

Central South Ban Banqiao 808

Central North Banqiao

2.48 2.98 3.28 3.30 3.37 3.47 3.32 3.42 3.52 3.43 3.40

Ban 828

Table 2 Multi-cycle gas storage utilization statistics of the Dagang warehouse group

Storage group 92.3 92.3 85.7 58.7 65.5 57.7 56.4 60.2 62.3 63.5 63.6 63.3 63.3 61.7 60.7 61.0 61.3 59.7 Dazhangtuo 92.3 92.3 90.9 90.0 90.3 90.5 90.3 90.2 89.7 89.8 89.6 89.6 89.7 89.3 89.1 88.4 89.0 88.3 25.0 46.7 46.3 50.4 55.5 57.6 58.2 59.6 58.8 57.5 55.3 53.1 53.7 53.5 51.9

65.6 63.8 61.7 61.7 62.0 61.8 60.8 61.5 61.3 61.5 62.0 62.2 63.0 62.4 62.5 62.7

22.2 31.0 30.5 29.2 33.2 32.0 31.5 33.8 32.9 32.3 33.7 35.9 34.0

Central Central North South Banqiao Banqiao

Ban 876

Utilization rate of gas storage (%)

16.2 55.9 70.6 73.2 72.7 73.1 74.1 72.2 71.8 70.7 71.2 67.3

Ban 808

56.5 62.8 65.7 66.8 68.3 70.8 68.5 69.0 69.7 69.2 69.7

Ban 828

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Production and injection cycle 00–01 01–02 02–03 03–04 04–05 05–06 06–07 07–08 08–09 09–10 10–11 11–12 12–13 13–14 14–15 15–16 16–17 17–18

Utilized gas-bearing pore volume (104 m3) Central Storage Ban North group Dazhangtuo 876 Banqiao 381 380.7 389 389.4 495 405.6 89.3 654 409.6 93.3 150.9 798 415.0 97.5 285.8 896 426.0 103.8 306.4 1041 432.9 104.9 376.8 1311 437.2 107.2 428.0 1450 439.2 108.1 460.2 1545 441.7 108.9 475.2 1594 442.8 110.3 494.4 1637 445.1 111.4 516.5 1668 447.0 113.0 528.7 1690 448.0 114.1 537.8 1709 448.8 116.1 545.7 1751 449.5 128.0 551.2 1769 449.8 130.0 561.9 1790 450.0 133.7 573.6 97.0 113.5 126.5 133.4 136.1 139.1 141.0 142.0 142.5 142.8 143.0

59.9 97.1 101.0 108.3 136.6 139.5 144.2 153.5 157.7 162.2 181.9 184.7 188.2 29.2 140.4 220.6 256.5 274.0 283.3 286.6 291.8 294.4 297.8 299.7 301.6

Ban 828

Central South Ban Banqiao 808

Table 3 Dagang storage group multi-cycle utilization gas pore volume statistics Accounting for the initial gas-bearing pore volume (%) Central Central Storage Ban North South Ban group Dazhangtuo 876 Banqiao Banqiao 808 13.0 93.5 13.3 95.7 16.9 99.7 43.1 22.3 100.6 45.1 14.1 27.2 102.0 47.1 26.7 30.6 104.7 50.1 28.6 13.4 35.5 106.4 50.7 35.2 21.7 5.1 44.7 107.4 51.8 39.9 22.6 24.8 49.5 107.9 52.2 42.9 24.2 38.9 52.7 108.5 52.6 44.3 30.5 45.2 54.4 108.8 53.3 46.1 31.1 48.3 55.8 109.4 53.8 48.2 32.2 50.0 56.9 109.8 54.6 49.3 34.3 50.6 57.7 110.1 55.1 50.2 35.2 51.5 58.3 110.3 56.1 50.9 36.2 51.9 59.7 110.4 61.8 51.4 40.6 52.5 60.4 110.5 62.8 52.4 41.2 52.9 61.1 110.6 64.6 53.5 42.0 53.2

42.2 49.3 55.0 58.0 59.2 60.5 61.3 61.7 62.0 62.1 62.2

Ban 828

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Fig. 3 Mobile gas-bearing pore volume of the Dagang gas storage operation

volume was used to a high degree. In 2002, the other five gas storage facilities were constructed and put into operation successively. The volume of the gas-bearing pores used by the storage group showed an overall increasing trend, and the expansion rate of the gas storage slowed down in the later period. The gas-bearing pore volume was used, but the increase was small. Moreover, the five gas storage facilities that were subsequently put into production were all converted from water invasion gas reservoirs, with strong reservoir heterogeneity and poor physical properties, and thus, the utilization rate of the gas-bearing pore space was greatly reduced. The utilized pore space accounts for about 62% of the original pore space (Table 3, Fig. 3), and the storage group as a whole has a greater expansion potential to increase the volume of the gas-bearing pores.

Banqiao Storage Capacity The Dagang gas storage group has been in operation since 2000. At the beginning, only the Dazhangtuo gas storage facility was in operation, with a storage capacity of 10.86  108 m3. During the multi-cycle injection and production operation, the gas storage capacity was expanded through the construction and by putting the gas storage facilities into operation, and the supply of the gas storage group shows a rapidly increasing trend. In 2017, the supply of the gas storage group reached 73.06  108 m3 (Table 4), which is an increase of 1.4  108 m3 or 2.0% from the

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Table 4 Multi-period reservoir capacity statistics of the Dagang storage group

Cycle Designed 01–02 02–03 03–04 04–05 05–06 06–07 07–08 08–09 09–10 10–11 11–12 12–13 13–14 14–15 15–16 16–17 17–18

Dazhangtuo 17.81 10.86 11.45 11.66 11.81 11.86 12.07 12.29 12.52 12.60 12.63 12.68 12.74 12.82 12.88 12.93 12.99 13.04

Ban 876 4.65

Central North Banqiao 24.48

Central South Banqiao 9.71

Ban 808 7.64

Ban 828 4.69

3.07 3.35 3.62 3.86 3.88 3.98 4.01 4.04 4.08 4.12 4.15 4.16 4.20 4.62 4.64 4.70

12.36 15.03 16.24 18.00 19.00 19.78 19.99 20.51 21.52 22.72 23.58 24.56 25.36 25.64 26.54

6.36 7.24 8.16 9.07 10.14 10.59 10.92 11.41 11.81 12.16 12.61 12.86 12.99

3.74 5.89 7.47 8.48 9.04 9.23 9.34 9.62 9.78 10.05 10.36 10.61

4.39 4.72 5.00 5.02 5.04 5.05 5.12 5.14 5.16 5.17 5.18

Storage group 68.98 10.86 14.52 27.37 30.46 38.32 44.94 53.71 57.56 60.25 61.88 63.51 65.41 67.12 68.72 70.74 71.66 73.06

previous period. The designed storage capacity of the Dagang gas storage group is 68.98  108 m3. At present, the practical total storage capacity has reached 73.06  108 m3, accounting for 105.9% of the design storage capacity. The storage group is still in the capacity expansion stage. The injection and production capacity of the gas storage is continuously improving, and the implementation of the capacity reaching project of the gas storage has been accelerated. The capacity of the Dagang gas storage group has further increased.

Working Gas Analysis The Dagang storage group has undergone 18 injection-production cycles. In the initial stage, only the Dazhangtuo gas storage facility was produced, with a gas production volume of 0.98  108 m3 and a working gas volume of 5.20  108 m3. With the continuous expansion, the working capacity of the storage group increased, and the peak regulation capacity continued to increase. The peak regulation capacity of the season from 2014 to 2015 reached 18.77  108 m3 (Table 5). The reason for this increase in the overall peak regulation capacity of the storage group is that the newly built gas storage played a role. As the number of injection-production cycles increased, the overall gas injection and production capacity of the gas storage group were continuously enhanced. Furthermore, the gas storage accelerated the capacity

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Table 5 Working gas volume of the Dagang gas storage operation Injection production cycle Planned 00–01 01–02 02–03 03–04 04–05 05–06 06–07 07–08 08–09 09–10 10–11 11–12 12–13 13–14 14–15 15–16 16–17 17–18

Storage group 30.30 5.20 5.24 6.45 8.41 10.15 11.31 12.68 15.22 16.52 17.53 18.01 18.23 18.50 18.61 18.77 19.60 19.76 19.88

Dazhangtuo 6.00 5.20 5.24 5.45 5.57 5.68 5.76 5.79 5.84 5.89 5.94 5.99 6.00 6.00 6.00 6.00 6.00 6.00 6.00

Ban 876 1.89

Central North Banqiao 10.97

1.00 1.04 1.08 1.16 1.17 1.19 1.20 1.21 1.22 1.22 1.23 1.24 1.25 1.41 1.45 1.47

1.80 3.39 3.72 4.64 5.24 5.54 5.60 5.84 5.95 6.04 6.08 6.15 6.33 6.38 6.45

Central South Banqiao 4.70

Ban 808 4.17

Ban 828 2.57

0.67 1.08 1.22 1.30 1.57 1.58 1.60 1.76 1.80 1.85 2.14 2.20 2.24

1.08 1.66 2.00 2.16 2.22 2.23 2.24 2.25 2.44 2.44 2.44

0.65 0.93 1.20 1.22 1.23 1.24 1.25 1.26 1.28 1.28 1.28

expansion. With the implementation of the capacity reaching project and the increase in the number of injection-production cycles, the entire gas storage operation is still in the expansion stage, the peak regulation capacity of the season is further enhanced, and the overall operation effect of the gas storage group has been further improved. The Dagang gas storage group has formed a working gas volume of 19.88  108 m3, but there is a large gap from the design program, that is, only 66% of the design value. This is mainly due to the complex geological conditions of the continental sedimentary conditions of the Dagang group, and the fact that most of the facilities were reconstructed from gas intrusion reservoirs. The working gas ratio is relatively low, ranging from 15.4% to 47.1%, and the overall operation efficiency is low (Table 6). Among them, the working gas volume of the Dazhangtuo facility is 6.00  108 m3, which reaches the indicators of the design program, showing a good working gas ratio and a better operation effect. The operation efficiency and operation effect of the six gas storage facilities in the Dagang group are different. Among them, the Dazhangtuo facility reached its designed working gas volume after 18 cycles of operation, its working gas ratio is high, and its operation effect is good. The Ban 876 gas storage facility has not reached its designed working gas volume, and its operating efficiency is low. After

Gas storage Dazhangtuo Ban876 Central North Banqiao Central South Banqiao Ban808 Ban828 Storage group

Storage capacity (108 m3) Designed Current 17.81 13.04 4.65 4.70 24.48 26.54 9.71 12.99 7.64 10.61 4.69 5.18 68.98 73.06 Current/designed 72.9 99.7 104.7 132.5 135.6 110.3 105.9

Work volume (108 m3) Designed Current 6.00 6.00 1.89 1.47 10.97 6.45 4.70 2.24 4.17 2.44 2.57 1.28 30.3 19.88

Current/Designed 100.0 77.6 58.8 47.7 58.5 49.8 65.6

Working gas ratio (%) Designed Current 33.7 46.0 40.6 31.2 44.8 24.3 48.4 17.3 54.6 23.0 54.8 24.7 43.9 27.2

Table 6 Capacity parameter comparison between the designed program and the current operation of the Dagang gas storage facility

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four new infill wells are drilled, the capacity expansion affect gradually became more prominent in the subsequent cycle. The main operation technical indicators increased, and the operation efficiency was further improved. The Central North Banqiao gas storage facility has been accelerated using the capacity reaching and expansion project. In addition, six new injection and production wells were drilled, and the capacity expansion effect was gradually observed in the subsequent cycles. Except for the Dazhangtuo gas storage facility, the capacities of the other five gas storage facilities have reached or even exceeded the design index. However, the working gas volume is far from reaching the design program, with a low working gas ratio. The current expansion rate decreases, the major storage technical indicators increase slowly, and there is little room for improvement.

Division of the Capacity Expansion Stages Based on the inventory analysis and prediction technical procedures applied to the Banqiao water-invasion gas storage type gas storage facility, the operation of the Dagang gas storage type was summarized, and a typical storage analysis curve was created, providing normalized analysis curve and method for the dynamic analysis and optimization adjustment of similar gas reservoir type gas storage facilities. The injection and production operations of the Banqiao gas storage facility over the past 20 years show that the multi-cycle capacity expansion process of gas reservoir type gas storage has an evident law. In general, gas reservoir-type gas storage facilities have to go through three milestone stages: the rapid expansion stage, the stable expansion stage, and the expansion stop period (Fig. 4). The operation mechanism and expansion characteristics of each stage are significantly different.

Fig. 4 Model diagram of the gas storage type gas storage expansion stage

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Rapid Capacity Expansion Stage Rapid expansion generally occurs in the expansion and production stage. Under the effect of the pressure difference of the injection, the gas bursts along the dominant channel, or it is quickly pointed in the direction of the maximum pressure gradient along the relative development zone of the reservoir. The internal gas flooding has a large range and a high sweeping efficiency, and the technical indicators, such as the storage capacity and the volume of the utilized pores, increase rapidly and by a large margin. Stable Capacity Expansion Stage Stable capacity expansion generally occurs during the stable operation phase. Compared with the rapid capacity expansion stage, the advancing speed of the gas-water front is slower. However, the sweeping effect of the gas flooding within the control range of the well pattern is further improved. The volume increases steadily. The major technical indicators show that the capacity expansion increases with decreasing speed. Stagnant Capacity Expansion Stage During the stagnant capacity expansion stage, the advancement of the gas-water front is basically terminated, and the gas saturation within the control range of the well pattern does not change significantly. The technical indicators remain basically unchanged, and the gas storage has entered the stable injection-production mode. I, the period of rapid expansion; II, the period of stable expansion; III, the expansion stop period

Characteristics of the Technical Indicators In the different operation stages of the gas storage operation, the variation trends and laws of the various technical indicators differ. According to the division of the capacity expansion stages and the years of experience at the Banqiao gas storage facility, the typical curves of each stage of the gas reservoir type gas storage have been determined, which can be used as a reference for the dynamic analysis of the injection and production operation of the gas storage facility.

Usable Pore Volume The usable pore volume refers to the underground gas-bearing pore space occupied as usable storage under the formation temperature and pressure. It is an important technical indicator used to measure the expansion rate and effect of gas storage. Its typical characteristics are shown in Fig. 5. 1. It has good consistency in the expansion stage. During the rapid expansion stage, the usable pore volume increases rapidly. This is mainly because the injected gas

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Fig. 5 Typical diagram of the usable pore volume of the gas reservoir type storage operation

protrudes along the dominant channels, or the injection-production well network is continuously improved. However, during the stable expansion stage, the gas drive expansion rate decreases, and the increase in the usable pore volume is slowed down. In the termination period of the storage capacity, it is dominated by liquid-based production, with a slow expansion rate and a limited increase in the usable pore volume. 2. It is different from the original gas-bearing pore volume. Macroscopically, under the condition of high-speed gas injection, the injection-production well pattern mainly controls the larger pore throats, and the degree of secondary development of small pore throats is low, which significantly reduces the utilization rate of the gas-bearing pore volume. Due to the physical properties, for example, wettability and heterogeneity, the limited gas injection displacement pressure cannot drive out all of the invading water, so some of the invading water will be retained in the original gas-bearing pore spaces, further reducing the effective utilization of the pore space. 3. It has the same curve characteristics as the usable pore volume, and the available indicators also include the usable storage and the storage utilization rate.

Storage Capacity and Working Gas Volume The storage capacity and working gas volume are consistent with the expansion stage, and they are similar to the characteristics of the usable pore volume curve. During the rapid expansion stage, the usable pore volume increases rapidly, and the

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Fig. 6 Typical diagram of the storage capacity and working gas volume of a gas reservoir type storage operation

storage capacity and working gas volume increase rapidly. During the stable expansion stage, the gas drive expansion speed decreases, the usable pore volume decelerates and increases, and the storage capacity and working gas volume increase steadily. The expansion stops (mainly carrying the liquid drainage), the capacity expansion basically stagnates, small changes in storage capacity and working gas volume occur, and the gas storage is in stable operation. Figure 6 shows a typical diagram of the storage capacity and working gas volume of a gas reservoir type storage facility.

Space Utilization Efficiency During the overall expansion of the gas storage, the available gas-bearing pore space grows slowly. After entering the expansion stagnation period, it is still difficult to reach the original gas-bearing pore volume, and the utilization efficiency of the gas-bearing pore space is low (Fig. 7). The working gas ratio of the warehouse is 17–46% (Fig. 8), and the overall operating efficiency is low.

Law of Cushion Gas Depletion The depletion ratio of the cushion gas and the variation in the working gas volume have the same curve characteristics. The former reflects the multi-period depletion of the cushion gas, and the latter reflects the change in the multi-period peak regulation

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Fig. 7 Usable pore volume of the Banqiao gas reservoir

Fig. 8 Working gas ratio of the Banqiao gas reservoir type gas storage operation

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Fig. 9 Typical diagram of the gas depletion ratio and depletion volume of the cushion gas of a gas reservoir type gas storage operation

capacity. The depletion ratio is the ratio between the cushion gas depleted and the gas injected. The multi-period curve’s characteristics are opposite to those of the usable pore volume, which can be divided in the following three typical periods (Fig. 9).

High Depletion Period The gas storage is in a period of rapid expansion, gas drive expansion, and pore volume increase. A large amount of cushion gas needs to be replenished, especially in a gas storage reservoir that is converted from a depleted gas reservoir. The injected gas is mainly used to fill the formation gap with a large increment and rapid increase in the periodic gas cushion gas increment, demonstrating the higher depletion and depletion rate of the cushion gas.

Depletion Reduction Period The results of the gas flooding in the well-controlled range have been further improved. The newly added pore volume needs to increase part of the cushion gas. Moreover, due to the physical properties and wettability of the reservoir, a certain amount of dead gas is formed, which is coupled with the newly added gas outside the well control range. The amount of unusable storage and cushion gas is still increasing, but the amount of depletion is significantly reduced, and the depletion ratio maintains a low growth rate.

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Low Depletion Period The gas-water front advancement has basically stopped, and the gas saturation within the well control range does not change significantly. The gas storage is in a good injection-production cycle based on the low depletion and the small depletion of the cushion gas.

Law of Well Pattern Space Compared with gas reservoir development, the supply radius of gas wells is limited under the short-term, high-speed injection and production conditions of gas storage operations. The injection and production well patterns of some gas storage facilities have a low degree of control over some areas and the low permeability areas in the reservoirs. The radius and the effective permeability of the gas phase chart (Fig. 10) are well correlated, and thus, they can guide the deployment and adjustment optimization of injection and production well patterns for the same type of gas storage.

Fig. 10 Plot of well-controlled radius versus effective permeability of the gas phase for a gas well

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Conclusion Dazhangtuo’s working gas ratio is high, and the operation effect is good. The Ban 876 gas storage facility has not reached the designed working gas volume, and its operating efficiency is low. The Central North Banqiao gas storage facility has accelerated the capacity reaching and expansion project goal. Apart from the Dazhangtuo gas storage facility, the capacities of the other five gas storage facilities have reached or even exceeded their design indexes.

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Suqiao Gas Storage Group Geology Xinhua Ma, Jieming Wang, Xiaosong Qiu, and Junchang Sun

Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stratigraphic Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Structural Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sealing Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reservoir Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Types of Gas Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geologic Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reserveverification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Abstract

The Suqiao gas reservoir group is located about 70 km south of Beijing. It consists of five gas reservoirs: the Su1, Su4, Su20, Su49, and Guxinzhuang reservoir. The reservoir group is composed of carbonate and sandstone reservoirs. The Ordovician lithology of buried hill Su1 is mainly limestone, dolomite, and argillaceous carbonate, with burial depths of more than 4,200 m, a well test permeability of 3.45 mD, and reserves of 16  108 m3. The gas bearing layer of fault block Su20 is the lower member of the upper stone box formation of the carboniferous-superimbedded system. The lithology of the reservoir is mainly Liuqiying quartz sandstone and quartz-pebbled coarse sandstone, with burial

X. Ma (*) · J. Wang · X. Qiu · J. Sun Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China e-mail: [email protected]; [email protected]; [email protected]; [email protected]; [email protected]; [email protected] © Petroleum Industry Press 2022 X. Ma (ed.), Handbook of Underground Gas Storages and Technology in China, https://doi.org/10.1007/978-981-33-4734-2_14

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depths of more than 3300 m, a well test permeability of 67 mD, and natural gas reserves of 2  108 m3. The Ordovician lithology of buried hill Su4 is composed of limestone, dolomite, and argillaceous carbonate, with burial depths of over 4,900 m, a well test permeability of 3.7 mD, and natural gas reserves of 63.52  108 m3. The reservoir rocks of buried mountain Su49 are limestone and dolomite, and the reservoir space is dominated by structural fractures, intercrystalline pores, and dissolution pores. The burial depths are more than 5,000 m, and the water body energy is relatively strong. Similar to Su1, the Guxinzhuang geology has natural gas reserves of 9.7  108 m3. The gas reservoir has a normal pressure system containing condensates and no hydrogen sulfide gas. Keywords

Suqiao storage group · Super deep burial · Sandstone and carbonate · Strong bottom water · Peak shaving for Beijing

Introduction It is difficult for gas to enter and exit a reservoir after the reservoir is built because of the permeability of the reservoir. The water energy also affects the operating pressure range after the reservoir is built. The depth of the reservoir can make drilling difficult and can further increase the cost of reservoir construction. The Suqiao gas storage group is an example of this type of reservoir. Thus, in order to facilitate its later reconstruction as a gas storage facility, it was necessary to study the geological background in detail. Therefore, this chapter presents a detailed analysis of the geological conditions of five gas reservoirs in Suqiao, including the stratigraphic sequence, structures, reservoir physical properties, tightness, and reserve scale.

Stratigraphic Characteristics From the top downwards, the drilled formations in the Su 1, Su 4, Su 49, and Guxinzhuang buried hills are Quaternary, Tertiary, Jurassic, Carboniferous-Permian, and Ordovician (Fig. 1). Of which, the Ordovician is the producing layer of the buried hill gas reservoirs, and the Carboniferous-Permian is the caprock of the gas reservoirs. Fault block Su 20 is located in the upper part of buried hill Su 1. The lower section of the upper Shihezi Formation is the gas-producing layer in this fault block, and the Shiqianfeng Formation and the lower section of the upper Shihezi Formation are the caprock of the gas reservoirs (Fig. 2).

Characteristics of the Ordovician Strata A set of marine carbonate strata was deposited in the Ordovician. In accordance with the strata in northern China, buried hill Su 4 lacks the Upper Ordovician deposits, but

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Fig. 1 Composite column for the Su 20 fault block

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Fig. 2 Composite column for the Su4 fault block

it contains the Fengfeng Formation, the upper Majiagou Formation, the lower Majiagou Formation, the lower Liangjiashan Formation, and the Yeli Formation. In buried hill Su 4, only 14 sublayers of the three formations above sublayer No. 3 of the lower Majiagou Formation have been exposed, of which the youngest is the No.2 sublayer of the Fengfeng Formation, and the oldest is sublayer No.3 of the lower Majiagou Formation. The average apparent formation thickness is 489 m. According

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to the core, sieve residue logging and well logging data, the lithology, and electrical characteristics of the formations in this buried hill are as follows. Fengfeng Formation: Its average apparent thickness is 162 m, and it contains a set of carbonate strata with a relatively high content of argillaceous material. It can be divided into five sublayers. The drill core results reveal that the top of the buried hill is composed of the No.2 and No.3 sublayers of the Fengfeng Formation. Due to denudation, the remained thickness of the formation is different. Sublayer No.2 of the Fengfeng Formation is only preserved in well Su4, with a thickness of 10 m. The other wells contain sublayer No.3, the max thickness of which is 36 m (average of 29 m). According to the core statistics for well Su 4–6, the argillaceous carbonate and mudstone account for 31% of the formation thickness, and the argillaceous dolomite is the most abundant. The mud logging profile shows that the limestone is well developed in the upper part of sublayer No.2 and in sublayer No.3, and grey dolomite is dominant in the lower parts of sublayer No.4 and in sublayer No.5. Two sets of dolomite intervals are stably distributed at the top of the Feng 4 Member and in the middle of the Feng 5 Member, with good interwell correlation and fair reservoir performance. Upper Majiagou Formation: Its average thickness is 266 m, and it can be divided into seven sublayers. According to the lithological and electrical analyses, it can be divided into three members. (1) The first member (sublayers No.1–3) is composed of alternating brown and gray limestone and dolomite layers. The statistical results of the core data show that the dolomite accounts for 68.6% of this member. (2) The second member (sublayers No. 4–6) is a large set of dark-gray and gray limestone, dominated by a micritic texture. The limestone content gradually increases from the top to the bottom. According to the statistics for the entire member, the limestone accounts for about 66% of this member. (3) The third member (sublayer No.7) is mainly composed of an argillaceous dolomite interval. Lower Majiagou Formation: It can be divided into five sublayers. In this buried hill, only wells Su401, 402, and 4-1 penetrate into sublayers No.1–3 of the lower Majiagou Formation. The lithology is mainly characterized by a large set of limestone interbedded with thin dolomite layers.

Characteristics of the Carboniferous-Permian Strata The Carboniferous-Permian strata consist of an alternating set of marine and continental deposits, and they are separated from the underlying Ordovician strata by a parallel unconformity. The Permian can be further divided into the Shiqianfeng Formation, the upper Shihezi Formation, the lower Shihezi Formation, and the Shanxi Formation. The Carboniferous can be further divided into the Taiyuan Formation and the Benxi Formation. The Shiqianfeng Formation and the upper part of the upper Shihezi Formation are dominated by mudstone and are locally interbedded with a small amount of fine silty sandstone. They have a thickness of over 250 m, and they make up an on-reservoir section in this area. The middle-lower parts of the upper Shihezi Formation in the middle section are interbedded with sandstone and mudstone. The sandstone is relatively well developed and is the main reservoir in well Su20. The lower Shihezi

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Table 1 Summary of the lithologic characteristics of the Carboniferous-Permian strata System Permian

Carboniferous

Formation Shiqianfeng

Thickness (m) 70

Upper Shihezi

355

Lower Shihezi

180

Shanxi

180

Taiyuan

220

Benxi

85

Lithologic characteristics Mainly dark mudstone locally interbedded with light fine sandstone The upper section is dark-gray and brown-gray mudstone interbedded with light sandstone. The mudstone distribution is stable, and the thickness of a single layer is generally greater than 15 m. the lower section is interbedded sandstone and mudstone, and it is the concentrated section of reservoir rocks in this area Dark mudstone at the top, and interbedded lightgray and green-gray siltstone and purple-gray mudstone at the bottom Coal seams are well developed, about 5–8 layers, and the thickness of a single layer is 1–10 m Purple-gray and brown-gray mudstone interbedded with gray sandstone, with coal seams Dark-gray mudstone interbedded with gray sandstone, bauxite mudstone at the bottom, directly covering the Ordovician buried hill with parallel orientations

Fig. 3 Distribution of the structures in the Suqiao gas storage group

Formation, the Shanxi Formation, the Taiyuan Formation, and the Benxi Formation in the lower section are mainly characterized by mudstone interbedded with coal seams. In particular, a 5–11.5 m thick layer of bauxite mudstone is developed at the bottom of the Benxi Formation, which plays an important role in the caprock conditions of this area. The lithologic characteristics of these formations are described in Table 1.

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Structural Features The Suqiao gas storage group is structurally located in the middle section of the Wen’anslope (Fig. 3). This section has very well-developed faults. The NE-trending major faults cut the basement structural formation into three buried hill belts and two graben belts. From east to west, the buried hill belts include the Suqiao buried hill belt, which contains buried hills Su 1, Su 4, and Su 6; and the Suqiao west buried hill belt, which contains buried hills Su 2 and Su 11. The Suqiao buried hill belt is sandwiched between two graben belts in a horst structure. It is bounded by the line formed by well Xin1–well Su7 – the Wen’an east fault in the west and the large Xinanzhen–Suqiao fault in the east. The NW-trending fault group cuts the buried hill belts into a series of faulted block mountains, including buried hills Su 6, Su 1, Su 4, and Su 49 from south to north. The Guxinzhuang buried hill is a fault horst formed by two of the remaining main faults.

Su 1 The top structure of the buried hill Su 1 gas reservoir is a fault block mountain cut by faults on four sides. The buried hill strike 20–30° NE. The structure is 5.0 km long from south to north and is 2.0 km wide from east to west. It is higher in the SE and lower in the NW. The strata plung toward the NW. The structural high position is located at the edge of the Suqiao Xinanzhen fault, 180 m southeast of well Su 1–8, at a burial depth of 3780 m. The structural low position is located near the northwestern edge of the fault, at a burial depth of 4300 m. The structural closure amplitude is 520 m, and the trap area is 6.93 km2. The structure of buried hill Su 1 has good inheritance. The internal structure is similar to the shape of the top surface, which is a monoclinic structure, inclined to the NWW, with an azimuth of 285° and a dip angle of 15–20°. There are five small faults inside the buried hill, with more small faults in the north than in the south. Su 20 Fault block Su 20 is controlled by the faults on its eastern, western, and southern sides, and it dips to the northwest. The fault block strikes northeast. The structure is 4.0 km long from north to south and is 1 km wide from east to west. The structure of fault block Su 20 is higher in the southeast and lower in the northwest. The structural high is located at the edge of the Suqiao Xinanzhen fault, to southeast of well Su 1–7, at a burial depth of 3250 m. The structural low is located near the NW edge of the fault, at a burial depth of 3550 m. The fault block has a closure amplitude of 250 m and a trap area of 2.52km2. Su 4 The top structure of the buried hill Su 4 gas reservoir is an early rectangular fault block mountain cut by faults on all four sides. Its eastern and western sides are cut by NE-striking faults, and its southern and northern sides are cut by NW-striking faults. The former constitutes the buried hill belt, while the latter constitutes the

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fault block hill top. The buried hill trends 20–30° NE, and the structure is 5.2 km long from north to south and is 2.23 km wide from east to the west. The Ordovician fault block has an area of 11.5km2 and a closure amplitude of 650 m. The top of the buried hill is generally higher in the east and lower in the west. However, due to the tilting and warping caused by the normal faults around the buried hill, the top surface of the buried hill is tilted on all four sides, and it is flexed in the central-western part. Due to the very large normal faults on the eastern edge of the buried hill, the eastern part of the buried hill experienced significant amounts of tilting along the nearly NE-trending margin extending from well Su 4 to well Su 4-1, forming a relatively high fault edge belt. The high point of the buried hill structure is located about 300 m to the south of well Su 4-3, at a burial depth of 4440 m. The slope angle of the top of the Ordovician strata is 7– 12°, and there are eight faults inside buried hill Su 4. The buried hill’s structure has a good inheritance. The internal structure is similar to the shape of the top surface. The structural form is a northwest inclined monocline, with a dip direction of about 300° and stratigraphic dip angle of 13–20°.

Su 49 Buried hill Su 49 is a fault block mountain cut by the northern section of the NNE-striking Suqiao Xin’an fault and the buried hill Su 49 west fault in the western part of the uplift belt and by the nearly EW-striking buried hill Su 49 north fault and the buried hill Su 49 south fault on its east and west sides. It is wider in the south and narrower in the north. The higher part of the Ordovician buried hill is nose shaped, and the lower part is a monocline. The buried hill strikes about 20° NE. It is higher in the east and south, lower in the west and north, and the terrain’s gradient is about 25°. The highest point of the buried hill is located 100 m to the east of well Wu 49, at a burial depth of 4700 m. Buried hill Su 49 has a trap area of 6.3km2 and a closure amplitude of 550 m. There are six fault combinations in buried hill Su 49, including four faults around the buried hill and two faults inside of it. Guxinzhuang The Guxinzhuang buried hill is controlled by faults, forming a buried hill fault horst that is about 2.5 km long from east to west and about 1.1 km wide from north to south. Its top is cut and broken by five faults, which further subdivide the tectonic units. The NE-dipping fault that cuts through well Ba21 cuts the buried hill top into two tectonic units, i.e., the eastern and western units. In the western tectonic unit, there are no wells drilled in the buried hill, and well Ba64 is completed within the Tertiary strata. The gas reservoir development wells in the Guxinzhuang buried hill are mainly located in the western tectonic unit. At present, there are six wells in the buried hill (wells Ba21, Ba33, Ba67, XB67, Ba33-1, and Ba33-2). The top of the buried hill pitches in toward this vicinity, forming a dome. Its structural high is located near well Ba33-2 in the middle of the structure, with a burial depth of about 3160 m and a closure amplitude of about 330 m.

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Sealing Conditions The caprock of the Suqiao buried hill gas reservoir is composed of CarboniferousPermian strata, which consists of a set of continuous sedimentary strata that overlies the Ordovician system, with a parallel orientation. The Permian Shanxi Formation, the Carboniferous Taiyuan Formation, and the Benxi Formation are the caprock sections of the gas reservoir. The lithology mainly includes interbedded mudstone and coal seams with tights and stone layer with a good caprock performance, of which the bauxite mudstone at the bottom is the best caprock. According to the experimental analysis of the nitrogen injection penetrative pressure of a mudstone sample from well Ren 102,the gas logging permeability is zero .At 26 °C and 30 MPa, the penetrative pressure reaches 40 MPa. The experimental results show that the caprock has a good sealing performance. According to the mudstone smear coefficient method calculations for the Suqiao boundary faults, the fault mudstone ratio is 50–94.7%, and the mudstone smear coefficient is 60–96.8%. Thus, all of the gas storage faults have good sealing properties.

Reservoir Features Su1 According to the statistics of the drill core, mud logging, and electrical logging data, the Ordovician lithology of buried hill Su 1 is mainly limestone, dolomite, and argillaceous carbonate. Among these three major rock types, the dolomite has good physical properties, a high porosity, a high planar porosity, a high permeability, and a good oil-bearing property. Thus, it is the main reservoir rock, followed by the limestone and argillaceous carbonate. According to the reservoir division based on the well logging data, the effective reservoir thickness in the dolomite strata accounts for 46% of the layer’s thickness, while that in the limestone strata it only accounts for 2% of the layer’s thickness. In the fractured sections, the dolomite reservoir accounts for the vast majority. The storage space includes tectonic microfractures, intercrystalline pores, and dissolution pores. According to the analysis of 300 cores from buried hill Su 1, the average effective porosity is 2.32%, of which 79.2% of samples had porosities of less than 3%, and only 9.7% of the samples have porosities greater than 5% (Fig. 4). The statistics of the porosity data for 12 wells based on the electrical log interpretation indicate that the average porosity of the gas reservoir is 5.6%, and that of the oil reservoir is 6.9%. The majority of the fractures are micro- and fine fractures with widths of less than 0.5 mm, and the effective fractures account for 98.1% of the total effective fractures. The reservoir is a microfracture- pore-type reservoir. The fractures are mainly high – angle fractures, with 83% of the fractures having dip angles of greater than 60°. The reservoir has poor seepage conditions. The average air permeability determined from the core analysis is 1.45 mD, and the average effective permeability obtained from the well test interpretation is 3.45 mD, making it a low-permeability oil reservoir.

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Fig. 4 Frequency histogram of the porosity data from the core analysis of buried hill Su 1

According to the statistics of 48 cores, the permeability is 0.1–20 mD, making the magnitude of the difference greater than 200. The horizontal permeability is 2.13 mD, and the vertical permeability is 0.73 mD. Thus, the horizontal permeability is 2.92 times larger than the vertical permeability, making this a low-porosity and low-permeability reservoir. The barrier in the Ordovician strata is mainly argillaceous carbonate, including gargillaceous (mud-bearing) limestone, argillaceous (argilliferous) dolomite, limy (dolomitic) mudstone, and mudstone. The argillaceous rocks have a large plasticity and they easily undergo plastic deformation when stressed. This makes it difficult to form fractures, and thus they can hinder or isolate the fluid flow in the strata.

Su 20 The gas-bearing bed in fault block Su 20 is the Carboniferous to the lower member of the Permian upper Shihezi Formation. The reservoir is mainly composed of quartz sandstone and quartz pebbled coarses and stone, with a medium-good gradation. The mineral composition includes quartz (26–36%), feldspar (26–32%), and rock debris (26–32%). The cements are mainly kaolinite and bauxite, and the cementation is pore-contact type. The reservoir in the gas-bearing section of the fault block is well developed with a stable lateral distribution and good correlation. In well Su 20, the effective thickness of the grade I reservoir is 20.0 m/2 layers and that of the grade II reservoir is 10.2 m/1 layer. The thickness of a single layer is larger (average of 10 m). According to the statistics of 13 core samples from the gas producing bed in well Su 20, the reservoir space mainly consists of pores. The porosity is 14.9–19.2% (average of 16.7%), and the air permeability is 29.8–404 mD (average of 227.4 mD). According to electrical log interpretation results, the porosity is 16.9–17.8% (average of 17.4%), and the

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permeability is 197–307 mD (average of 252 mD). The effective permeability obtained from the well test calculations is 67 mD. Thus, this is a medium-porosity and medium-permeability reservoir. The porosity and permeability values obtained from the physical property analysis and the electrical log data interpretation of the fault block are similar, so it is concluded that the reservoir heterogeneity in this fault block is small.

Su 4 According to the statistics of drill core, mud logging, and electrical logging data, the Ordovician lithology of buried hill Su 4 is composed of limestone, dolomite, and argillaceous carbonate. The statistical results of the fracture and physical property analysis reveal that of these three major rock types, the dolomite is the main reservoir rock. It has a high porosity, a high planar porosity, a high permeability, and good oilbearing property. The argillaceous carbonate and mudstone have the worst reservoir properties. The lime stone is the second best reservoir rock. According to the reservoir classification results obtained from the well logging data, the effective reservoir thickness in the dolomite strata accounts for 46% of the layer’s thickness, while that in the limestone strata only account for 2% of the layer’s thickness. In the fractured section, the dolomite reservoir accounts for the vast majority of the thickness. According to the statistics of the core data, the planar porosity of the vugs in the dolomite accounts for 66–90% of the total porosity, 66% of the vugs are oil-bearing, and the main reservoir space is in vug. The planar porosity of the fractures in the limestone accounts for 67–80% of the total porosity, 70% of the fractures are oil-bearing, and the main reservoir space is in the fractures. Of the 24 identified limestone thin sections, only two contained corroded vugs, accounting for 8% of the total number of identified samples; among the 32 identified dolomite samples, 12 of the samples contained vugs, accounting for 38% of the total dolomite samples. This also indicates that the reservoir space in the dolomite is dominated by vugs, while that the limestone is dominated by fractures. According to the statistics of the mercury injection data for 18 core samples (Table 2), the pore volume of the dolomite with pore-throat radii of >0.1 μm only accounts for 37.63% of the total pore volume, and the limestone only accounts for 51.72%, reflecting the narrow nature of the pores and throats. The statistics of the physical property analysis data of 19 large rock samples and 25 small rock samples reveal that their average permeabilities are 3.7 mD and 7.03 mD, respectively. The calculation results of unstable well test data from five wells indicate that their effective permeability is less than 1–11 mD. This permeability is lower than that of the same type of oil and gas reservoir in the Jizhong depression. There was no large blowdown and leakage during the drilling in buried hill Su 4. The mercury injection curve reflects the narrow nature of the throats of the pores and fractures, and the permeability calculated from the core analysis and well test data is low, so this buried hill is a low-permeability gas reservoir.

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Table 2 Statistics of the mercury injection data for the buried hill Su 4 reservoir

Sample No. 4-2/9 8-5/9 9-2/7 9-4/7 10-11/16(1) 15-2/19 15-12/19 17-22/23 19-13/16(2) 20-6/20(2) 22-6/8(1) Subtotal 13-1/2 15-14/13(1) 21-8/22(2) 21-14/22(1) 21-22/22 23-16/24 24-7/18 Subtotal Total

Lithology Micritic muddy dolomite Fine silty muddy dolomite Fine powder crystal dolomite Fine powder crystal dolomite Powder crystalline dolomite Powder crystalline dolomite Fine powder crystalline dolomite Fine powder crystalline dolomite Micritic powder crystalline dolomite Fine powder crystalline dolomite Dolomitic dolomite Dolomite Fine powder crystal marl Calcarenitic micritic limestone Bioclastic limestone Micrite Dolomitic limestone Mudporphyry limestone Powder crystal limestone Limestone

Pore volume controlled by different throat radii (%) 0.1– >0.1 μm 0.5 μm 91.41 8.59 11.6 79.81 43.06 56.94 6.48 36.58 3.48 96.52 0.95 2.53 16.55 83.45 4.24 12.31 8.93 91.07 8.16 0.77 35.83 64.17 10.8 25.03 38.86 61.14 8.58 30.28 42.92

57.08

5.31

37.61

68.25

31.75

8.32

59.93

14.3

85.7

13.61

0.69

50.45 37.63 56.02 64.73 73.67 36.95 48.91 39.89 41.89 51.72 43.11

49.55 62.37 43.98 35.27 26.33 63.05 51.09 60.11 58.11 48.28 56.89

8.8 7.89 3.64 4.99 8.38 11.77 7.35 6.35 8.06 7.22 7.63

41.65 29.74 52.38 59.74 65.29 25.18 41.56 33.54 33.83 44.5 35.48

Su 49 The reservoir rocks of buried hill Su 49 are limestone and dolomite, and the main reservoir spaces are tectonic fractures, intercrystal pores, and dissolution vugs, with few large fractures and vugs. Circulation was only lost twice during the drilling of well Su 49 (Ordovician) in buried hill Su 49, but the lost circulation rate and amount were small. The first loss of circulation was mainly caused by the leakage of the formation due to the large mud weight, which indicates that the reservoir in the buried hill is a microfractured poroustype reservoir. According to the electrical logging interpretations for well Su 49 and well Su 49-1, the average porosity is 3.8%, including 4.1% in the Fengfeng Formation, 3.9% in the upper Majiagou Formation, and 2.7% in the lower Majiagou Formation. This indicates that the physical properties become poorer from top to bottom, making it a low-porosity and low-permeability reservoir (Table 3).

Layer O2f3 O2f4 O2f5 Subtotal O2S1 O2S2 O2S3 O2S4 O2S5 O2S6 O2S7 Subtotal O2X1 Total

Bed thickness (m) 45 55 38 138 44 54 28 39 58 32 54 309 55 502

Su49

Reservoir thickness (m) 8.8 8.2 6.8 23.8 16.2 18.6 4.0 7.0 5.0 0.0 17.4 68.2 32.6 124.6

Reservoir porosity (%) 5.6 4.6 4.0 4.8 4.1 3.3 4.9 3.7 2.0 0.0 3.5 3.6 2.7 3.6

Reservoir thickness (m) 19.2 12.0 4.8 36 0 2.0 1.4 9.6 2.0

15.0 51.0

Bed thickness (m) 22 48 38 108 43 44 28 44 12

171 279

Su49-1

Table 3 Statistics of the porosity data for the buried hill Su 49 reservoir

4.1

5.3

3.5 7.5 6.1 1.7

Reservoir porosity (%) 3.7 3.5 3.5 3.6 Bed thickness (m) 67 103 76 246 87 99 56 83 70 32 54 480 55 781

Fault block Reservoir thickness (m) 28 20.2 11.6 59.8 16.2 20.6 5.4 16.6 7 0 17.4 83.2 32.6 175.6

Reservoir porosity (%) 4.3 3.9 3.8 4.1 4.1 3.3 5.6 5.1 1.9 0 3.5 3.9 2.7 3.8

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Guxinzhuang Only a 3.87 m section of core was obtained from the gas-bearing section of the Ordovician gas reservoir in the Guxinzhuang buried hill, preventing the acquisition of systematic core analysis data. A large number of geological characteristics and reservoir research results show that the reservoir characteristics of Ordovician buried hill oil reservoir covered by the Carboniferous-Permian strata in the Jizhong area are basically the same as that of gas reservoir Su 1.

Types of Gas Reservoirs Su1 After long-term gravitational differentiation, the fluids in buried hill Su 1 have entered a fluid distribution state with condensate gas in the upper part, black oil in the middle, and bottom water in the lower part. The average relative density of the natural gas is 0.685, the methane content is 83.14%, the critical temperature is 217.5 K, and the critical pressure is 4.7 MPa. The condensate density is 0.793 g/cm3, the viscosity is 0.99 mPa·s, the freezing point is 11.0 °C, the wax content is 3.39%, and the gum + asphaltene content is 2.78%. The crude oil density is 0.853 g/cm3, the viscosity is 6.88 mPa·s, the freezing point is 21.26 °C, the wax content is 14.23%, and the gum + asphaltene content is 9.88%. The total salinity of the formation water is about 18,000 mg/L, the chloride content is about 10,000 mg/L, and the water is sodium bicarbonate and calcium chloride type. The gas reservoir has an initial pressure of 40.9 MPa and a pressure coefficient of 1.05 at its central depth (3978 m). The oil reservoir has an initial pressure of 42.0 MPa and a pressure coefficient of 1.01 at its central depth (4238 m). The gas reservoir has a formation temperature of 136 °C and a geothermal gradient of 2.8 °C/100 m at its central depth, making it a normal temperature and pressure system. Due to the gravitational differentiation, buried hill Su 1 contains gas, oil, and water from top to bottom, with serious planar reservoir heterogeneity. In particular, the existence of a low-permeability area in the central area of well block Su 7 leads to heterogeneous gas–oil and oil–water contact depths in the northern block, southern block, and the central area of the buried hill. According to the oil testing and well logging interpretation data for each well, and considering the influence of the gas coning caused by production with a large pressure difference during oil testing, it was determined that the gas–oil contact in the northern block is at 4206 m, and the oil–water contact is at 4270 m; the gas–oil contact in the southern block is at 4140 m, and the oil–water contact is at 4230 m; and the gas–oil contact in well block Su 7 is at 4280 m, and the oil–water contact is at 4362 m. After the buried hill was put into development, the pressure drop was the same in each well in the southern block, thus these wells drill into the same pressure system. In 1999, when the pressure drop in the southern block and northern block reached 10 MPa, the pressure drop in well Su7 in the central area had only reached 3.4 MPa, which indicates that the pressure systems of oil and gas reservoirs are inconsistent in the various well areas (Fig. 5).

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Fig. 5 Profile of gas reservoir Su 1

Buried hill Su 1 is a condensate gas reservoir with an oil ring in an ultra-low permeability zone. Due to the existence of a tight zone around well Su7, the buried hill is divided into three independent zones, i.e., the southern zone, the northern zone, and the central zone, with independent gas–oil contacts, oil–water contacts, and pressure systems.

Su 20 The average relative density of the natural gas is 0.748, the methane content is 76.01%, the ethane content is 10.83%, the propane content is 5.33%, the butane +pentane content is 3.81%, the critical temperature is 222.88 K, and the critical pressure is 4.748 MPa. The crude oil at ground level has good properties, with a yellow color, low density, low viscosity, low freezing point, and low initial fraction. The crude oil density is 0.774 g/cm3, the viscosity is 1.2 mPa·s, the freezing point is 5 °C, the sulfur content is 0.03%, the wax content is 3.99%, the gum+asphaltene content is 0.96%, and it has typical condensate characteristics. The formation water has a chloride ion content of 3456 mg/L, the total salinity is 7630 mg/L, and the water type is NaHCO3. The measured temperature at a depth of 3311 min well Su 20 is 108.3 °C, the pressure is 34.7 MPa. The calculated temperature of the middle of the reservoir is 109.3 °C, the pressure is 35.7 MPa, the converted geothermal gradient is 2.8 °C/100 m, and the pressure coefficient is 1.05, making it a normal temperature and pressure system. In well Su20, in the 3342.0–3376.6 m interval, 20.0 m of two grade I gas layers were identified, and in the 3379.8–3392.4 m interval a grade II gas–water layer was identified. During the gas testing, oil testing was conducted in the 3419–3422 m interval, which had produced water. In the 3342.0–3392.4 m interval, for a 12 mm choke, the daily oil production was 134.4 t, the daily gas production was 21.9  104 m3, and the daily water production was 144m3.This shows that the

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Fig. 6 Profile of gas reservoir Su 20

gas–water contact is located at about 3376.6–3379.8 m. Through composite analysis, it was determined that the gas–water contact is located at 3376 m (Fig. 6). The original condensate content in fault block Su 20 was very high (upto800g/m3), and the difference between the formation pressure and the dew point pressure was very small, so the reverse condensate phenomenon in the formation is very serious. Thus, this fault-block gas reservoir is a closed condensate gas reservoir with block characteristics and a high condensate oil content.

Su 4 After long-term gravitational differentiation, the fluids in buried hill Su 4 have entered a fluid distribution state with condensate gas in the upper part, and bottom water in the lower part. The average relative density of the natural gas is 0.6722, the methane content is 84.43%, the critical temperature is 211.96 K, and the critical pressure is 4.67 MPa. The average density of the condensate is 0.7955, the viscosity is 0.89 mPa·s, the freezing point is 9 °C, the wax content is 6.71%, the sulfur content is 0.03%, and the gum + asphaltene content is 1.24%. The total salinity of the formation water is about 20,000 mg/L, the chloride content is greater than 10,000 mg/L, and the water is NaHCO3 type. The gas reservoir has an initial pressure of 40.9 MPa and a pressure coefficient of 1.05 at its central depth (3978 m). At its central depth (4700 m), the gas reservoir has a formation temperature of 156 °C, a geothermal gradient of 2.52 °C/100 m, an initial formation pressure of 47.9 MPa, and a pressure coefficient of 1.0–1.06, making it a normal temperature and pressure system. According to the data from the gas testing, mud logging, and electrical logging interpretations of each well, the gas–water contacts in all of the wells in the buried

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Fig. 7 Profile of gas reservoir Su 4

hill Su 4 gas reservoir are consistent (Fig. 7). The depth of the gas–water contact is relatively uniform, 4936.0–4980.0 m. Through composite analysis, the gas–water contact was determined to be located at 4954.0 m. Buried hill Su 4 is a closed, low-permeability, condensate gas reservoir with a single temperature and pressure system, a unified gas–water contact, massive characteristics, and a medium condensate content.

Su 49 In buried hill Su 49, the average relative density of the natural gas is 0.7175, the methane content is 77.62%, the ethane content is 11.89%, and there is little H2S (45.71–59.34 mg/m3). The critical temperature is 218.99 K, and the critical pressure is 4.681 MPa. The gas reservoir is characterized by a lower relative density and a higher methane content in the upper part and a higher relative density and lower methane content in the lower part. The crude oil at ground level has good properties, exhibiting a yellow color, low density, low viscosity, low freezing point, and low initial fraction. Its relative density is 0.7802–0.8061, the viscosity is 0.8827– 1.12 mPa·s, the freezing point is 11 to 4 °C, the initial boiling point is 41–84 °C, and the fraction at 200 °C is 50–58%. It has typical condensate characteristics. According to the data from the formation water analysis, in the 5122–5250 m interval in well Su49, the chloride content is 4386.9 mg/L, the total salinity is 9682.5 mg/L, and it is NaHCO3 type. In the 4752.01–4950 m testing interval in well Su49, the measured formation pressure is 48.48 MPa and the pressure coefficient is 1.0 at a depth of 4726.6 m. In the 4949.33–5030 m testing interval, the measured formation pressure is 49.5 MPa and the pressure coefficient is 0.99 at a depth of 4951.67 m. After converting to the central depth of the gas reservoir, the formation pressure is

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Fig. 8 Profile of gas reservoir Su 49

48.92 MPa and the pressure coefficient is 0.99. In the 4752.01–4950 m testing interval, the measured formation temperature is 152 °C and the geothermal gradient is 2.80 °C/100 m at a depth of 4726.6 m. After converting to the central depth of the gas reservoir, the formation temperature is 154 °C. Thus, it is a normal temperature and pressure system. The electrical logging interpretation shows that in well Su49, the bilateral resistivity curve exhibits an apparent decrease at a depth of 5180 m. The mud logging data shows that well Su49 exhibits fluorescence at well depths of less than 5213 m. The oil testing data for the 4952.0–5028.6 m interval indicate that well Su49 had a daily oil production of 30.4 t, a daily gas production of 126660m3, and a daily water production of 2.4m3. After the overall development, the initial daily oil production was 47.3 t, and the daily gas production was 118209.4m3. It was determined that the gas–water contact in buried hill Su 49 is located at 5176 m (Fig. 8). When the gas reservoir in the 5122–5250.0 m interval was tested, the formation produced water, indicating that the gas reservoir contains bottom water. However, the water production is low (only13.92m3/d), and the productivity index permeter is only 0.035m3/d· MPa. Thus, the buried hill Su 49 gas reservoir is a massive carbonate condensate gas reservoir with weak bottom water, a high condensate content, and a low or extra-low permeability without an oil ring.

Guxinzhuang The average relative density of the natural gas is 0.6482, the methane content is 88.02%, the ethane content is 4.86%, the propane content is 1.32%, the butane content is 0.67%, and the total methane–butane content is 94.87%. The content of pentane and the higher alkanes is 0.76%, the CO2 content is 3.47%, the H2S content is 0%, the N2 content is 1.34%, the critical pressure is 4.64 MPa, and the critical temperature is 201.76 K. Well Ba21 produced crude oil from the 3484–3516.0 m

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Fig. 9 Profile of the Guxinzhuang gas reservoir

interval during oil testing in the late stage of the production process. The average crude oil density is 0.8430 mg/L, the viscosity is 5.66 mPa.s, the freezing point is 37 °C, the wax content is 23.79%, the sulfur content is 0.16%, and the gum + asphalt content is 6.71%. During the early stage, this interval produced condensate oil, with an average oil density of 0.7636 mg/L, a viscosity of 1.01 mPa.s, a freezing point of 6 °C, a wax content of 3.81%, a sulfur content of 0.04%, and a gum + asphalt content of 0.85%. The average chloride content of the formation water is 2898 mg/L, the total salinity is 5996 mg/L, and the water type is NaHCO3 and CaCl2. The original formation pressure measured in the middle of the buried hill gas reservoir is 34.16 MPa, and the pressure coefficient is 1.02. The measured formation temperature is 108 °C, and the geothermal gradient is 3.2 °C/100 m, making it a normal temperature and pressure system. When a reserve estimate for the Guxinzhuang buried hill was reported in 1983, the gas–oil contact was 3421 m, the oil–water contact was 3484 m, and the reservoir was a condensate gas reservoir with an oil ring. As the amount of drilling and production data increased, the understanding on the buried hill deepened. The newly determined gas–oil contact was at 3460 m, and the oil–water contact was at 3484 m (Fig. 9). Gas testing was conducted in the 3484.6–3516.4 m interval in Well Ba 21, and by opening the needle valve for a round, the daily oil production was determined to be 0.1 t, the daily gas production was 520m3, and the daily water production was 124m3, indicating that the gas reservoir contains relatively active bottom water. After the gas reservoir was put into trial production on November 8, 1979, it was driven elastically for only 4 months, and the total pressure drop was 1.18 MPa. Due to the supplement provided by the bottom water energy, the formation pressure began to increase. By May 1985, the total pressure drop of the formation had decreased to 0.21 MPa. As of February 2010, the cumulative gas production of the gas reservoir was 3.58  108 m3. At present, the formation pressure is 31.02 MPa, the formation pressure has only decreased by 2.82 MPa, and the gas production per unit pressure drop is 1.27  108 m3/MPa. This demonstrates that the bottom water energy in the gas reservoir is relatively sufficient.

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The Guxinzhuang buried hill reservoir is a massive condensate gas reservoir with an oil ring, bottom water, a single pressure system, and unified oil–water and gas–oil contacts.

Geologic Model Modeling Principle At present, there are two main types of geological modeling methods: deterministic modeling and stochastic modeling. Deterministic modeling methods are mainly based on the data obtained through specific inter-well interpolation processing, which is used to create a unique reservoir geological model. These models are suitable for geological bodies with stable structures and depositional characteristics and continuously changing reservoir physical properties. Stochastic modeling methods are used to study reservoir heterogeneity. They are based on known user information, and on function theory and stochastic modeling to generate optional and equal probability reservoir models. They can organically combine various geological knowledge and observation data, and they reflect the uncertainty caused by a lack of information. The advantage of stochastic modeling is that it controls the reservoir distribution between wells using the various types of data. Seismic data and well logging data are rich in litho logic and physical property information. Seismic information is widely distributed in space and has a high planar resolution. It contains not only formation interface information but also formation physical property information. The seismic attribute parameters are related to the lithology, depth, and physical properties of the formation (e.g., porosity, permeability, and shale content). Although well logging has a higher vertical resolution, it can only measure the stratigraphic information near a well. The reliability and accuracy of the model can be greatly improved by using both seismic data and logging data to constrain the 3D geological model. During reservoir modeling of the buried hill of the Suqiao gas storage, due to the larger well spacing and uneven distribution in this area, the prediction of the inter well reservoir distribution needed to be coordinated using seismic data. In addition, as a carbonate reservoir with fractures, due to its heterogeneity, appropriate modeling methods needed to be selected. Therefore, the porosity data from the well logging interpretation was transformed into the equivalent fracture porosity and matrix porosity according to different modeling standards. The sequential Gauss and coordinated kriging algorithms were selected for the stochastic modeling; the logging data were used as the hard data and the coherent seismic attribute data were used as the soft data. Using this method, a dual medium porosity model was established for buried hill Su 4. Modeling Process The structural model reflects the spatial framework of the reservoir, so before establishing the spatial distribution of the reservoir’s attribute parameters, the

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structural modeling was carried out. A structural model is composed of fault and layer models. The fault model actually reflects the fault planes in three-dimensional space. It is mainly based on the fault file corrected using the seismic interpretation and well data and is used to establish the distribution of the faults in threedimensional space. The layer model reflects the three-dimensional distribution of the stratum interfaces. In order to improve the modeling accuracy and to make the model more inline with the geological reality, the isochronous modeling principle was used, and these ismic and well logging interpretation data were combined to establish a structural model that reflected the horizon framework. The target stratum in this area is the Ordovician buried hill, which is divided into the Fengfeng Formation, the upper Majiagou Formation, and the lower Majiagou Formation. In addition, the Fengfeng Formation is subdivided into three sublayers, and the upper Majiagou Formation is subdivided into seven sublayers. Using the seismic interpretation horizons, fault data, and drilling stratification, fault models and structural models were established for the Su1, Su4, Su20, Su49, and Guxinzhuang gas reservoirs.

Reserveverification Su1 In 1984, when there were only five wells in buried hill Su 1, the reservoir type was a gas reservoir with an oil ring. The reported oil-bearing area was 8.4km2, the geological grade II oil reserves were 408  104 t, the gas-bearing area was 6.9km 2, and the geological grade II natural gas reserves were 31  108 m3 . In 2001, with the improvement of the well pattern and the increase in the number of drilled wells, the oil-bearing area and effective thickness were re-estimated, and the new values were significantly different. The reserves were recalculated. After the recalculation, the oil-bearing area was determined to be 7.8km2, the geological grade I oil reserves were 193.81  104 t, and the recoverable reserves were 28  104 t. The dissolved gas reserves were 5.82  108 m3 and the recoverable reserves were 1.46  104 t. The gas-bearing area was 6.6km2, the geological grade I natural gas reserves were 16.41  108 m3, and the recoverable reserves were 9.3  108 m3. The geological condensate oil reserves were 45.3  104 t, and the recoverable reserves were 18.17  104 t. The development of the well pattern in buried hill Su 1 was completed during the reserve recalculation in 2001, and no new wells were drilled after the reserve recalculation. Thus, there has been no change in the reservoir understanding, there calculated reserves in 2001 were directly changed into discovered and developed reserves in the reserve standard exchange in 2006 (Table 4). Su 20 Fault block Su 20 contains only one well. Its proven reserves were reported in 1984, with a gas-bearing area of 1.6km2, a gas play thickness of 20 m, a unit reserves factor

2006

2001

Year 1984

Area Thickness Type Grade (km2) (m) Crude III 8.4 16.9 oil Gas 6.9 30.2 Crude I 7.8 11.3 oil Gas 6.6 35 (20.5) Crude I 7.8 11.3 oil Gas 6.6 35 (20.5)

Saturation (%) 80 90 80 80 80 80

Porosity (%) 6

6 5.8

4.5 5.8

4.5

290.67

290.67 0.556

275.49 0.556

Volume conversion factor 0.7

16.41

16.41

31

45.3

45.3

Gas Condensate (108 m3) oil (104 t)

Geological reserves

194

194

Crude oil (104 t) 408

Table 4 Summary of the geological reserve calculations for buried hill Su 1 gas reservoir over the years

5.82

5.82

Dissolved gas (108 m3) 12.24

9.3

9.3

9.3

18.17

18.1

Gas Condensate (108 m3) oil (104 t)

Recoverable reserves

28

28

Crude oil (104 t) 28

1.46

1.46

Dissolved gas (108 m3) 6.12

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16

80

327

9.8

2.03

20

2006 I

0.31

Geological reserves Condensate Condensate gas (108 m3) oil (104 t) 10.3 49

Volume Area conversion Year Grade (km2) Thickness (m) Porosity (%) Saturation (%) factor 1984 III 1.6 20 16 75 322

Table 5 Summary of the geological reserve calculations for fault block Su 20 gas reservoir over the years

1.74

3.72

Recoverable reserves Condensate Condensate gas (108 m3) oil (104 t) 1.6 3.72

Note Reported based on exploration Reserve verification

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of 0.322  108 m3/km2.m, geological grade III gas reserves of 10.3  108 m3, and condensate oil reserves of 49.0  104 t. In 1985, a development well (well Su 20-1) was drilled in the high part of the gas reservoir, 800 m from well Su 20. This well was abandoned. The drilling proved that the fault moves inward, the structure changes, and the gas-bearing area decreases. Thus, in the reserve standard exchange in 2006, the reserves of the gas reservoir in fault block Su 20 were recalculated. The oil-bearing area was determined to be 0.31km2, the reservoir thickness was 20 m, the gas initially in place was 2.03  108 m3, the recoverable gas reserves were 1.74  108 m3, the geological condensate reserves were 9.8  104 t, and the recoverable condensate reserves were 3.72  104 t (Table 5).

Su4 In 1984, proven reserves were reported for buried hill Su 4 after three wells were drilled (wells Su4, Su401, and Su402). The reserves are classified as grade III. It was determined to be a condensate gas reservoir with an oil ring. The reported oil-bearing area was 22.54km2, the initial oil in place (IOIP) was 1481  104 t, the gas-bearing area was 19.8km2, and the condensate gas reserves were 85  108 m3, including 202  104 t of condensate oil. In 2001, after six wells were drilled, the reserves were verified, but the reservoir type was reclassified. By increasing the number of drilled wells and obtaining confirmation through production data, the reservoir was reclassified as a condensate gas reservoir without an oil ring. The verified gas-bearing area was 11.5km2, and the condensate gas reserves were 63.52  108 m3, of which the condensate oil reserves were 119.4  104 t, making them grade I reserves. Two new wells (wells Su4-2 and Su4-3) were drilled in buried hill Su 4 in 2005 and 2006, respectively. They were both within the gas-bearing scope, and the drilling results were consistent with the previous understanding of the gas reservoir. Thus, in the reserve standard exchange in 2006, it was concluded that the verified reserves reported in 2001 were reliable, the geologic reserves were unchanged after the standard exchange, and the recoverable condensate reserves were increased by 8.3  104 t (Table 6). Su 49 Proven reserves for buried hill Su 49 were reported in 1999. It was determined to be a condensate gas reservoir, with a reported oil-bearing area of 6.0km2, 25.28  108 m3 of grade III gas reserves, 15.17  108 m3 of recoverable gas reserves, 91.3  104 t of geologic condensate reserves, and 36.5  104 t of recoverable condensate reserves. Two new wells (wells Su49-1 and Su49-2) were drilled in buried hill Su 49 after the proven reserves were reported in 2005. The recoverable reserves were calibrated based on the production performance data. The calibrated recoverable gas and condensate reserves were 9.72  108 m3 and 30.0  104 t, respectively. In the reserve standard exchange in 2006, it was concluded that the reserves reported in 1999 were reliable, the two new wells were both within gas-bearing scope, and the drilling results were consistent with the previous understanding of the gas reservoir. Thus, the geologic reserves remained unchanged after the standard exchange (Table 7).

Grade III

I

I

1984

2001

2006

11.5

11.5

61.5

61.5

Area Thickness (km2) (m) 19.8 49.9

4.0

4.0

Porosity (%) 3.8

80

80

Saturation (%) 80

289.04

289.04

Volume conversion factor 283

63.52

63.52 119.4

119.4

Geological reserves Condensate Condensate gas (108 m3) oil (104 t) 85 202

Table 6 Summary of the geological reserve calculations for buried hill Su 4 gas reservoir over the years

26.7

26.7

50.6

42.3

Recoverable reserves Condensate Condensate gas (108 m3) oil (104 t) 81

Note Reported based on exploration Reserve verification Reserve standard exchange

4 Suqiao Gas Storage Group Geology 97

3.8

51.1

2006 I

6.0

Porosity (%) 3.8

Area Thickness Year Grade (km2) (m) 1999 III 6.0 51.1 80

Saturation (%) 80 287.83

Volume conversion factor 287.83 25.28

91.3

Geological reserves Condensate Condensate gas (108 m3) oil (104 t) 25.28 91.3

Table 7 Summary of the geological reserve calculations for buried hill Su 49 gas reservoir over the years

9.72

30.0

Recoverable reserves Condensate Condensate gas (108 m3) oil (104 t) 15.17 36.5

Note Submitted by exploration Reserve standard exchange

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Table 8 Summary of the geological reserve calculations for the Guxinzhuang buried hill Gasbearing area (km2) 1.7

Type Gas reservoir gas Condensate 1.7

Geological reserves Reservoir thickness (m) 54.2

Net porosity (%) 5.3

Gas saturation (%) 80

Gas volume factor 256.25

Condensate oil density

54.2

5.3

80

256.25

0.758

m3 9.71  108

104 t

20.52  104

15.55

Guxinzhuang When the reserves were reported in 1983, the Guxinzhuang buried hill gas reservoir was considered to be a condensate gas reservoir with an oil ring, an oil–gas contact at 3421 m, and an oil–water contact at 3484 m. The gas-bearing area, which was reviewed and approved by the State Reserves Committee, was reported to be 2.6km2. The grade I gas reserves calculated using the pressure drop method were 3.3  108 m3. In 2010, based on an in-depth and careful geologic study of the gas reservoir, the recalculated geologic gas reserves were determined to be 9.71  108 m3, and the geologic condensate reserves were 15.55  104 t (Table 8).

Conclusions The overall burial depth of the Suqiao gas reservoir group is almost the deepest in China and even in the world, which poses significant challenges in terms of the well construction and operation in the later stage of injection and production. Moreover, most of the gas reservoirs are carbonate reservoirs with poor physical properties, which doomed them to have a low injection and production capacity in the later stage of the gas reservoir. Despite this, these reservoirs have been converted into gas storage tanks, which are mainly connected to the pipeline system from Shaanxi to Beijing and are used to help regulate the city’s gas consumption peak.

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Suqiao Reservoir Development and Storage Design Xinhua Ma

Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Characteristics of Gas Reservoir Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Water Invasion State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Numerical Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Scheme for Building Gas Storage Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geologic Scheme . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling and Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Surface Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Brief Introduction to the Cyclic Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

102 102 102 106 108 110 111 111 114 115 117 119

Abstract

This chapter introduces the exploration and development of the Suqiao reservoir, as well as the design for rebuilding the gas storage facility after reservoir depletion and the operation of the gas storage facility. The Suqiao storage group, with a burial depth of close to 5000 m, consists of five reservoirs: the Su1, Su4, Su49, Su20, and Guxinzhuang reservoirs. In the process of building the storage group, we made full use of the trap dynamic sealing property evaluation technology under complex geological conditions, the partitioning evaluation technology of the storage capacity parameters, the optimization operation technology of the injection and production of fractured, sandstone reservoirs, the drilling and completion technology of super-deep, low-pressure reservoirs, and the reservoir protection technology to optimize the geological scheme and the engineering scheme design. The storage facility was put into operation in 2012, X. Ma Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China e-mail: [email protected]; [email protected]; [email protected] © Petroleum Industry Press 2022 X. Ma (ed.), Handbook of Underground Gas Storages and Technology in China, https://doi.org/10.1007/978-981-33-4734-2_4

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and since then, it has been playing an important role in peak load regulation and supply guarantee in Beijing, Tianjin, and Hebei. Keywords

Suqiao storages · Deeply buried · Storage capacity · Water invasion · Super-deep drilling

Introduction The Suqiao storage group is located in the Bohai Sea area with the largest peakshaving demand. However, the gas storage group is deeply buried and has strong water energy. Therefore, how to make good use of the original gas reservoir space while avoiding the intrusion of water on a large scale is a challenge for Chinese gas storage researchers. Therefore, it is necessary to study the development history of Suqiao reservoir before reservoir construction and the design of reservoir construction scheme, as well as its subsequent operation, so as to provide examples for similar gas reservoir construction in the world.

Characteristics of Gas Reservoir Development Development History Su 1 Gas Reservoir The production test was conducted on Well Su 1 in March 1983, after which it experienced three typical development stages: the production test of the oil ring (3/1983–12/1988), shut-in pressure buildup (1/1989–12/1990), and gas production by returning to the gas reservoir upwards (1/1991–11/2010) (Fig. 1). As of November

Fig. 1 Development curve of the Su 1 gas reservoir

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2010, 12 wells had undergone gas testing by returning upwards in the buried hill, including 8 gas wells put into production and 1 well opened in the same month. With a daily gas production of 0.95
104 m3, a daily oil production of 1.2 t, and a daily water production of 0.8 m3, the cumulative gas production was 7.52
108 m3, with a recovery degree of 45.8%, the cumulative oil production (including black oil) was 19.28
104 t, and the cumulative water production was 15.6
104 m3. In the southern block, the cumulative gas production was 5.61
108 m3, with a recovery degree of 74.7%; the cumulative oil production was 12.17
104 t; and the cumulative water production was 5.86
104 m3. The formation pressure dropped to about 9.8 MPa (average value) in November 2008, with a total pressure drop of 31.1 MPa. In the northern block, the cumulative gas production was 1.91
108 m3, with a recovery degree of 19%; the cumulative oil production was 7.11
104 t; and the cumulative water production was 9.74
104 m3. In the Su 1–5 well field, the formation pressure dropped to 28.29 MPa in November 2008, with a total pressure drop of 12.61 MPa. At present, the southern block has a high cumulative production and a low formation pressure, and it has nearly been exhausted and has lost production capacity. The northern block has worse reservoir physical properties, serious reservoir heterogeneity, and worse connectivity between gas wells. Among 10 drilled wells, seven have obtained industrial oil and gas flow in the gas reservoir; only two wells (Su 1–4 and Su 1–5) were put into production through natural flow, while the other gas testing wells (Su 1, Su 1–1, Su 1–2, Su 3, and Su 1–20) cannot be produced through natural flow due to their worse reservoir physical properties, low productivity, and containing water. The utilization degree of the natural gas reserves is low in the northern block.

Su 4 Gas Reservoir Well Su 4 was put into production on December 24, 1988, after which it experienced three typical development stages: low-speed and stable production (12/1988–10/ 1998), high-speed and unstable peak shaving production (11/1998–1/2003), and development regulation (2/2003–11/2010) (Fig. 2). As of November 2010, all nine drilled gas wells had been put into production, and all had been opened. Due to the reservoir’s heterogeneity, Well Su 401 only produced a low production by interval pumping after reperforation, so there were only eight normal production wells, with daily gas productions of 41.7
104 m3, daily oil productions of 68.4 t, daily water productions of 246.1 m3, cumulative gas productions of 18.6
108 m3, recovery degrees of recoverable gas reserves of 66.6%, cumulative oil productions of 38.01
104 t, and cumulative water productions of 47.8
104 m3. The formation pressure dropped to 27.43 MPa in May 2010, with a total pressure drop of 20.47 MPa. Su 49 Gas Reservoir Well Su 49 was put into production in October 1999, after which it experienced two typical development stages: high-speed and unstable peak shaving production (10/1999–6/2003) and production decline (7/2003–11/2010) (Fig. 3). Three gas wells have been put into production, with cumulative gas productions of 4.8
108 m3,

104

X. Ma

Fig. 2 Development curve of the Su 4 gas reservoir

Fig. 3 Development curve of the Su 49 gas reservoir

recovery degrees of recoverable gas reserves of 49.4%, cumulative oil productions of 17.5
104 t, and cumulative water productions of 18.82
104 m3. The formation pressure dropped to 29.54 MPa, with a total pressure drop of 19.0 MPa. The production of some of the gas wells was achieved by returning reperforation and enlarging pressure differences. Among the nine produced gas wells, three wells (Su 4–14, Su 4–6, and Su 4) in the central-northern part of the gas reservoir are presently being produced with water. Well Su 4–14 and Well Su 4–6 can maintain normal production only through gas lift drainage; and the other wells do not produce water. This gas reservoir is in the gas production stage through natural flow with water and artificial drainage. During the 1999–2003 winter peak shaving period, the over-high gas production intensity of the gas wells led to a large increase in the gas-water contact, and with

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decreasing formation pressure, the open flow also decreased. Therefore, as the gaswater contact moved upwards and the formation pressure decreased, the reasonable anhydrous production of the gas wells also decreased. At present, the anhydrous daily gas production of a single gas well is 4–5
104 m3, and the calculated minimum liquid-carrying gas production of the watering wells under the current flow pressure is around 6
104 m3. However, due to the influence of pressure transmission and small amounts of displacement, the daily gas production of drainage gas wells Su 4–14 and Su 4–6 is 2.7–0.3
104 m3/d.

Su 20 Gas Reservoir Well Su 20 was put into production in October 1988, after which it stably produced until November 2000, with a daily gas production of about 3–4
104 m3. When the wellhead pressure dropped to the transmission pressure, the well was shut in, with a cumulative gas production of 1.47
108 m3, a cumulative condensate production of 3.52
104 t, and a cumulative water production of 1.87
104 m3. After the reducing wellhead pressure and boosting transportation measures were implemented, the well was opened for production in June 2001, with a daily gas production of about 3
104 m3. The well achieved stable production until March 2003. Afterward, since the wellhead pressure was close to the transmission pressure, it was produced by interval opening until November 2004, with a daily gas production of about 2
104 m3. Then, the well was shut in due to energy exhaustion. By November 2010, the cumulative gas production was 1.72
108 m3, the cumulative condensate production was 3.60
104 t, the cumulative water production was 2.18
104 m3, the recovery degree of the recoverable gas reserves was 98.8%, the recovery degree of the recoverable condensate reserves was 96.8%, the formation pressure was reduced from the original 35.72 MPa to 5.82 MPa (relative pressure) in June 2003, and the total pressure drop was 29.9 MPa (Fig. 4).

Fig. 4 Development curve of the Su 20 gas reservoir

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Guxinzhuang Gas Reservoir The Guxinzhuang well was put into production in November 1979, after which it experienced three typical development stages: low-speed production (11/1979–10/ 1998), unstable peak shaving production (11/1998–2/2004), and development regulation (3/2004–11/2010) (Fig. 5). By the end of November 2010, six gas wells had been put into production. Three wells (Ba 33–1, XB 67, and Ba 33–2) were opened in the same month, with daily gas productions of 10.2
104 m3, daily oil productions of 14.07 t, daily water productions of 34.43 m3, cumulative gas productions of 3.85
108 m3 (including 3300
104 m3 of blowout gas production in Well Ba 33), and the recovery degrees of recoverable gas reserves of 74%. The cumulative oil production (including black oil) was 6.83
104 t, and the cumulative water production was 1.6
104 m3. The formation pressure was reduced from the original 33.84 MPa to 31.02 MPa in April 2009 (converted to 3309.5 m, the middle depth of the gas reservoir), and the total pressure drop was only 2.82 MPa.

Water Invasion State The water invasion state is one of the most important factors in the evaluation of gas storage construction. Generally, the material balance equation (MBE) linear method and the material balance method are used for the calculation of water-driven gas reservoirs. We used these two methods to analyze the water invasion in the Su 1, Su 20, Su 4, Su 49, and Guxinzhuang gas reservoirs.

Su 1 In June 2003, when the formation pressure of the southern block of the Su 1 buried hill was 15.65 MPa (relative pressure) before producing gas through drainage, the bottom water influx obtained using the MBE linear method was 22.49
104 m3, the cumulative water production was 2.63
104 m3, and the corresponding net water influx was 19.86
104 m3. According to the material balance method, the calculated bottom water influx was 17.70
104 m3, and the corresponding net water influx was 15.07
104 m3. In December 2008, when the formation pressure was 11.7 MPa (relative pressure) before producing gas through drainage, the calculated bottom

Fig. 5 Development curve of the Guxinzhuang gas reservoir

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107

water influx obtained using the MBE linear method was 61.07
104 m3, the cumulative water production was 5.13
104 m3, and the corresponding net water influx was 55.94
104 m3. According to the material balance method, the calculated bottom water influx was 50.65
104 m3, and the corresponding net water influx was 45.52
104 m3. The calculation results show that before gas production through drainage in the southern block, the maximum water influx was 22.49
104 m3, and the net water inflow was 19.86
104 m3. In December 2008, after gas production through drainage, the maximum water influx was 61.07
104 m3, and the net water inflow was 55.94
104 m3.

Su 4 According to the MBE linear method, when the formation pressure was 32.02 MPa, the bottom water influx was 282.20
104 m3, the cumulative water production was 22.05
104 m3, and the corresponding net water influx was 260.15
104 m3. According to the material balance method, when the formation pressure was 32.02 MPa, the bottom water influx was 147.12
104 m3, and the corresponding net water influx was 125.07
104 m3. The calculation results show that the maximum water influx was 282.20
104 m3 when the current formation pressure was 32.02 MPa, and the net water influx accounts for 92.2% of the apparent water influx. This shows that most of the formation water remains in the gas reservoir. With decreasing formation pressure during gas reservoir exploitation, the formation water continuously invades the top of the gas reservoir, which has a serious impact on the gas reservoir’s productivity. Su 49 According to the MBE linear method, when the formation pressure was 29.54 MPa (relative pressure), the bottom water influx was 27.45
104 m3, the cumulative water production was 15.95
104 m3, and the corresponding net water influx was 11.49
104 m3. According to the material balance method, when the formation pressure was 29.54 MPa, the bottom water influx was 27.94
104 m3, and the corresponding net water influx was 11.99
104 m3. The calculation results show that the maximum water influx was 27.94
104 m3 when the current formation pressure was 29.54 MPa, and the net water influx accounts for 42.9% of the apparent water influx. This shows that nearly half of the formation water remains in the gas reservoir. With decreasing formation pressure during the gas reservoir exploitation, the formation water continuously invades the top of the gas reservoir, which has a serious impact on the gas reservoir’s productivity. Guxinzhuang In the Guxinzhuang buried hill, in April 2009, according to the MBE linear method, when the formation pressure was 31.02 MPa, the bottom water influx was 123.12
104 m3, the cumulative water production was 1.09
104 m3, and the corresponding net water influx was 156.58
104 m3. According to the material balance method, the bottom water influx was 123.12
104 m3, and the corresponding net water influx was 122.03
104 m3. The calculation results show

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that as of April 2009, the maximum water influx was 157.67
104 m3, and the net water influx was 156.58
104 m3, and thus, most of the invaded formation water remains in the reservoir.

Production Reserves The Su 1, Su 4, Su 49, and Guxinzhuang buried hills have the characteristics of water drive during exploitation, and the produced wells all successively produced formation water. The relationship curves by the MBE linear method warp upwards, illustrating the exploitation features of the water-driven gas reservoirs. Therefore, we utilized the MBE linear method to predict the reserves of water-driven gas reservoirs. For nonconstant volume gas reservoirs with a black oil ring, natural water invasion, compressible rocks and fluids, and decreasing formation pressure during exploitation, the material balance relationship between the production volume and the pressure drop can be expressed as 

 Cw Swi þ C f GBgi ¼ ðG  GP ÞBg þ GBgi ð Pi  PÞ 1  Swi
þ W e  W P Bw  N p Bo

ð1Þ

Letting     Cw Swi þ C f P Ce ¼ Cef ¼ Pi :Ce EP ¼ Cef 1  ¼ Ce ðPi  PÞ Pi 1  Swi where G is the original gas in place (OGIP) (104 m3). Swi is the original irreducible water saturation (f). Cw is the compressibility coefficient of the formation water (MPa1). Cf is the effective compressibility coefficient of the rock (MPa1). Pi is the original formation pressure (MPa). P is the current formation pressure (MPa). Gp is the cumulative gas production (104 m3). We is the cumulative water influx (104 m3). Wp is the cumulative water production (104 m3). Np is the cumulative black oil production (104 m3). Bgi is the original gas volume factor (f). Bg is the current gas volume factor (f). Bw is the formation water volume factor (f). When Cef ¼ Pi. Ce 0.10, the nonconstant volume item (Ep) can be neglected. After transforming Eq. (1), the formula of the MBE linear method is Eq. (2), and the schematic diagram is shown in Fig. 6:

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Fig. 6 Schematic diagram of the MBE linear method

G p Bg þ N p Bo þ W p Bw We ¼ þG Bg  Bgi Bg  Bgi

ð2Þ

As shown in Fig. 6, in the Cartesian coordinate system, this diagram uses (GpBg +WpBw)/(Bg-Bgi) as the vertical coordinate and GPBg as the horizontal coordinate. If there is no water invasion in the gas reservoir, a horizontal line is obtained. If there is water invasion in the gas reservoir, a rising horizontal line is obtained. The intercept of the straight line on the vertical axis is the original gas in place (OGIP). In the south block of the Su 1 buried hill, the calculated geologic reserves of the condensate gas obtained using the dynamic method are 7.84
108 m3, the original gas-oil ratio is 2886 m3/m3, the relative density of the condensate is 0.796, the calculated OGIP is 7.51
108 m3, and the geologic reserves of the condensate are 20.7
104 t. In the Su 4 buried hill, the calculated geologic reserves of the condensate gas obtained using the dynamic method are 47.91
108 m3, the original gas-oil ratio is 3730 m3/m3, the relative density of the condensate is 0.796, the calculated OGIP is 46.33
108 m3, and the geologic reserves of the condensate are 98.87
104 t. In the Su 49 gas reservoir, the calculated geologic reserves of the condensate gas obtained using the dynamic method are 15.46
108 m3, the original gas-oil ratio is 2195.28 m3/m3, the relative density of the condensate is 0.7836, the calculated OGIP is 14.56
108 m3, and the geologic reserves of the condensate are 51.7
104 t. In the Guxinzhuang gas reservoir, the calculated geologic reserves of the condensate gas obtained using the dynamic method are 9.88
108 m3, the original gas-oil ratio is 4724 m3/m3, the relative density of the condensate is 0.758, the calculated OGIP is 9.58
108 m3, and the geologic reserves of the condensate are 15.33
104 t. Su 20 is a constant-volume sandstone gas reservoir. With decreasing formation pressure, during exploitation, P/Z is taken as the vertical coordinate and Gp as the horizontal coordinate to obtain the linear regression between P/Z and Gp. The total geological reserves of the condensate gas calculated using the pressure drop method

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are 2.23
108 m3. If 942 m3/m3 is the original gas-oil ratio and 0.774 is the relative density of the condensate, then the OGIP of the gas reservoir is 1.94
108 m3, and the total geological reserves of the condensate are 15.9
104 t.

Numerical Modeling This numerical modeling was conducted using Eclipse, a suite of numerical modeling software produced by Schlumberger. The Eclipse software has powerful functions and excellent performance. It is a suite of precise numerical modeling software, and it is also the most widely used numerical modeling software in the world. In this study, three main modules (PVTi, Office, and Schedule) of the Eclipse software were used to research and fit the fluid phase characteristics, to generate the dynamic history, to fit the production history, and to predict the scheme indexes.

Model Establishment The establishment of a gas reservoir geological model is the basis of the numerical modeling. The correct numerical modeling must be based on a real geological model. The geological models of the Su 1, Su 20, Su 4, Su 49, and Guxinzhuang gas reservoirs were established by Petrel using a suite of 3D geological modeling software. Based on the seismic data, well logging, geostatistics, and sedimentary facies, the data volumes of the 3D geological models were established and displayed by combining deterministic and stochastic methods, and the grid parameter file was directly output for the numerical modeling. The interface between Petrel (geological modeling software) and Eclipse (numerical modeling software) was used to import the grid parameter files into Eclipse. Based on this, the models were properly modified using Flogrid (the preprocessing module in Eclipse), and a new grid system was formed. History Fitting Reserves Fitting According to the exploitation characteristics of the production wells, the porosity, net thickness, fluid physical properties, and other parameters that affect the gas reservoir reserves and the oil ring reserves were modified several times. During the pressure fitting and water production dynamic fitting in the whole area, it was found that the condensate oil reserves are larger than the reserves reported to the state.

Production History Fitting The dynamic parameters of the production wells in the Su 1, Su 20, Su 4, Su 49, and Guxinzhuang gas reservoirs were fitted. The main fitting parameters include the formation pressure, cumulative gas production, cumulative oil production, and cumulative water production of the entire area; and the daily gas production, daily

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oil production, daily water production, bottom flow, and static pressure of each gas well. The daily gas production was determined according to the production situation.

Scheme for Building Gas Storage Facilities Geologic Scheme Principle of Scheme Design General principle: The scheme design for constructing the underground gas storage facilities and the comprehensive geological research were used to accurately calibrate the underground well locations and to simultaneously repeatedly combine the well location design, the drilling engineering design, the surface well site design, and the well bore string design in order to unify the geology, engineering, and surface. (a) Principle of uniform deployment of gas injection and production wells in the gas storage facility: Based on the number of wells indicated by the gas storage construction scheme, and considering the planar distribution uniformity of the gas injection and production wells, the reasonable injection and production capacity were ensured, and the requirements of uniform gas injection and production at all parts of the facility were met. (b) Principle of consistency between the well location design and the gas reservoir operation plan: The gas injection and production wells of the gas storage facility should be deployed in the fractured areas in the higher part of a buried hill structure to employ the top-down injection mode. Moreover, to fully consider the current development situation of the reservoirs when constructing the gas storage facility, the bottom hole depth of a newly drilled well should be as far away as possible from a water body to prevent or slow down gas channeling and to avoid the occurrence of serious oil and water coning when a gas well is produced with a high flow. (c) Principle of optimizing the drilling geological trajectory: To fully consider the characteristics of the gas reservoir; under permissible drilling conditions, the well trajectory in the geological design should be drilled as far as possible into the formations with well-developed reservoirs or into as many sets of oil groups or sub-layers as possible to achieve the optimal development effect. (d) Principle of reducing geological and engineering risks during drilling: The geological risk should be fully considered in the horizontal well design. In the drilling engineering design, under the premise of ensuring an accurate landing, the landing deviation angle of a horizontal well should be controlled (the well deviation angle should not be too large), and there should be room for trajectory adjustment after entering formation. (e) Principle of closely combining the geology, drilling, and surface data: First, according to the preliminary design scheme, a comprehensive geological re-study should be conducted to determine the well location deployment scheme, the seismic data volumes and well locations should be calibrated, the spatial

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position of the underground target point of a new well should be repeatedly determined and designed, and the trajectory of the designed well in the seismic section should be checked to ensure that the target point occupies a favorable position within the structure. Then, the well location coordinates should be sent to the drilling and surface departments, and the orientation and distance from the wellhead to the target point should be adjusted in a timely manner according to the changes in the surface well site survey. In addition, to simulate the designed well trajectory through drilling engineering, the rationality of the frontal distance should be calculated from the target point, drilling depth, and horizontal displacement. Only after closely and repeatedly combining the geology, drilling, and surface data, should the locations of surface and subsurface targets be finalized.

Gas Storage Capacity As the above-described gas reservoirs have been developed for many years, there is a great deal of related dynamic data available, and many methods have been used to calculate their geological reserves. After fully combining and analyzing the dynamic and static data, it was concluded that the dynamic geologic reserves are more substantial and reliable. The risk of using the dynamic reserves as the gas storage capacity is smaller, and it can more truly reflect the underground development status of the gas reservoir and the scale of the producible reserves of the gas reservoir. Moreover, the overall physical properties of the Guxinzhuang gas reservoir are better, the calculated open flow is higher, and the vertical reservoir heterogeneity of the buried hill is not strong; and the physical properties of the Fengfeng Formation in the higher part of the structure is better, the reservoir thickness is larger, and all of the indexes are equivalent to those of the upper Majiagou Formation and the lower Majiagou Formation. Therefore, the calculated dynamic gas geological reserves were finally determined and were used as the reasonable storage capacity (67.4
108 m3) of the Guxinzhuang gas storage. Working Gas Volume When determining the effective working gas volume, the design experience obtained from the Suqiao gas storage facilities should be fully considered, and the operation conditions of the surface gathering and transmission should be satisfied. In principle, the utilization rate of the storage capacity should be about 30–50%. Considering that although the single well productivity and gas column height of the Guxinzhuang buried hill are higher, the bottom water energy is active, and the possibility of bottom water coning at the end of gas production is higher, in order to ensure the normal operation of the gas storage, the working gas ratio should not be too high (about 40% is suitable). For this case, the reasonable working gas volume was determined to be 23.3
l08 m3. Considering that the capacity scale of the Suqiao gas storage group is 67.4
l08 m3, the corresponding capacity utilization rate is 35%. Cushion Gas The determination of the cushion gas ratio not only is related to the geological conditions of the reservoir itself but also depends on the operation conditions of the

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gas storage facility. According to foreign experience, the cushion gas ratio is generally between 35% and 65% depending on the specific situation of the reservoir itself. Based on the comprehensive analysis of the Guxinzhuang gas storage facility, a suitable cushion gas ratio was determined to be about 60%. However, the rising height of the gas-oil contact is relatively low, the formation pressure is maintained at a higher level, and the risk of vertical oil-water channeling during the gas production stage is relatively small. Moreover, considering that the buried hill has stronger bottom water, it is predicted that the internal pressure of the gas reservoir will decrease to a certain extent at the end of gas production, especially under the conditions of rapid and strong production at the top. If the cushion gas volume is kept high, it will help to improve the gas storage pressure and the single well production at the end of gas production, and it will effectively control the bottom water coning. Since the working gas ratio of the gas storage can be about 35% of the storage capacity, the corresponding cushion gas ratio can reach about 65%. Thus, the corresponding cushion gas volume of the Guxinzhuang gas storage facility is 44.1
108 m3.

Operation Cycle The main purpose of the Suqiao gas storage facilities is to meet the demands of the gas consumption in Beijing, but it also takes into account the gas consumption in Tianjin, Hebei, and other places. Therefore, the operation cycle of the gas storage facilities mainly depends on the gas consumption in Beijing. From November 15 to March 14 of the next year, the period in which buildings in Beijing need to be heated is 120 days. The period from April to October every year is the gas injection stage, when part of the remaining gas from the No. 2 Shaanxi-Beijing line is injected into the underground gas storage for about 200 days. Considering the physical properties and heterogeneity of the reservoir, to extend the equilibrium period appropriately, the operation cycle of the gas storages was determined as follows: (a) Gas production period: November 15 to March 14, 120 days in total (b) Gas injection period: April 1 to October 17, 200 days in total (c) Gas supply stop period: March 15 to March 31 in spring, 17 days in total; and October 18 to November 14 in autumn, 28 days in total

Design Scheme When deploying the gas injection and production wells in the gas storage facility, the wells should be deployed in the fractured areas in the high part of the buried hill. However, the gas can be injected from the top of the reservoir to achieve vertical displacement from the top to the bottom. This injection mode is mainly used to ensure the full play of the gravity effect and to prevent or slow down the gas channeling phenomenon. It can also avoid serious oil and water coning when a gas well is produced with a high flow rate. In addition, it can fully consider the heterogeneity of the reservoir and helps to evenly deploy wells in the areas with a well-developed reservoir, so as to ensure the maximum utilization of the reservoir’s capacity resources in a short time. Thirty-nine production wells were designed as

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Table 1 Main design parameters of the Suqiao gas storage group

Gas storage name Su 1 Su 20 Su 4 Su 49 Guxinzhuang Total

Gas storage capacity (108 m3) 6.3 1.9 35.0 14.6 9.6 67.4

Working gas volume (108 m3) 2.0 0.7 12.1 4.5 4.0 23.3

Upper pressure limit (MPa) 41.2 35.7 28 48 34

Lower pressure limit (MPa) 25 18.5 48 29 25

Daily average gas injection (104 m3) 100 36 605 225 200 1166

Daily average gas production (104 m3) 167 60 1008 375 333 1943

injection and production wells, including 15 new horizontal wells, 12 directional wells, and 12 old wells used for gas production. There were also 16 monitoring wells, with a daily average gas injection of 1166
104 m3 and a daily average gas production of 1935
104 m3 (Table 1).

Drilling and Completion Wellbore Structure Two types of wells (horizontal and directional) were used for the new wells in the Suqiao gas storage group. Figures 7 and 8 show the wellbore structures. For directional wells, as Φ406.4 mm casing was used for the first spud, a Φ273.1 mm casing for the second spud, a Φ177.8 mm liner for the third spud, and a Φ114.3 mm liner + a high strength screen with a Φ177.8 mm tie-back air-sealing casing were used for the fourth spud. For the horizontal wells, a Φ508 mm casing was used for the first spud, a Φ339.7 mm casing for the second spud, a Φ244.5 mm technical casing for the third spud, and a Φ177.8 mm air-sealing casing + Φ168.3 mm high strength screen with Φ177.8 mm tie-back air-sealing casing was used for the fourth spud. Drilling Fluid System For the Su 1, Su 4, Su 49, and Guxinzhuang carbonate reservoirs, the first spud uses bentonite drilling fluid, the second spud uses polymer drilling fluid, the third spud uses polyamine MMH polysulfonate drilling fluid, and the fourth spud uses solidfree drilling fluid. For the Su 20 sandstone reservoir, the first spud uses bentonite drilling fluid, the second spud uses polymer drilling fluid above 1602 m and polysulfonate drilling fluid below 1602 m, the third spud uses MMH polysulfonate drilling fluid, and the fourth spud uses polyamine organic salt MMH polysulfonate drilling fluid. Oil Tube (a) In the southern zone of the Su 1 and Su 20 gas storage facilities, the horizontal wells use 3-inch oil tube, and the old wells use 2-inch oil tube to the produce gas.

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Fig. 7 Wellbore structure of a directional well

(b) In the Su 4 and Su 49 gas storage facilities, the horizontal wells use 4-inch oil tube, and the directional wells use 3-inch oil tube. (c) In the Guxinzhuang gas storage facility, the horizontal wells use 4-inch oil tube, and the old wells use 2-inch oil tube to produce the gas. (d) Old well treatment: There are 35 old wells in the Suqiao gas storage group, 20 of which are utilized and 15 of which are plugged.

Surface Engineering The surface engineering of the Suqiao gas storage group mainly includes a gas storage gathering and transmission system, a gas gathering and injection station, a two-way gas transmission pipeline, and the control center for the gas storage in the Huabei Oilfield (Fig. 9). The gas injection scale is 1300
104 m3/d, and the gas production scale is 2100
104 m3/d. The injection, production, and metering pipelines of a single well on the surface of the gas storage facility were installed together, while the gas injection main line

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Fig. 8 Wellbore structure of a horizontal well

and the gas production main line were installed independently. During the gas production period, the mixed gas-liquid transportation and injecting methanol technology was used in the initial stage of well opening. A corrosion inhibitor injection device is set at the wellhead to prevent corrosion by hydrogen sulfide and carbon dioxide. The J-T valve throttling refrigeration + glycol injection antifreeze process is used for dew point control and the low-pressure treatment of hydrocarbon water in the gathering and injection station. The two-stage flash vaporization + distillation stabilization process is used for the condensate. The stabilized condensate is loaded for export sales. 1. Build 13 new injection-production well sites. Build 21.04 km of new single well injection-production pipeline. Build 59.45 km of gas production pipeline from the new well sites to the gathering-injection station. Build 59.45 km of gas injection pipeline from the gathering-injection station to the well sites. Build 21.64 km of the pipeline for injecting the corrosion inhibitor.

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Fig. 9 Diagram of the surface engineering layout

2. Build one gathering-injection station, including three sets of control devices for the hydrocarbon water dew point (700
104 m3/d); 10 electric-driven reciprocating gas injection compressors with a single unit displacement of 115
104 m3/d and a motor power of 3500–4500 kW; 2 electric-driven reciprocating gas injection compressors with a single unit displacement of 110
104 m3/d and a motor power of 4000 kW; 1 low-pressure gas processing device (30
104 m3/d); 1 condensate stabilization device with a capacity of 1200 t/d; 1 condensate stabilization device with a capacity of 600 t/d; 1 glycol regeneration device (2200 kg/h); 1 light hydrocarbon storing and loading device (270 t/d); 1 sewage reinjection device (2400 m3/d); and 1 transforming station (110/35/10 kV). 3. Build 16.25 km of two-way gas transport pipeline from the Bazhou offtake station to the Suqiao gathering-injection station. 4. Build one sewage reinjection pipeline (14.2 km long). 5. Build two circuits with a 110 kV power supply line (33.6 km long) and a 12-core optical communication cable (110.5 km long). 6. Build a new public system supporting engineering, such as water supply and drainage, firefighting, power supply and distribution, communication, automatic instrument control, thermal engineering and HVAC, general drawing, and roads.

Brief Introduction to the Cyclic Operation The Suqiao gas storage group was put into operation in 2013. At present, two gas storage facilities (Su1 and Su 4) are in operation. By the end of gas injection in October 2019, the cumulative gas injection was 34.99
108 m3, the cumulative gas

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Fig. 10 Injection-production curve of the Suqiao gas storage group

Fig. 11 Inventory and utilized capacity rate of the Suqiao gas storage group

production was 13.85
108 m3, the maximum daily gas injection was 542
104 m3, and the maximum daily gas production was 541
104 m3. The Suqiao gas storage group was mainly reconstructed from carbonate gas reservoirs with strong bottom water. At present, the group has undergone seven episodes of injections and six episodes of production (Fig. 10). The inventory and utilized capacity rate of the gas storages are increasing every year, and the peak

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shaving capacity is gradually increasing. By the end of gas injection in October 2019, the inventory had increased to 60.2
108 m3, and the utilized capacity rate was 92% (Fig. 11). The overall capacity trend of the gas storages is better. Due to the development of high-angle fractures and strong bottom-water energy in the reservoir and the strong injection and production characteristics of the gas reservoir, upward channeling along the high-angle fractures during the gas storage production stage easily occurs in the formations. Then, the gas wells are flooded, causing serious harm to the movable gas-bearing pore volume of the gas storage facilities. For this type of reservoir, close attention should be paid to the water production of the gas wells, the productivity testing of the gas wells and analysis of the produced fluids should be strengthened during the gas production period, the pressure relief of the producing gas wells should be enhanced, and the reasonable gas well productivity should be investigated.

Conclusion The Suqiao storage group, with a burial depth of close to 5000 m, consists of five reservoirs: the Su1, Su4, Su49, Su20, and Guxinzhuang reservoirs. In the process of building the storage group, we made full use of the trap dynamic sealing property evaluation technology under complex geological conditions, the partitioning evaluation technology of the storage capacity parameters, the optimization operation technology of the injection and production of fractured, sandstone reservoirs, the drilling and completion technology of super-deep, low-pressure reservoirs, and the reservoir protection technology to optimize the geological scheme and the engineering scheme design.

6

Jing 58 Underground Gas Storage Group Reconstructed from a Sandstone Oil Reservoir with a Gas Cap Xinhua Ma, Kai Zhao, and Chun Li

Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geological Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas Reservoir Development Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Storage Building Scheme . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cyclic Injection and Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

122 122 135 142 152 155

Abstract

The Jing 58 Underground Gas Storage Group is composed of three different types of underground gas storages, including Jing 58, Yong 22, and Jing 51. The Jing 58 Underground Gas Storage was the first underground gas storage to be reconstructed from a sandstone oil reservoir with a gas cap in China. The Yong 22 Underground Gas Storage was reconstructed from a condensate gas reservoir, and the Jing 51 Underground Gas Storage was reconstructed from a depleted constant-volume gas reservoir. Their construction designs and engineering were performed by applying their comprehensive geological evaluations, the storage capacity parameter design optimization for reservoirs with complex fluids, and the drilling and completion techniques used for complex fault blocks containing different types of underground gas storage. They were all put into production in 2020 and have been playing an important role in guaranteeing winter peak shaving and gas supply in the Beijing, Tianjin, and Hebei areas. The Jing 58 Underground Gas Storage Group is located about 70 km south of Beijing, in

X. Ma (*) · K. Zhao · C. Li Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China e-mail: [email protected]; [email protected]; [email protected]; [email protected]; [email protected] © Petroleum Industry Press 2022 X. Ma (ed.), Handbook of Underground Gas Storages and Technology in China, https://doi.org/10.1007/978-981-33-4734-2_13

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Langfang City, Yongqing County, Hebei Province. As the support facility of the Shaanxi-Beijing Gas Pipeline System, it is connected to the first, second, and third Shaanxi-Beijing Gas Pipelines via the Yongqing Offtake Station, and it mainly accommodates winter peak shaving and emergency gas supply for the downstream users of the Shaanxi-Beijing Gas Pipeline system. Keywords

Jing 58 storage · Multilayer sandstone · Oil ring reservoir · Sulfides · Peakshaving for Beijing

Introduction Many years of practice have shown that it is very difficult to reconstruct a multilayer reservoir containing oil, gas, and water because of the complex nature of the oil and gas flow and the uneven gas diffusion in a longitudinal multilayer reservoir. The Jing 58 reservoir is even more complex because it consists of three fault blocks and contains hydrogen sulfide gas, which further complicates the construction of the reservoir and the subsequent aboveground handling of the gas. This chapter introduces the geological background, the history of the exploration and development, the design of the reservoir construction scheme, the drilling and surface engineering, and the operation of the gas storage. The study of the Jing 58 reservoir provides a reference for similar gas storage operations in the future.

Geological Background Stratigraphic Characteristics The Jing 58 Underground Gas Storage Group is geologically located in the Hexiwu Structural Belt in the Huabei Oilfield. The Jing 58 Underground Gas Storage was reconstructed from a depleted gas-cap reservoir, and its reservoir building horizons mainly include sand bodies I–IV in the upper Es4 (Fig. 1). The Yong 22 Underground Gas Storage was reconstructed from a sulfur-bearing condensate gas reservoir with an oil rim and bottom water. It is in the production test stage, and its reservoir building horizons mainly include the Ordovician Fengfeng Formation and the Upper Majiagou Formation in the buried hill. The Jing 51 Underground Gas Storage was reconstructed from a depleted gas reservoir, and its reservoir building horizons mainly include gas bearing formations I–III in the lower Es4. In the 250–300 m interval at the top of Es4 in the Jing 58 fault block, the sandstone is developed in a concentrated area, and its hydrocarbon distribution is the most concentrated. Its distribution is relatively stable throughout the Hexiwu Structural Belt. According to the degree of control of the vertical correlation marker, the lithological combination, the oil layer distribution, the electrical characteristics, the oil bearing formation division principle, the third-order cycle, the formation

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Jing 58 Underground Gas Storage Group Reconstructed from a Sandstone Oil. . .

Fig. 1 Composite stratigraphic column for the Jing 58 fault block

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thickness, and the distribution situations of the stable mudstone barriers, the main oil bearing target layer in the Jing 58 fault block, i.e., the upper Es4, can be divided into three oil bearing formations. In most of the wells, oil bearing formations I and II are penetrated and oil bearing formation III is not penetrated (Fig. 1). Oil bearing formations I and II in the main oil and gas bearing interval in the Jing 58 fault block are completely divided into four sand bodies, including three sand bodies in oil formation I and one sand body in oil formation II. The Ordovician strata in the buried hill in the Yong 22 Underground Gas Storage is overlain by Quaternary, Tertiary, and Permo-Carboniferous strata, and the apparent thickness of the drilled formations is about 3000 m. Among them, the PermoCarboniferous is the cap rock of the buried hill, and the Ordovician is the reservoir (Fig. 2). The lithology of the Fengfeng Formation consists of brownish-gray limestone and marl in the upper part and dolomite and thick marl in the lower part. The lithology of the upper Majiagou Formation consists of brownish-gray micrite in the upper part, microlaminated dolomite and argillaceous limestone in the middle part, brownish-gray thick limestone in the lower part, and marl at the bottom. The lithology of the lower Majiagou Formation mainly consists of gray and brownishgray limestone interbedded with thin dolomite, and marl at the bottom.

Fig. 2 Composite stratigraphic column for the Yong 22 fault block

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The drilled formations in well Jing 51 include the Quaternary Pingyuan Formation, the Neogene Minghuazhen Formation, and the Paleogene upper, middle, and lower Es4 and partial Kongdian Formation (Fig. 3). Due to crustal arching and denudation, the Neogene Guantao and Dongying formations and the Paleogene Es1, Es2, Es3, and partial Es4 are absent between the Neogene and Paleogene strata, which are separated by an angular unconformity.

Structural Characteristics The Jing 58 fault block is located in the southern end of the Hexiwu Structural Belt. Due to further cutting by faults, a series of NW down-dipping faulted noses of a monoclinal fault block have formed. The Jing 58 fault block is a hydrocarbon bearing horst structure controlled and supported by two main faults (the West Jing 58 Fault and the Liuqiying Fault). Its structural high is distributed along the edge of the Liuqiying Fault, with a burial depth of 1750 m. The closure is 200 m, and the trap area is 1.15 km2. The Jing 58 fault block is internally cut into five small fault blocks of different sizes by six first-order minor faults (Fig. 4). The Yong 22 fault block is a faulted horst between the Liuqiying Fault and the North Buried Hill Fault. The well Yong 22 buried hill is located in the upthrown side of the Liuqiying Fault. It is bounded by the Liuqiying Fault to the east and the south, it is adjacent to the Langgu Sag to the north, and it is separated from the Buried Hill Yong 9 by a fault to the west. Its structural form is a faulted horst supported by the Liuqiying Fault and the North Buried Hill Fault. This faulted horst is cut in the middle by the NE fault to the west of well Yong 23, and thus, the buried hill is cut into two parts, i.e., the well Yong 22 buried hill and the well Yong 23 buried hill. Four faults are completely developed around and inside the Yong 22 buried hill (Fig. 5). The Jing 51 fault block is regionally located in the southern end of the Hexiwu Structural Belt, in the Langgu Sag. It is a secondary gas-bearing block in wells Yong 8–Jing 51 with a wide and gentle faulted nose, which is dominated by the Banjiehe Fault and is cut by other faults. The Jing 51 fault block is a trapezoid shaped faulted horst controlled by four faults. The structural high is close to well Jing 51 in the northeast, with a burial depth of 1540 m. The trap area is 0.3 km2. The formation has a NE strike and dips 8–12° to the NW (Fig. 6). Sealing Conditions There is a special lithological section (calcareous shale and limy dolomite) that is about 60 m thick at the bottom of Es3 in the Jing 58 fault block, which directly overlies the oil and gas reservoir and acts as an ideal cap rock with a good sealing capacity. Six faults are completely developed in the fault block. Two main faults, i.e., the Liuqiying Fault and the West Jing 58 Fault, have thicker fault surface gouges and were formed due to formation compaction. Their diagenesis is good, and the proportion of impermeable mudstone within the range of the fault slip is up to 100%. Thus, these faults have a good lateral sealing capacity for the oil and gas traps in the Jing 58 fault block. Six minor faults inside the fault block have shorter throws and the sandstone on both sides of the faults connects inside the formation, so their

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Fig. 3 Composite stratigraphic column for the Jing 51 fault block

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Fig. 4 Surface structure of Es4 in southern Hexiwu

sealing capacity is not obvious, and they act as the main channels for liquid during the development.

Cap Rock The statistics of the drilling, well logging, and mud logging data show that the interval from the bottom of the Minghuazhen Formation to the top of the upper Es4 is almost completely composed of mudstone, except for the thin argillaceous siltstone and fine sandstone interbeds at the top of the middle Es3, which have a cumulative thickness of less than 20 m. The net/gross ratio is less than 5%, and the rest of the formation is mainly composed of gray and dark-gray pure mudstone. As for their electrical characteristics, the SP (spontaneous) curve is flat and the resistivity curve is low and flat. There is a special lithological section (calcareous shale and limy dolomite) that is about 60 m thick at the bottom of Es3, which directly overlies the oil and gas reservoir and acts as an ideal cap rock with a good sealing capacity. The statistical data for the wells drilled in the main part of the Jing 58 fault block show that the middle and lower Es3 are generally 600–700 m thick. They are advantageous due to their good sealing capacity, stable distribution, pure lithology, and large

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Fig. 5 Surface structure of the Ordovician strata in the Yong 22 buried hill

Fig. 6 Surface structure of the lower Es4 in the Jing 51 fault block

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Table 1 Statistical cap rock thickness in the Jing 58 fault block Well No. 58 58-1 58-2 58-3 58-4 58-5 58-6 58-7

Es3 thickness (m) 581 679 656 625 650 570 638 714

Well No. 58-8 58-9 58-10 58-11 58-12 58-13 58-14 58-15

Es3 thickness (m) 716 673 700 661 666 610 580 655

Well No. 58-16 58-17 58-18 58-19 58-20 58-21 58-22 58-24

Es3 thickness (m) 678 688 720 735 695 673 718 690

Well No. 58-26 58-27 58-31 58-32 58-33 58-39 58-42

Es3 thickness (m) 665 642 664 646 660 701 674

thickness. The mudstone is tight and has better consolidation and diagenesis, so the sealing capacity of the mudstone at the top of the cap rock is better (Table 1). The Permo-Carboniferous cap rock in the Yong 22 buried hill is 300 m thick, it is composed of mudstone and coal, and it is partially interbedded with tight sandstone. Only one permeable sandstone layer is developed locally in the middle-lower part, and it is 110 m from the top of the buried hill. As for the main electrical characteristics of the Permo-Carboniferous, the SP curve is flat with a local negative amplitude anomaly in the middle part, and the resistivity curve has high values, which is caused by the coal bed. Thus, the cap rock has a good performance. In addition, it is separated from the underlying Ordovician strata of the buried hill by a parallel unconformity, which further enhances the sealing capacity of the buried hill. The analysis of the geological conditions indicates that the sealing to the buried hill is mainly due to the mudstone layer at a depth of 110 m. The cap rock in the Jing 51 fault block is the middle Es4, which has a large sedimentary thickness. It was formed in a shore-shallow lacustrine environment and mainly composed of fine grained mudstone, occasionally interbedded with silty strip. In particular, the lower part of the middle Es4, which is in direct contact with the lower Es4, is dominated by 60–80 m of gray pure mudstone, giving it a better sealing capacity as a cap rock. According to the actual sample measurements provided by the China University of Petroleum, the displacement pressure of the mudstone in the Langgu Sag is 0.714–2.83 MPa. Therefore, it is classified as a goodexcellent mudstone cap rock (Table 2). Faults The two main fault systems in the Jing 58 fault block are characterized by early formation, a long active period, multiple cut horizons, and long-term inherited activity. They are tensile-shear faults that control the sedimentary stratigraphy, with throws of greater than 300 m. Their matched secondary minor faults are tensile feather faults, which were formed in the late activity stage of the main fault systems. The throws of the minor faults are smaller, generally between 20 m and 50 m. These minor faults disappear in the Es3 sandstone or intersect with the main faults. Two

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Table 2 Classification and evaluation of the mudstone cap rock Classification I

Displacement pressure (MPa) >2.0

Sealing capacity Excellent

Cap rock thickness (m) >200–400

II

2.0–0.5

Good

100–200

III

0.5–0.1

Fair

1000 m. A regionally distributed 70–100 m thick silty mudstone is classified as a medium caprock, which can seal a 500–1000 m air column. The muddy caprock in the study area is pure, is widely distributed, and is generally >200 m thick, suggesting a good sealing ability. ⑤ The reduction of the temperature and pressure can improve the sealing ability of the caprock. In general, the initial pressure and temperature of natural gas reservoirs are the highest. As the exploitation initiates, the temperature and pressure of the gas reservoirs decrease, inevitably resulting in a decrease in the temperature and pressure of the caprock. Consequently, the surface tension of the gas and water within the caprock increases. The increased capillary force improves the capping ability. The initial pressure of the reservoir in the Shuang 6 block was 24.85 MPa,

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and the initial temperature was 89 °C. This area has been developed in terms of natural energy. The formation pressure has now dropped to less than 10 MPa, which is more conducive to sealing a gas column. Therefore, based on the comprehensive analyses of the microscopic petrophysical properties and the breakthrough pressure, the caprock directly overlying the reservoir has a good microscopic sealing ability.

Sealing Ability of Fault The Shuangtaizi long-axial anticline is divided into five third-order fault blocks (or blocks) by a group of nearly E-W oriented faults. The Shuang 6 block is one of these fault blocks. It is located in the structural high of the second-order anticline structural belt. The fault activity mainly occurred during the deposition of the Dongying Formation, so it did not affect the deposition of the Xinglongtai reservoir. However, the fault active was contemporaneous with the peak of hydrocarbon migration and accumulation in the third member of the Shahejie Formation, which is the main source rock in the area. Therefore, the fault activity provided a hydrocarbon migration pathway, resulting in the hydrocarbon accumulation in the anticline. The closure of the faults isolated the oil-gas-water system. The hydrocarbons are present in the isolated traps in each fault block, which are also the general characteristics of the gas reservoir in the Liaohe Basin. The maximum fault throw of the Shuang 607 boundary fault in the southern Shuang 67 block is about 200 m. The oil-gas and oil-water contacts in the southern Shuang 7 block are lower than those in the Shuang 67 block, indicating two different pressures and oil-gas-water systems. The lateral contact between the mudstone and the hydrocarbon bed in the Shuang 67 block suggests that the fault is closed. The Shuang 30-26 fault in the northern Shuang 6 block has a fault throw of 70– 150 m. The Shuang 6 block contains a gas cap, an oil ring, and an edge water trap. The Shuang 55 and Shuang 56 blocks contain bottom-water oil traps, and their oil-water contacts are different from that in the Shuang 6 block, indicating independent oil, gas, and water systems. The production data also confirm that these blocks do not share the same pressure system, indicating that the fault is sealed. The Shuang 34-12 fault is the western boundary fault of the Shuang 6 and Shuang 67 blocks. Although the fault throw is not large (about 50 m), the gas-oil-water contacts on either side of the fault are different. Thus, the fault is considered to be a closed fault. Under the initial conditions, the Shuang 6 and Shuang 67 blocks have a unified gas-oil contact (about 2450 m) and an oil-water contact at 2500 to 2540 m. The contacts in the Shuang 6 block are slightly lower than those in the Shuang 67 block. According to the production data, the pressure drops in the two blocks were similar during exploitation (Fig. 3), and thus, the Shuang 6 and 67 blocks are considered to be one large gas reservoir.

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Fig. 3 Pressure variation curves for the Shuang 6, Shuang 67, and Shuang 56 blocks

Depositional Characteristics The Shuangtaizi structure is located in the central deep depression near the western slope of the sag. The Xinglongtai reservoir in the Shuangtaizi oilfield is part of the Qihuan double fan delta. The provenance of the sandstone reservoir is the northern and northwestern slopes. The detrital material was carried by strong seasonal currents and was transported a short distance along the margin of a lake, and then it was rapidly deposited in the lake, forming a gentle-slope type Qihuan double fan delta. The Shuang 6 block is located in the fan delta front.

Characteristics of the Sedimentary Facies The presence of a Camarocypris elliptica-Cypria gargara-Phacocypris-Ilyocypris assembly, Conicoidium granorugosum-Pediastrum assembly, and a Quercusdominated spore-pollen assembly in the dark gray mudstone reflects a warm and humid depositional environment within a shallow lake. The sedimentary structures, such as parallel bedding, tabular cross bedding, trough cross bedding, and scouring surfaces, are well developed and indicate fluvial channel deposition. The sandstone reservoir is coarse-grained and poorly sorted, and it has a highly variable mineral content. The textural and compositional maturities of the reservoir are low, suggesting rapid deposition. The grain size distribution within the reservoir suggests strong hydrodynamic conditions and traction flow deposition, with strong bottom disturbance. Figures 4 and 5 show the grain size cumulative probability curve and C-M diagram, respectively.

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Fig. 4 Grain size cumulative probability curve

Fig. 5 C-M diagram

The presence of dark gray mudstone, calcareous shale, dolomitic micrite, and thin horizontal lamina reflects a stagnant and stable lacustrine environment.

Sedimentary Facies Based on the comprehensive analyses of the depositional environment and the sedimentary textures and structures, it is concluded that the Xinglongtai reservoir in the Shuangtaizi oilfield is a fan delta deposited on a relatively steep slope, near the

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sediment source, under strong hydrodynamic conditions. The Shuang 6 block is located in the fan delta front. The fan delta front sedimentary facies can be further divided into several subfacies: braided distributary channels, an interdistributary bay, a channel mouth bar, and a thin sandstone layer in the profan delta.

Characteristics of Sedimentary Facies in the Shuang 6 Block The sedimentary facies of the Xinglongtai reservoir in this area reflect multiple depositional cycles under a background of lake expansion. The lower part of the Xinglongtai reservoir is coarse-grained, the single beds are thick, and it is dominated by distributary channel deposits. The upper part is finer-grained, and gradually grades into channel-mouth bar and prodelta deposits. Each oil-bearing sandstone unit exhibits similar characteristics, and they form a fining-upward second-order cycle. The Xinglongtai reservoir in the Shuang 6 block is dominated by braided distributary channels and channel-mouth bar deposits. The relationship between the deposition and structure is good, and the structural lows in the east are mostly the tip of the sandstone bed or the profundal lake deposits.

Reservoir Characteristics Lithological and Petrophysical Characteristics The Xinglongtai reservoir mainly consists of gravelly medium-coarse sandstone, unequal-sized sandstone, and minor fine sandstone and siltstone. The quartz content is 25–50%, with an average of 38.2%. The feldspar content is relatively high, 30–60%, with an average of 44.4%. The lithic content is 5–60%, with an average of 17.4%. Textual maturity is 0.62. Consequently, based on the ternary diagram for sandstone classification, the reservoir is mainly lithic arkose, feldspathic litharenite, and minormixed sandstone, reflecting rapid near-source deposition (Fig. 6). The reservoir consists of muddy and calcareous cements, which are mainly porefilling (41–50%), some contact type, and minor amounts of poikilotopic type. The grain-sorting of the reservoir is medium to poor, and the average sorting coefficient is 1.7. The grain roundness is poor and is mainly subrounded and subangular. The textural maturity is also low. The matrix of the reservoir is mainly mud and carbonate, with average contents of 6.4% and 7.9%, respectively. The muddy matrix contains two types of minerals: depositional and diagenetic clay minerals. The diagenetic clay is mainly composed of authigenic kaolinite, which is present as vermicular or book-like aggregates distributed on the grain surfaces. The authigenic illite has a film-like texture. The carbonate cement commonly occurs with the mud matrix in the form of intergranular cementation. It is mainly generated by early diagenetic microcrystalline siderite and late diagenetic carbonate (calcite and dolomite). The composition of the clay mineral is mixed illite, kaolinite, and smectite with relative contents of 56.2%, 36.8%, and 7.0%, respectively. According to the core analysis, the porosity of the reservoir in the Shuang 6 block is 5–6.8%, with an average of 17.3%. The average permeability is 224 mD. The average median grain size is 0.44 mm. The average sorting coefficient is 1.47.

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Fig. 6 Ternary diagram for sandstone classification

The petrophysical properties of the reservoir in the Shuang 6 block are as follows: ① The petrophysical distribution of the reservoir is controlled by the sandstone distribution and the sedimentary facies. The high petrophysical value areas are mostly distributed in the area where the sandstone is concentrated, with a NW-SE or N-S orientation. ② The channel-mouth bar deposits have the best petrophysical properties, with an average porosity of 23.4% and an average permeability of 427
103 μm2. Although the distributary channel deposits are coarse-grained and thick, they have poor sorting due to unstable depositional conditions. Consequently, their petrophysical properties vary significantly. Their average porosity is 17.5%, and their average permeability is 228
103 μm2. Due to their fine grain size and high cement content, the prodelta deposits are fine-grained, resulting in poor physical properties, with an average porosity of 17.2% and an average permeability of 184
103 μm2. ③ The lithology has a certain influence on the petrophysical properties of the reservoir, and it is generally positively correlated with grain size and negatively correlated with mud content.

Macroscopic Distribution Characteristics The sandstone is best developed adjacent to the source area, and it thins toward the southeast. The maximum thickness of the Xinglongtai reservoir is 169.0 m (in well

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Shuang 32-16) and the minimum thickness is 35.3 m (in well Shuang 152). The reservoir thickness commonly ranges from 100 to 140 m. The thicknesses of the Xinglongtai reservoir and of each oil unit gradually decrease from NW to SE. Among them, oil unit III is the best developed, and the thickness of each sandstone unit within it is 40–120 m. Oil unit II is 10–40 m, and oil unit I is the thinnest (2–10 m). The isopach maps of the individual oil and sandstone units show that the sandstone distribution is highly directional, and the thickest areas have a belt-like geometry, trending NW-SE or N-S. The thickness of the sandstone beds in each sandstone unit varies significantly. The thickest sandstone bed is 15–25 m, and the thinnest is less than 2 m. Generally, in the Xinglongtai reservoir, the lower part of the sedimentary cycle and its oil units are very thick and have better lateral continuity, whereas the upper part of the sedimentary cycle and its oil units are thinner, have a smaller distribution area, and poorer lateral continuity. In the vertical direction, sandstone beds III24–III59 are the best developed, followed by beds II35–II36. Beds I2, II11, and II12 are poorly developed.

Heterogeneous Characteristics Planar heterogeneity: The upper part of the sedimentary cycle has a stronger planar heterogeneity than the lower part, which is manifested by the distribution of the sandstone. The sandstone in the upper part has poor lateral continuity. The channels are separated by mudstone pinch-outs (channel widths of 200–400 m), causing planar heterogeneity. In addition, the variations in the petrophysical properties along the orientation of the sandstone are smaller than those perpendicular to the orientation of the sandstone. Interlayer heterogeneity: The Xinglongtai oil reservoir is composed of vertically stacked sandstone beds deposited in various sedimentary facies. The interlayer heterogeneity is strong. The average stratification coefficient is 7.5–10.1/100 m. The permeability difference between layers is normally greater than 20 and is as high as 65. Intralayer heterogeneity: The reservoirs in this area are mainly composed of a fining-upward cycle, some composite cycles, and minor coarsening-upward cycles or cycles with no clear grain size trend. The average heterogeneity coefficient of the different cycles is 2.43–7.56, and the variation coefficient is 0.92–1.52, indicating strong intralayer heterogeneity. The cycles with no clear grain size trend are slightly more homogenous than the other cycles.

Development of Compartments and Interlayers Development of Compartments The compartment within the Shuang 6 block consists of dark-gray or brownish-gray mudstone, calcareous shale, and minor dolomitic micrite and silty mudstone. In this block, the Xinglongtai oil reservoir is composed of a fan delta deposit. The reservoir and the oil and sandstone units within it are variable in thickness and distribution,

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exhibiting an overall fining-ward cycle. The development of the compartment varies significantly in the vertical direction. Compartments Between the Oil Units In this area, the distribution of the compartments between oil units I, II, and III is relatively stable, and the drilling ratio of the compartments in the study area is 100%. The thickness of the compartment between the Xing II and III oil units ranges from 5 to 15 m, with an average of 8.9 m and a maximum of 35.6 m (well Shuang 152). The number of wells with compartments thicker than 8 m accounts for 54.4%. The thickness of the compartment between the Xing I and II oil units ranges from 5 to 20 m, with an average of 12.3 m and a maximum of 29.4 m. The number of wells with compartments thicker than 8 m accounts for 63%. In general, the quality of the compartments between oil units is better than those between the sandstone units and beds, as the compartments between the oil units have a high stability coefficient, and a high proportion, and are more than 8 m thick (Table 7). Compartments Between the Sandstone Units The thickness of the compartments between the sandstone units is mostly 0.4– 21.0 m, with an average of 6.7 m. The drilling rate of the compartments is 59–98%, with an average of 83%. Based on the statistical analysis of the compartments between each sandstone unit and bed, the compartment between oil units I and II is better developed than the compartment between oil units II and III. The average thickness of the former compartment (ranging from 3.7 to 15.7 m, with an average of 8.9 m) is greater than that of the latter compartment (ranging from 2.7 to 12.5 m, with an average of 5.5 m). The stability coefficient of the former compartment (average 0.92) is also higher than that of the later compartment (average 0.77). The percentage of the former compartment that is thicker than 8 m (average 45.6%) is higher than that of the latter compartment (average 24.1%). The percentage of the former compartment that is less than 2 m thick (16.6%) is lower than that of the latter compartment (46.8%) (Table 7).

Development of Interlayers There are two types of interlayers in the Xinglongtai oil reservoir in the study area: the interlayers between beds (i.e., interlayers between two adjacent sandstone beds) and the interlayer within a single bed. The interlayers between two adjacent beds are impermeable layers composed of mudstone, calcareous shale, silty mudstone, and minor muddy siltstone. These interlayers were primarily formed by seasonal alterations in the hydrodynamic conditions during deposition. The Xinglongtai oil reservoir consists of fan delta deposits. Due to changes in the hydrodynamic conditions during deposition, the lower part of the reservoir has well-developed thick sandstone beds with limited interlayers, which were deposited by a relatively high-energy current, whereas the upper part of the reservoir has less-developed sandstone beds that contain more

III

III5

III4

III3

III2

III1

II3

II2

Stratigraphy Oil Sandstone unit unit I I1 I2 II II1

Average thickness (m)

15.7 12.3 9.3 8.8 5.4 3.7 7.4 8.9 8.6 7.7 3.4 3.5 3.1 2.7 4.6 3.8 12.5

Compartment thickness (m)

8.2–29.4 3.2–29.4 1.0–29.4 1.0–29.0 0.8–25.0 0.8–25.0 0.4–25.0 0.8–35.6 0.6–28.4 0.8–28.4 0.3–28.4 0.4–27.0 0.4–27.0 0.6–22.7 0.8–21.0 1.0–21.0 0.5–27.0

Bed

II11 II12 II23 II24 II35 II36 III11 III12 III23 III24 III35 III36 III47 III48 III59 III510

95.5 63.0 45.7 43.9 23.4 12.5 35.4 54.4 48.8 38.6 13.3 11.1 7.3 10.8 13.9 13.3 60.0

>8m Compartment (%)

Table 7 Statistics of the compartments in the Shuang 6 block

0 18.5 2.9 17.1 8.5 6.3 25.0 6.5 7.0 9.1 4.4 6.7 9.8 2.7 22.2 10.0 30.0

5–8 m Compartment (%) 0 18.5 40.0 29.3 34.0 35.4 27.1 13.0 9.3 20.5 11.1 22.2 19.5 27.0 19.4 30.0 0

2–5 m Compartment (%) 4.5 0 11.4 9.8 34.1 45.8 10.4 26.1 34.9 31.8 71.2 60.0 63.4 59.5 44.5 46.7 10.0

0–2 m Compartment (%)

0.95 1.0 0.97 0.98 0.83 0.75 0.98 1.0 0.79 0.82 0.73 0.80 0.71 0.59 0.78 0.70 1.0

Average stability coefficient

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Table 8 Statistics of the interlayers (between two adjacent beds) in the Shuang 6 block Bed I1 I2 II11 II12 II23 II24 II35 II36 III11 III12 III23 III24 III35 III36 III47 III48 III59 III510

Interlayer number Max Ave. Well no. 2 0.19 54 1 0.07 54 1 0.02 53 1 0.02 53 3 0.15 53 4 0.79 52 3 0.86 51 3 0.76 51 4 0.375 48 2 0.17 46 2 0.4 47 4 0.83 47 3 0.77 47 2 0.6 45 4 1.04 45 6 1.39 46 7 0.86 43 3 0.68 41

Interlayer density (%) Ave. Well no. 89.38 54 96.71 54 90.83 53 91.28 53 74.43 53 59.22 52 44.26 51 47.67 51 71.45 48 60.77 46 65.16 47 37.39 47 35.14 47 31.31 45 23.37 45 25.07 46 31.82 43 48.35 41

Interlayer frequency (layers/100 m) Ave. Well no. 1.13 54 0.52 54 0.41 53 0.24 53 0.24 53 6.4 52 7.05 51 7.27 51 4.325 48 1.98 46 4.22 47 6.81 47 7.13 47 5.79 45 5.85 45 5.85 45 5.21 43 4.22 41

interlayers. The number of interlayers in beds III24–III510 and II24–II36 is 0.6–1.39, with an average of 0.86, and the interlayer frequency is 4.22–7.27 layers/100 m, with an average of 6.2 layers/100 m (Table 8). Due to the well-developed sandstone, the interlayer density (thickness percentage) is relatively low (mostly 23.4–59.2%). The number of interlayers in the other beds is low (average 0.17), the interlayer frequency is low (average 1.6 layers/100 m), and the interlayer density is high (60.8– 96.7%, with an average of 80%). The interlayers within a single bed are impermeable beds or lamina sandwiched within a single permeable layer. This type of interlayer is commonly thin and has a limited lateral extension. It is normally an impermeable layer composed of mudstone or calcareous shale. Due to the overall coarse grain size, good petrophysical properties, and large thickness of the Xinglongtai gas-dominated reservoir in the study area, these interlayers (with acoustic values of less than 220 μs/m) are not well developed and only account for a small proportion of the reservoir thickness.

Types of Gas Reservoirs The Shuang 6 and Shuang 67 blocks contain large oil and gas-bearing areas, a thick oil and gas-bearing reservoir, and concentrated reserves, making it the most petroliferous area in the Shuangtaizi oilfield. The oil and gas reservoir is generally 30–50 m thick. The thickest hydrocarbon reservoir is 126.6 m, and it contains

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14 beds (well Shuang 31-20 has an effective thickness of 107.6 m, including 74.8 m of gas reservoir and 51.8 m of oil reservoir). The maximum effective thickness of the oil reservoir is 57.4 m (well Shuang 30-26). The hydrocarbons are concentrated in the structural highs, which form composite traps with a gas cap and bottom (edge) water. The Shuang 6 block is located in the structurally highest region, and the top of the trap is filled with gas. The maximum thickness of the gas reservoir is 106 m, and it contains15 beds (well Shuang 32-22 has an effective thickness of 93.4 m). The hydrocarbons in the Shuang 6 and Shuang 67 blocks are concentrated and continuously distributed in the reservoirs. The minimum and maximum burial depths of the hydrocarbon reservoir are 2288 m (well Shuang 33-20) and 2540 m, respectively. The thickness of the hydrocarbon reservoir is 100–200 m, with a maximum gas reservoir thickness of 144–162 m and a maximum oil reservoir thickness of 45–90 m (Table 9). These hydrocarbon reservoirs are controlled by the depositional conditions. The lower part of cycle contains well-developed sandstone, resulting in the thick and laterally continuous nature of oil units II and III. Oil unit I, which is located in the upper part of the cycle, is thin and exhibits a beltshaped distribution. The thickness of the oil and gas reservoir varies significantly in the vertical direction. The sandstone at the top of the cycle is thin, whereas the sandstone in the lower part of the cycle is thick and massive. The maximum and minimum thicknesses of the hydrocarbon reservoir are 43.2 m (bed 14 in well Shuang 31-20) and 0.6 m, respectively. The maximum thickness of the gas reservoir is 34.2 m (bed 19 in well Shuang 33-20) (Fig. 7). The Xinglongtai reservoir in the Shuang 6 and Shuang 67 blocks is characterized by massive composite reservoirs. Based on the formation mechanism, the traps are classified as roof-shaped faulted nose traps. Based on the spatial distribution of the oil, gas, and water, the traps in the Shuang 6 block are classified as traps with a gas cap, oil ring, and edge water, and the traps in the Shuang 67 block are classified as traps with a gas cap and bottom water. There is a unified oil-gas-water contact and pressure system within the fault block. Each fault block may contain variable types of traps and reservoirs, such as a trap with gas cap and bottom (edge) water, a trap with an oil cap and edge (bottom) water, a stratified oil reservoir, a pinched-out hydrocarbon reservoir, and a lithological reservoir (mainly tight sandstone). The crude oil in the Shuang 6 block has a low density, a low wax content, and a low sulfur content, indicating good quality. The density of the surface crude oil is Table 9 Oil and gas distribution Block Shuang 6 block Shuang 67 block

Trap type Gas cap, oil ring, and bottom water Gas top and bottom water

Gas range (m) 162

Gas-oil contact (m) 2450

Oil range (m) 90

Oil-water contact (m) 2540

144

2450

45

2500

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Fig. 7 Cross section of the Shuang 6 gas reservoir

0.8362–0.8611 g/cm3, and the density of the formation crude oil is 0.6349–0.6470 g/ cm3. The viscosity of the surface crude oil is 15 mPa·s at 50 °C, and the viscosity of the formation crude oil is less than 0.5 mPa·s (Tables 10 and 11). The density of the natural gas is 0.6886–0.7131, and it has a methane content of 80.14–81.9%. The density of the condensate oil is 183–289 g/m3 (Table 12). The total salinity of the formation water is greater than 9000 mg/L. The formation water contains NaHCO3 (Table 13). The formation pressure in the middle of the Xinglongtai reservoir is 23.23– 24.86 MPa, with an average of 24.27 MPa. The pressure gradient is 0.933– 1.0 MPa/100 m, with an average of 0.978 MPa/100 m. The saturation pressure is 23–24.04 MPa, with an average of 23.45 MPa. The saturation pressure difference is primarily less than 1 MPa, with an average of 0.82 MPa. The formation temperature of the Shuang 6 block is 88–90 °C, and the geothermal gradient is 3.09–3.21 °C/100 m. The Shuang 6 block is a normal temperature and pressure system.

Verification of the Reserves The Shuang 6 block includes two fault blocks: the Shuang 6 and Shuang 67 fault blocks. The main producing stratum is the Xinglongtai reservoir in the second member of the Shahejie Formation. In 1991, the class I proven oil-bearing area was 4.0 km2, and the geological reserves were 665
104 t. The gas-bearing area was 3.9 km2, and the geological reserves were 39.34
108 m3. The geological condensate oil reserves were 105
104 t. In order to determine the needs of the gas storage project, it is necessary to study the structure, reservoir, hydrocarbon distribution, and trap type and to calculate the oil and gas reserves. The calculation of the reserves is based on the vertical distribution of the oil units (the Xing I, Xing II, and Xing III) and the lateral distribution of the small fault blocks. The volume method was used and the equations are as follows:

Block Shuang 6 Shuang 67

Depth 2499.4–2540.0 2479.0–2492.4

Density (d20) (g/cm3) 0.8611 0.8362

Viscosity (at 50 °C) (mPa·S) 13.7 2.65

Properties of crude oil

Table 10 Properties of the surface crude oil in the Shuang 6 block

Freezing point (°C) 15 19

Sulfur content (%) 0.169 0.086

Asphalt+ mastic (%) 16.9 6.5

Wax content (%) 4.7 5.65

Representative Well Shuang 6 Well Shuang 62

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Block Shuang 6 Shuang 67

Formation pressure (MPa) 24.76 24.85

Saturation pressure (MPa) 23.54 23.09

Formation temperature (°C) 89 89 Bulk coefficient 1.6579 1.6331

Table 11 Properties of the formation crude oil in the Shuang 6 block Gas-oil ratio (m3/t) 243 238 Gas dissolution coefficient 0.8717 0.8479

Formation crude oil density (g/cm3) 0.6349 0.6470

Formation crude oil viscosity (mPa·S) 28.5

Fault length (km) >22.5

150–230

60–150

120–400

200–1200

80–570

Drop range (m) 200–1400

T1f4

T1f4

T3x1

T1j22

T3x

Upward T3x

S

S

S

S

S

Downward S

Disappearance

SN

SN

SN

SN

SN

Dip direction azimuth SN

Occurrence

50–55

50–60

35–45

35–45

50–60

Dip angle (°) 50–60

Reliable

Reliable

Reliable

Reliable

Reliable

Reliability Reliable

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7.47%. According to the core analysis results of 6 coring wells (i.e., wells Xiang 10, 12, 13, 14, 16, and 30), the highest connected porosity is 15.82%. Fractures: The average fracture rate of the reservoir dolomite breccia obtained using the core stripping method was up to 0.347%. The statistical results of the core fractures and caves indicate that the micro-fine fractures are extremely welldeveloped and are distributed in a network within the dolomite breccia and finesilt crystalline dolomite, and there are basically no large fractures. The average fracture density generally ranges from 5.69 to 27.97 fractures/m, and the width of the fractures is less than 0.1 cm (Table 3). Caves: The core analysis results show that the reservoir caves are also welldeveloped, with an average cave density ranging from 7.6 to 43.6 caves/m. The caves are mostly unfilled, with diameters of generally less than 0.5 cm. Due to the well-developed pores, caves, and fractures in the reservoir, its permeability is very good. According to various well test interpretation results, the permeability of well Xiang 25 is the lowest and has reached 20 mD, and the permeability of well Xiang 30 is up to 800 mD. The average permeability of the other wells is about 300 mD. In the structural plane, the permeability is high at the top and tends to decrease toward the flank. The reservoir rocks of the Xiangguosi Carboniferous gas reservoir are mainly finesilt crystalline dolomite, calcareous dolomite, and breccia dolomite. According to the Carboniferous Huanglong Formation reservoir classification table for the Xiangguosi block (Table 4), the reservoir’s pore structure mainly includes the following types. 1. Coarse pores and large throats or caves and large throats, with a low displacement pressure ( > < max qscðiÞ i¼1

673

ðunable to meet the requirements of the gas volume needed for peak shavingÞ

j > P > > : qscðiÞ ¼ QPjhðmÞ ðable to meet the requirements of the gas volume needed for peak shavingÞ i¼1

ð49Þ The constraints are 8 p2
p2wf ðiÞ ¼ AqscðiÞ þ Bq2scðiÞ > > > r ði Þ >   > > prðiÞ p0ðiÞ G P ði Þ > > ¼ 1
> > > ZrðiÞ Z0ðiÞ G ði Þ > > < 2 2 pwf ðiÞ ¼ bpwhðiÞ
aq2scðiÞ   > > > > Δ p
p OΔp max ðiÞ > r ð i Þ wf ð i Þ > > > > > qscðiÞ Pq min ðiÞ > > > : q Oq scðiÞ e ði Þ

ðFormation seepage pressure dropÞ Material balance equation Wellbore flow pressure drop Less than the gas injection capacity of compressor Less than pipe wall erosion flow rate Less than non-steady critical flow rate

ð50Þ

Solution Process of the Production Allocation Optimization The optimized production allocation operation scheme for a gas storage group can be obtained by solving the reasonable production allocation of the gas storage spaces meeting the target conditions and by using the formation seepage, the vertical wellbore pipe flow, the surface horizontal pipe flow, and the produced gas treatment unit capacity as the constraints according to the winter peak-shaving needs of the gas storage group. The basic solution process is as follows: 1. Input the relevant data for the production allocation optimization. 2. Set the priority level of peak shaving for the gas storage group. 3. Assume that the peak-shaving stage is 1 (calculated from the first peak-shaving stage). 4. If the peak-shaving stage is the actual peak-shaving operation that has taken place, there is no need for production allocation optimization (go to step 9). If it is 1, then the peak shaving calculation is required (go to step 5). 5. Assume that the peak-shaving level is 1 (calculated from the peak-shaving level 1). 6. Calculate the maximum gas production capacity of each gas storage space in this stage and at this level, and obtain the sum of the maximum gas production capacities of all of the gas storage spaces in this stage and at this level. 7. If the sum of the gas production capacity calculated in step 6 is greater than the remaining peak-shaving gas volume in this stage, the actually needed peakshaving gas production capacity of each gas storage space is recalculated according to the ratio of the maximum gas production capacity of the gas storages at this level (go to step 9). If the sum of the gas production capacity calculated in step 6 is less than the remaining peak-shaving gas volume in this stage, the calculated maximum gas production capacity of each gas storage

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space is the actually needed peak-shaving gas production capacity, and the remaining peak-shaving gas volume is calculated (go to step 8). 8. Go to step 6 to calculate the next peak-shaving level up to all of the peakshaving levels. If all of the gas storage spaces at all of the peak-shaving levels have been calculated, but the remaining peak-shaving gas volume is still not 0, then in this stage, the gas storage group cannot meet the peak-shaving requirements. Output the relevant information and enter it in step 9. 9. Go to step 4 to calculate the peak shaving in the next stage until the peakshaving stage is ended. 10. Output the calculation results.

Optimized Production Allocation Scheme The formation seepage equation and the vertical wellbore pipe flow equation for the gas injection and production wells are obtained through dynamic analysis and calculation using the gas reservoir engineering method according to the winter peak-shaving needs of the gas storage group. In addition, the optimized production allocation operation scheme for the gas storage group can be obtained using the above-established production allocation optimization method for the gas storage group taking the dew point unit treatment capacity, the wellbore erosion flow rate, and the critical drawdown pressure as constraints in order to provide a basis for the gas production operation of the gas storage group.

Gas Reservoir Engineering Method for Optimizing the Injection Allocation Basic Principle The optimization of the injection allocation of a gas storage facility is as follows. By taking multiple adjacent gas storage spaces as a whole and by using both the independent and interconnected formation seepage, wellbore flow, pipeline network pressure, and the capacity of the surface compressors and dew point units of the gas storage spaces as constraints, the optimal gas injection operation scheme for meeting the requirements of the gas injection volume plan of the gas storage group can be developed based on the theory of the inventory analysis of a single gas storage space, thus achieving the overall optimization of the injection allocation of the gas storage group, further improving its overall operating efficiency, and reducing the gas storage operation costs. Figure 1 shows the basic theory of the optimization of the injection allocation of a gas storage group. Importance is attached to the basic principles, objective functions, constraints, and basic solution process of the injection allocation optimization. Assumptions Reasonable coordination and allocation are performed between gas storage spaces based on the relevant conditions of their reasonable allocation and the surplus gas injection volume of the pipeline system and the operational state of the gas storage

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spaces. The following are the basic principles formulated for optimizing the injection allocation of a gas storage group through analysis, research, and summarization. 1. The priority level of the gas injection operation of gas storage spaces mainly includes two levels: the preferential gas injection for gas storage in the capacity expansion stage and the secondary preferential gas injection for gas storage under stable operation. 2. The optimization of the gas injection operation mode of gas storage spaces mainly includes the following modes: preferential gas injection into the gas wells in the midhigh parts in the early stage; suspended gas injection and intermittent gas injection into the marginal gas wells in the midlate stage; and the stable operation of the gas storage spaces during the gas injection period in order to ensure the implementation of gas injection tasks and to meet the requirements of the monthly gas injection plan. In the process of optimizing the injection allocation of gas storage facilities, it is necessary to adjust and improve the basic principles for optimizing the injection allocation of the gas storage group according to the dynamic operation state of the gas storage spaces, their injection and production conditions, and their different gas injection operation modes, so that the established technology and methods of optimizing the injection allocation are more scientific and reasonable, thereby truly achieving the purpose of optimizing the gas injection operation of the gas storage group, improving its operation efficiency, and meeting the actual field operation needs.

Mathematical Model for Injection Allocation Optimization Target Conditions for Injection Allocation Optimization It is necessary to seek the optimal gas injection operation scheme that meets the pipeline system operation requirements and improves the operation efficiency of the gas storage facilities while comprehensively considering the surplus gas volume provided by the pipeline system and the gas injection capacity of the gas storage facilities in order to achieve the injection allocation optimization objective. The target conditions for injection allocation optimization include the gas injection operation scheme for the gas storage spaces developed to meet the monthly gas injection plan of the gas storage group (gas injection capacity of greater than the planned gas injection volume) and the gas injection operation scheme for the gas storage spaces developed to meet the monthly maximum gas injection capacity of the gas storage group (gas injection capacity of less than the planned gas injection volume). Constraints for Injection Allocation Optimization During the gas injection operation of a gas storage facility, it is necessary to comprehensively consider all of the components of the facility, such as the underground and surface systems, as a whole. Therefore, the gas injection operation of a

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gas storage facility is limited by the formation seepage, the vertical wellbore pipe flow, the surface horizontal pipe flow, and the natural gas compressor capacity. The specific constraints include five aspects: the formation gas injection capacity equation, the material balance equation for the gas storage facility, the wellbore flow equation for the gas wells, the pipe wall erosion flow rate in the gas wells, and the compressor gas injection capacity.

Mathematical Model for Injection Allocation Optimization The following is the mathematical model developed for injection allocation optimization according to the objective conditions and constraints for the production allocation optimization of a gas storage group. The injection allocation target is 8 j > P > > > max qscðiÞ > < i¼1 > j > P > > > : i¼1 qscðiÞ ¼ QINJHðmÞ

Gas injection capacity of the gas storage group less

!

than the planned gas injection volume Gas injection capacity of the gas storage group more

!:

than the planned gas injection volume ð51Þ

The constraints are 8 > p2wf ðiÞ
p2rðiÞ ¼ AqscðiÞ þ Bq2scðiÞ > > >   > > > > prðiÞ ¼ p0ðiÞ 1
GinðiÞ > > > Z Z0ðiÞ GðiÞ > < rðiÞ 2 2 pwf ðiÞ ¼ bpwhðiÞ
aq2scðiÞ > > > q Oq > > scðiÞ ineðiÞ > > > > qscðiÞ OqeðiÞ > > > : q Oq scðiÞ

eðiÞ

ðFormation seepage pressure dropÞ ðMaterial balance equationÞ ðWellbore flow pressure dropÞ

:

ðLess than the gas injection capacity of compressorÞ ðLess than pipe wall erosion flow rateÞ ðLess than non-steady critical flow rateÞ

ð52Þ

Solution Process of the Injection Allocation Optimization The optimized injection allocation operation scheme for a gas storage group can be obtained by solving the reasonable injection allocation of the gas storage spaces meeting the target conditions and by using the formation seepage, the vertical wellbore pipe flow, the surface horizontal pipe flow, and the gas injection compressor capacity as the constraints. The basic solution process is as follows: 1. Input the relevant data for the injection allocation optimization. 2. Set the priority level of the gas injection for the gas storage group. 3. Assume that the gas injection stage is 1 (calculated from the first gas injection stage).

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4. If the gas injection stage is the actual gas injection operation that has taken place, there is no need for injection allocation optimization. If it is 1, then the calculation is required (go to step 5). 5. Assume that the gas injection level is 1, and then calculate the staged average minimum gas injection volume (Qav) and the maximum gas injection capacity (Qmax) of the gas storage spaces. 6. Proceed to the calculation for the next gas injection stage if the maximum gas injection capacity of the gas storage space is greater than the minimum gas injection volume, and the sum (Sum) of the average minimum gas injection volume of the gas storage group is less than the planned gas injection volume in this stage. Otherwise, reallocate the gas injection volume for this stage and return to the injection allocation for the previous stage. 7. Go to step 3 to calculate for the next stage until the gas injection stage is ended. 8. Output the injection allocation optimization calculation results.

Optimized Injection Allocation Scheme The formation seepage equation and the vertical wellbore pipe flow equation for the gas injection and production wells are obtained through dynamic analysis and calculation using the gas reservoir engineering method according to the surplus gas volume of the pipeline system during the gas injection period of the gas storage group. In addition, the optimized injection allocation operation scheme for the gas storage group can be obtained using the above-established injection allocation optimization method for the gas storage group taking the gas injection capacity of the gas injection compressors, the wellbore erosion flow rate, and the maximum formation gas injection volume as constraints in order to provide a basis for the gas injection operation of the gas storage group.

Conclusion In this chapter, for Chinese gas storage facilities with water invasion of the gas layers, a method of inventory, productivity, and deliverability prediction was introduced. This method could be used to evaluate the gas injection and production capacity during a cycle, to evaluate the multicycle gas injection and production capacity, and to predict the productivity and deliverability.

References 1. X. Hongcheng, W. Jieming, L. Chun, Inventory verification of underground gas storage based on a flooded and depleted gas reservoir. Nat. Gas Ind. 30(8), 79–82 (2010) 2. Y. Xiaoping, C. Linsong, H. Xueliang, et al., A prediction method for multi-stage injection and recovery capacity of underground gas storage. Nat. Gas Ind. 33(4), 96–99 (2013)

Design of Hole Structure and Casing String in UGS Drilling

27

Xinhua Ma, Guosheng Ding, and Jingcui Li

Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling Design for Gas Storage Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling Design Principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling Mode Optimization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selection of Well Completion Methods for Gas Storage Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . Completion Requirements for Injection and Production Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Factors to be Considered When Selecting a Completion Method . . . . . . . . . . . . . . . . . . . . . . . . . . Completion Method Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Completion Method Determination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hole Structure Design of Injection and Production Wells in Gas Storage Facilities . . . . . . . . . . Hole Structure Design Principles for Injection and Production Wells . . . . . . . . . . . . . . . . . . . . . Hole Structure Design Principle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hole Structure Design Methods and Steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Determination of the Casing Size and Hole Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Casing String Strength Design and Material Optimization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technical Requirements for the Casing String . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technical Requirements for Threads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling Fluid Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling Fluid Property Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling Fluid System Optimization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

680 681 681 681 683 683 683 683 684 685 685 685 688 689 689 689 691 692 692 693

X. Ma (*) · G. Ding Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China e-mail: [email protected]; [email protected]; [email protected] J. Li China National Petroleum Corporation, Beijing, China e-mail: [email protected] © Petroleum Industry Press 2022 X. Ma (ed.), Handbook of Underground Gas Storages and Technology in China, https://doi.org/10.1007/978-981-33-4734-2_26

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Introduction to Drilling Fluid Systems Used in Gas Storage Construction . . . . . . . . . . . . . . . . 694 Determination of the Drilling Fluid Parameters and the Maintenance of the Drilling Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 699 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 699

Abstract

Most of the gas reservoirs in China are constructed from depleted gas reservoirs, which can cause many challenges and difficulties when drilling into the gas reservoirs. To this end, in this chapter, according to the dry gas reservoir reconstruction gas storage well drilling problem, especially those related to the wellbore structure, completion method, casing string design, and mud design, such as the key link, the basic status, and the related performance requirements are analyzed and a design method and concrete implementation steps are proposed. Finally, based on China’s current successful gas storage drilling experiences, several typical cases are discussed in order to provide a basis and a reference for subsequent similar situations. Keywords

Drilling into depleted reservoirs · Hole structure · Completion · Casing design · Mud

Introduction The drilling and completion of gas storage facilities are an important link in the construction of gas storage facilities. Gas storage facilities have high injection and production intensities and experience large pressure changes. In order to achieve the integrity and reliability of the gas injection and production system of a gas storage facility, advanced, applicable, mature, and reliable techniques and equipment should be used in the drilling and completion stages of gas storage construction. The drilling engineering plan should be designed on a targeted basis according to the reservoir’s characteristics. The drilling engineering design should attach importance to achieving the objective of meeting the injection and production requirements, reducing problems during drilling and completion, effectively protecting the reservoirs, and ensuring the cementing quality. The hole structure should meet the needs of long-term cyclic highintensity injection and production and the safe production of the gas in the storage facility. Significant breakthroughs have been made in the development of drilling and completion techniques for the construction of the gas storage facilities, such as in the Banqiao gas storage group, Huabei gas storage group, Huabei Suqiao gas storage, and Chongqing Xiangguosi gas storage, and a series of drilling and completion techniques have been developed, thereby providing valuable methods and experience for the construction of larger-scale gas storage facilities in depleted gas reservoirs.

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Drilling Design for Gas Storage Facilities Drilling Design Principles The general principles and methods involved in the design of the drilling and completion stages of the development of conventional oil and gas fields are all applicable to the drilling and completion design for underground gas storage facilities constructed from depleted reservoirs. Underground gas storage has unique operating laws and conditions. Therefore, the following special principles should be followed in the drilling and completion design for gas storage facilities. 1. The basic content of the drilling design includes the geologic design, engineering design, construction schedule, and expense budget. If the wells are to be drilled in a block where a gas storage facility has been constructed, it is necessary to obtain data on the periodic changes in the gas injection pressure of the injection and production wells in the block. 2. Considering the requirements imposed by the special operating conditions of gas storage injection and production wells, the hole structure used when specifically drilling into reservoirs should be adopted to the greatest extent possible. In addition, the hole structure should be able to effectively seal off the oil, gas, and water layers, protect the gas-bearing reservoirs to the greatest extent possible, prevent damage to the gas-bearing reservoirs, and ensure a high production of single injection and production wells. 3. As is required by the cementing design, the cement slurry should return to protect the gas-bearing reservoirs and improve the safety performance of the injection and production wells. 4. The completion design should ensure the maximum seepage area between the gas layers and the bottom hole, thus reducing the flow resistance of the gas into wellbore. 5. The possibility of hole sloughing or sand production in play formations should be considered in the optimization of the completion method to ensure the long-term stable operation of the injection and production wells.

Drilling Mode Optimization Analysis of the Advantages and Disadvantages of Vertical Well Drilling ① Advantages of vertical well drilling The advantages include simple drilling technology, easy operation, low construction risk, a short drilling period for single wells, and a low drilling engineering investment. The friction force acting on the wall of the vertical wells is small, which is favorable for the running of various completion strings.

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Compared to directional wells, it is easier to improve cementing quality of vertical wells. ② Disadvantages of vertical well drilling For each new well drilled, a well site and a road leading to it need to be built. The land area required is huge, and the land acquisition cost is high. Based on the gas storage facilities already built in China, gas storage construction areas are often industrial and densely populated areas, and the land is densely covered by construction facilities, such as fishponds, factories, and private houses. In addition, in some regions, drilling platforms need to be erected. If all of the wells are vertical wells, the compensation for the ground occupied by the vertical wells and the cost of well site construction are high. Vertical well heads are scattered, and a relatively large number of high-pressure injection-production pipelines need to be laid during the surface engineering construction, thus increasing the surface engineering investment. Vertical well heads are scattered, which is inconvenient for ensuring the safe daily production management of the wellheads.

Analysis of the Advantages and Disadvantages of Directional Well Drilling ① Advantages of directional well drilling The drilling of directional wells is limited by ground conditions to a relatively small extent. Directional wells can be used when the ground conditions make vertical well site setup difficult or impossible. Compared with vertical wells, a cluster of directional wells greatly reduces the area of the occupied land; the construction of surface pipelines, roads, and well sites; and the construction investments. The locations of directional well heads are relatively concentrated, thus making the safety daily production management of wellheads easier. ② Disadvantages of directional well drilling Due to the particularity of cluster drilling, the anticollision distance between holes is short, which increases the difficulty in the design and construction of the drilling engineering. In addition, the hole measurement depth is large and the drilling period is long. Clusters of directional wells (including extended reach directional wells) have a large inclination angle and high requirements for well trajectory control, thereby increasing the friction force between the string and borehole wall and easily leading to problems. Therefore, according to the scale of the gas storage facility, the structural characteristics of the oil and gas reservoirs, and the injection and production capacity and mode of the single wells, drilling platforms (well sites) are selected at suitable locations within the structures, and cluster directional wells are preferred for the injection and production wells of gas storage facilities.

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Selection of Well Completion Methods for Gas Storage Facilities Completion Requirements for Injection and Production Wells In view of the particularity of injection and production wells for gas storage facilities, the completion method for injection and production wells should be determined by comprehensively considering the reservoir type, formation lithology, reservoir stability, reservoir permeability, and economic indexes.

Factors to be Considered When Selecting a Completion Method The following factors need to be considered when selecting a completion method: gas-bearing reservoir type, lithology, and permeability of gas-bearing reservoirs, oil and gas distribution, completion interval stability, existence or absence of high pressure layers nearby, and bottom water. The open hole completion method is used for homogenous hard formations, while the cased hole completion method is used for heterogeneous hard formations. The nonfixed screen completion method is used for unstable formations, and the sand control screen completion method should be used for play formations with poor cementation and sand production.

Completion Method Selection A series of laboratory experiments, evaluations, and analysis should be carried out before selecting a completion method for injection and production wells in gas storage facilities. 1. Analysis of the sand production of the gas wells in the gas reservoir development stage should be conducted. That is, whether sand control measures were taken in the completion of the production wells, whether sand production or collapse occurred during the production process, and whether sand settling at the bottom of the hole was recorded during the workover. 2. Experimental evaluation of the rock mechanics should be conducted, including the rock compressive strength, Young’s modulus, and Poisson’s ratio. 3. Borehole wall stability analysis should be conducted. Based on the results of the rock mechanics experiments and the in situ gas reservoir stress data, the relationship between the maximum shear stress on the borehole wall and the shear strength of the rocks should be calculated and analyzed. 4. Formation sand production prediction The strength of the reservoir rock and the possibility of sand production can be evaluated using the combined modulus method. The combined elastic modulus

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(EC) of the rocks is calculated using Eq. (1) according to the acoustic and density logging data.

EC ¼

9:94  108  ρ , Δt2c

ð1Þ

where EC is the combined elastic modulus of the rocks (MPa), ρ is the rock’s density (g/cm3), and Δtc is the interval transit time (μs/m). Based on the theory of reservoir sand production prediction, the larger the combined elastic modulus (EC), the smaller the possibility of sand production. Experience shows that when the combined elastic modulus (EC) is greater than 2.0  104 MPa, no sand production will occur in oil and gas wells; otherwise, sand production will occur. The judgment standard is as follows: when EC  2.0  104 MPa, no sand production will occur during normal production; when 1.5  104 MPa < EC < 2.0  104 MPa, slight sand production will occur during normal production; and when EC  5  104 MPa, serious sand production will occur during normal production. Domestic oilfields use this method for sand production prediction for some oil and gas wells. The accuracy rate of this method is greater than 80%.

Completion Method Determination At present, there are more than 10 types of completion methods for oil and gas reservoirs. The completion methods applicable to gas storage facilities mainly include the open hole completion method and the perforation completion method. Most of China’s existing gas storage facilities constructed from depleted reservoirs have used the casing perforation completion method. The reservoirs in the Huabei Yong-2 gas storage facility are carbonate reservoirs, and the common screen completion method was used. Sand control screen completion tests have been carried out in horizontal injection and production wells in some sandstone reservoirs.

Open Hole Completion Open hole completion includes initial open hole completion, open hole screen completion, and open hole gravel pack completion. The open hole completion method can increase the gas injection gas production volumes and reduce reservoir damage caused by cementing and perforation, but it is limited by the formation conditions and the inter-layer interference can be serious. Perforation Completion Perforation completion is the most widely used completion method for gas storage facilities worldwide. The casing perforation completion method allows for the selective perforation and opening of reservoirs with different physical properties, which prevents inter-layer interference. In addition, this method avoids interbedded

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water, bottom water, and interlayer collapse and has conditions favorable for the implementation of layered operations such as layered injection and production. This completion method can be used for sandstone or carbonate reservoirs. Perforation completion requires detailed research into the perforation techniques, perforation parameters, and perforation fluids in order to meet the requirements of injection and production wells in gas storage facilities, that is, large injection quantity and large production.

Hole Structure Design of Injection and Production Wells in Gas Storage Facilities The hole structure includes the casing layers, casing setting depth, and the matching of the hole size (bit size) and the casing size. The hole structure design is the basis of the drilling engineering design. Designing a reasonable hole structure is an important part of the drilling engineering design.

Hole Structure Design Principles for Injection and Production Wells 1. The hole structure of injection and production wells should meet the needs of long-term, cyclic, high-intensity injection and production and the safe production of gas storage facilities. 2. The setting depth of each layer of casing should be designed in conjunction with the actual data for the formation’s pore pressure, collapse pressure, and fracture pressure during gas storage construction. Reservoirs should be specially drills when conditions permit. 3. Downhole problems such as lost circulation, blowouts, collapse, and sticking should be avoided to create conditions favorable for the drilling of wells and to minimize the drilling period.

Hole Structure Design Principle Hydrostatic Fluid Column Pressure The hydrostatic fluid column pressure is the pressure caused by the gravity of the fluid column. The hydrostatic fluid column pressure is related to the density and vertical height of the fluid column, and it has nothing to do with its horizontal size and shape. The hydrostatic fluid column pressure (Ph) is ph ¼ 103 ρgH,

ð2Þ

where Ph is the hydrostatic fluid column pressure (MPa); ρ is the fluid column density (g/cm3); g is the acceleration due to gravity (9.81 m/s2); and H is the vertical height of the fluid column (m).

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Overburden Pressure The overburden pressure of a formation is the pressure caused by the total gravity of the formation matrixes (rocks) and the fluids (oil, gas, and water) above the formation. The overburden pressure ( po) is po ¼

ðH 0

103 ½ð1  ϕÞρrm þ ϕρgH,

ð3Þ

where po is the overburden pressure (MPa); Φ is the rock’s porosity; ρrm is the rock’s matrix density (g/cm3); ρ is the density of the fluids in rock’s pores (g/cm3); g is the acceleration due to gravity (9.81 m/s2); and H is the vertical height of the fluid column (m).

Formation Pressure The formation pressure is the pressure acting on the fluids (oil, gas, and water) in the underground rock formation’s pores, and it is also called the formation pore pressure Pp. In various geologic sediments, the normal formation pressure is equal to the hydrostatic fluid column pressure from the ground surface to the formation underground. Therefore, most normal formation pressure gradients are 0.0105 MPa/m. However, during drilling, the actual formation pressure gradient is often found to be far greater than the normal formation pressure gradient. A formation pressure that exceeds the hydrostatic fluid column pressure (Pp > Ph) in a special geologic environment is called an abnormally high pressure, while a formation pressure that is less than the hydrostatic fluid column pressure (Pp < Ph) is called an abnormally low pressure. Drilling experience has proven that all three types of formation pressures may be encountered, of which abnormally high pressure formations are more common and are the most relevant to the drilling engineering design and construction. Formation Fracture Pressure The formation fracture pressure is the well fluid pressure at a certain depth where the pressure generated by the drilling fluid column in a well becomes high enough to fracture the formation, thus causing the original fractures to open and extend or causing the formation of new fractures. This pressure is called the formation fracture pressure Pf. Drilling fluid leakage will occur at the formation fracture pressure. Formation Collapse Pressure When the fluid column pressure in a well is lower than a certain value, the formation will collapse. The formation collapse pressure Ps is the minimum well pressure for which the borehole’s wall rocks do not collapse and hole diameter shrinkage does not occur. Pressure System in a Wellbore Formation pressure, formation fracture pressure, and drilling fluid pressure exist in an open hole section. These three pressures must meet the following condition:

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Design of Hole Structure and Casing String in UGS Drilling

pf Ppm Ppp ,

687

ð4Þ

where Pf is the formation fracture pressure (MPa); Pm is the drilling fluid column pressure (MPa); and Pp is the formation pressure (MPa). The drilling fluid column pressure should be slightly greater than the formation pressure to prevent well kick, but it must be less than the formation fracture pressure to prevent formation fracturing and thus lost circulation. In a nonclosed hydraulic system (i.e., the blowout preventer is not closed for back pressuring-out), the pressure varies linearly with increasing well depth, so the adoption of the concept of a pressure gradient is convenient. Equation (4) can be expressed as follows: Gf PGm PGp ,

ð5Þ

where Gf is the formation fracture pressure gradient (MPa/m); Gm is the drilling fluid column pressure gradient (MPa/m); and Gp is the formation pressure gradient (MPa/m). If the stability of the borehole’s wall is taken into account, a time-related inequality needs to be added: Gm ðtÞPGs ðtÞ,

ð6Þ

where Gm(t) is the drilling fluid column pressure gradient (MPa/m) and Gs(t) is the formation collapse pressure gradient (MPa/m). The above pressure systems are necessary to ensure normal drilling, otherwise drilling accidents may occur. When these pressure systems can coexist in the same well section, that is, the above conditions are all met for a series of sections, the sections do not need to be isolated by a casing; but when the pressure systems cannot coexist, the sections need to be isolated by a casing. In short, the hole structure design must meet strict mechanical requirements, that is, the balance of the formation-hole pressure system. A reasonable hole structure design can only be created when the above pressure systems are fully understood.

Equivalent Gradient Distribution in a Liquid Pressure System 1. The pressure distribution and equivalent gradient distribution in a nonsealed fluid column system: when a hole with a depth H is filled with drilling fluids with a density of ρm, the fluid column pressure varies linearly with increasing well depth, while the equivalent gradient is constant from top to bottom. 2. The pressure distribution and equivalent gradient distribution in a sealed fluid column system: if the above system is sealed and an additional pressure Po is applied, this is equivalent to Po being applied to each depth section, but it does not change the linear distribution of the pressure. However, in this case, the pressure equivalent gradient distribution is a hyperbola. This is the case for the liquid column pressure and equivalent gradient distribution in a well when the blowout preventer is closed due to the occurrence of overflow or blowout during the drilling of high pressure formations. In this case, the standpipe pressure or casing pressure is Po.

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3. In the linear interpolation of the formation pressure and formation fracture pressure profile, the formation pressure and formation fracture pressure data are generally discrete and composed of several scattered pressure gradient and depth data points. In order to obtain continuous formation pressure and formation fracture pressure gradient profiles, the linear interpolation method can be used, but the curve fitting method is not applicable. 4. In the determination of the depth of the essential sealing points, the limit length well section that meets the pressure inequality (Eq. 5) or inequality (Eq. 6) in an open hole is defined as a feasible open hole section. The length of the feasible open hole section is determined by the engineering and geological conditions. The upper boundary of the section is the essential sealing point of the upper layer of the casing, and the lower boundary of the section is the essential sealing point of this layer of casing.

Hole Structure Design Methods and Steps 1. The relevant geologic data includes the lithologic profile and its fault tips, the formation pressure gradient profile, and the formation fracture pressure gradient profile. 2. The relevant engineering data include the following. ① The swabbing pressure coefficient Sbo: when the string is lifted, the fluid column pressure in the well decreases due to the swabbing action. ② The surge pressure coefficient Sgo: when the string is lowered, the surge pressure generated by the downward movement of the string causes the fluid column pressure in the well to increase. ③ The formation fracture safety factor Sfo: the safety increment of the formation fracture pressure required to prevent the exposed formation at the upper casing shoe from being fractured. The magnitude of the safety factor is related to the prediction accuracy of the formation fracture pressure. ④ The kick tolerance Sko: the allowable value of the kick volume caused by the formation pressure prediction error. Sko is related to the formation pressure’s prediction accuracy. ⑤ The differential pressure tolerance ΔPo: the allowed maximum pressure value where the casing is not affected by the differential pressure. The magnitude of ΔPo is related to the drilling technique used, the drilling fluid’s properties, and the pore pressure in the open hole section. If both the normal formation pressure and the abnormally high pressure come from an open hole section, pipe sticking easily occurs in the normal pressure section, so the differential pressure tolerance can be differentiated using the normal pressure section and the abnormally high pressure section, which are expressed as ΔPN and ΔPA, respectively. The above five engineering design factors are all expressed in equivalent density and their unit is g/cm3. 3. Design methods and steps The formation pressure and the fracture pressure profiles of the region in which the design well is located should be established before designing the hole structure. The setting depth of the production casing depends on the location of the gas-bearing reservoir and the completion method used, so the design steps begin with the intermediate casing. The hole structure design should be developed using the following steps.

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① Calculate the supposed point of the setting depth of the intermediate casing. The basis for determining the casing setting depth is that the predicted maximum hole pressure should not cause the formation exposed at the casing shoe to fracture during the drilling of the lower section. ② Verify whether the intermediate casing is stuck when it is run to the supposed depth. ③ Calculate the supposed point of the setting depth of the drilling liner. When the setting depth of the intermediate casing is smaller than the depth of the supposed point, a liner needs to be run and its setting depth needs to be determined. ④ Verify whether the drilling liner is stuck when it is run to the supposed depth. The verification method is the same as that for verifying whether the intermediate casing is stuck when it is run to the supposed depth. ⑤ Calculate the setting depth of the surface casing. According to the formation pressure gradient at the intermediate casing shoe and given the kick condition Sk, the setting depth of the surface casing is calculated using the trial-and-error method.

Determination of the Casing Size and Hole Size 1. Principle for determining the casing size and hole size The hole structure’s size is generally determined from inside to outside. The production casing size, the size of the hole in which the production casing is run, the intermediate casing size, the size of the hole in which the surface casing is run, and the conductor size are successively determined. The production casing size is determined according to the injection and production engineering design. There is a certain clearance between the casing and hole. If the clearance is too large, it is not economical, but if it is too small, the cementing quality cannot be guaranteed. The minimum clearance is generally 9.5–12.7 mm (3/8–½ in), and the preferred clearance is 19 mm (3/4 in). 2. Standard matching of the casing and the hole size. At present, the sizes of the casing and the bits manufactured in China and in other countries have been standardized and serialized. The matching of the casing and the size of the corresponding hole is basically determined or varies within a small range.

Casing String Strength Design and Material Optimization Technical Requirements for the Casing String 1. The chemical composition, mechanical properties (e.g., tensile strength, impact toughness, and hardness), and microscopic structure of the casing should meet the requirements of the Specification for Casing and Tubing (API Spec 5CT).

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2. The minimum value of the casing strengths (tensile strength, internal pressure strength, and collapse strength) should not be lower than the values required by the Bulletin on the Performance Properties of Casing, Tubing, and Drill Pipe (API Bul 5C2). 3. Casing connection thread requirements ① For long round threads, the thread parameters should not be lower than the values specified by the Gauging and Inspection of Casing, Tubing, and Line Pipe Threads (API Spec STD 5B) and they should be subjected to thread gluing resistance tests using the relevant test methods described in the Performance Evaluation Method for Casing and Tubing Connections (API RP 5C5). ② For special threads, it should be ensured that the threaded connections do not leak at an internal pressure equivalent to 95% of the minimum yield stress of the casing, and the gluing of special threads does not occur after five episodes of makeup and break-out. The manufacturer must provide the optimal make-up torque value and make-up torque range. 4. Casing string strength design method and safety factor The injection and production wells in underground gas storage facilities should be designed based on the casing strength and should be subjected to triaxial stress testing in accordance with the equal safety factor method. The criteria for determining the safety factor are as follows: the safety factor of the collapse strength should be greater than 1.125, the safety factor for the internal pressure strength should be greater than 1.10, and the safety factor for the tensile strength should be greater than 1.8. 5. Design assumptions The collapse pressure of the casing string mainly comes from the external formation fluid pressure, the lateral pressure of the free-flowing rock formations, the completion operations, and reservoir stimulation. It is generally deemed that the drilling fluid column pressure while running the casing is the maximum collapse pressure for the casing. The collapse pressures of the surface casing and the production casing are determined by considering the complete evacuation of the casing. The collapse pressure of the intermediate casing is calculated after the drilling fluid column pressure is balanced with the formation support fluid column pressure during the next drilling session. The maximum internal pressure on the casing string should be the wellhead pressure when the casing is full of natural gas, and the internal pressure of only the intermediate casing is calculated at 40% of the kick volume. The axial tensile force of the casing string is generated by its dead weight. The axial tensile force of the casing string is calculated according to its weight in air. Due to the existence of biaxial stress, the rated collapse strength and the rated internal pressure strength of the casing will change. Under the effect of axial stress,

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the rated collapse pressure of the string above the neutral point on the casing is reduced. Therefore, the impact of the stress is considered when verifying the collapse strength of the casing, the effective collapse strength of the casing is calculated, and the strength of the casing string is checked using the data. The equation for this calculation is as follows: h  2 i0:5   pca =pco ¼ 1  0:75 Sa =Y p  0:5 Sa =Y p ,

ð7Þ

where Pca is the effective collapse pressure under the action of axial tensile stress (kPa); Pco is the rated collapse pressure calculated without the action of axial tensile stress (kPa); Sa is the axial stress on the casing body (kPa); and Yp is the yield strength of the casing body (kPa). 6. Selection of casing threads Conventional wells are generally only designed for string verification and without regard to thread sealing. The casing string of the injection and production wells in gas storage facilities is composed of thousands of meters of casing with a threaded connection, and it is a high pressure vessel capable of withstanding pressures hundreds or even thousands of times greater than atmospheric pressure. Therefore, threaded connections are a weak link. According to the American Petroleum Institute’s (API) reports, 86% of casing string failure accidents occur at threads, which is also consistent with Chinese statistics. Therefore, injection and production wells in gas storage facilities should use casings with special threads to improve the gas tightness of the casing strings.

Technical Requirements for Threads The tubing and casing of injection and production wells in gas storage facilities need to bear the complex stresses, including the tensile stress, compressive stress, bending stress, internal pressure, external pressure, and thermal cycling stress, for long periods of time. Therefore, the casing of gas storage wells must have two characteristics: structural integrity and seal integrity. Structural integrity means that after the threads are engaged, they should have sufficient connection strength to prevent the structure from being damaged by external forces. Seal integrity means that the threads do not leak under various stress conditions. The seal integrity of the threads is a key indicator of the quality of gas injection and production wells in gas storage facilities. According to field applications, the different thread types have significantly different sealing properties. The widely used API round threads and buttress threads have advantages, such as a low price, convenient processing and maintenance, and easy operation, but they have serious flaws in terms of their seal integrity and are not suitable for use in gas storage injection and production wells. Therefore, special threads with good sealing properties are required.

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These special threads have overcome the design disadvantages of the API threads, and the sealing effect is no longer solely borne by the threads, but instead it depends on special metal-to-metal seals. In general, these special threads have multiple seals, including a main seal (mainly achieved by a metal-to-metal radial seal structure) and an auxiliary seal (generally achieved by a torque shoulder). In addition, the threads no longer play a primary sealing role, but they still play a certain auxiliary sealing role. These structural designs give the special threads good sealing properties. See Table 1 for the types and manufacturers of the main oil well pipes with special threads.

Drilling Fluid Technology Drilling Fluid Property Requirements Protecting the gas-bearing reservoirs is critical during the drilling of new injection and production wells during the conversion of depleted oil and gas reservoirs into underground gas storage facilities. The pressure in the gas-bearing reservoirs is severely depleted, so it is necessary to minimize the amount of drilling fluid filtrates that enter the gas-bearing reservoirs and to prevent the loss of circulation. In addition, it is necessary to try to prevent solid-phase particles from blocking the throats, to increase the return permeability, and to ensure that injection and production wells can reach the designed injection and production capacity. Therefore, in addition to meeting the general property requirements, drilling fluids must also meet the following requirements during the drilling of new injection and production wells during the conversion of depleted oil and gas reservoirs into underground gas storage facilities. 1. The density, inhibiting ability, filtration property, wall building capacity, and plugging ability of the drilling fluids must meet the requirements of the drilled formation and ensure the stability of the borehole wall. 2. The fluid pressure in the formations needs to be controlled to ensure smooth drilling. 3. A reasonable gradation of the drilling fluid system needs to be maintained to reduce reservoir damage by the solid particles in the drilling fluid. 4. The drilling fluid system should have a good compatibility with the formations. 5. The drilling fluid system should have a strong ability to inhibit the hydration of clay. 6. In order to effectively clean the bottom hole and carry cuttings, the drilling fluids must have a corresponding rheological behavior. 7. The wall building capacity and filter cake quality need to be improved, the borehole wall needs to be stabilized, and downhole problems such as hole sloughing and lost circulation need to be prevented.

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Table 1 Types and manufacturers of the main oil well pipes with special threads Manufacturer Tenaris

Country Argentina, Italy, Mexico, Japan, Brazil, etc.

V&M

France, Germany, USA, Brazil, etc.

Hunting

USA

Sumitomo Metal

Japan

JFE TMK

Japan Russia

TPCO Wuxi Seamless Oil Pipe Co., Ltd. Baosteel

China China

China

Thread type Blue series: BLUE, BLUE-DPLS, BLUE-MS, BLUE-SC, BLUE-SB, BLUE-CB, BTL (Blue Thermal Lite), and BNF (Blue Near Flush); Wedge500 series: W563, W523, W521, W513, W511, W503, W533; and Others: 3SB, MS, HW, ER, PJD, SLX, MARCII, PH4, PH6, and CS VAM21, VAMTOP, VAMTOP HT, VAMTOP HC, VAMTOP FE, DINO VAM, BIG OMEGA, VAM FJL, VAM HTF, VAM SLIJ-II, VAM MUST, VAM HW ST, VAM HP, and CLEANWELL Two-stage tubing series: TS-HD, TS-HD-SR, TS-HP, and TS-HP-SR; Seal locking series: SEAL-LOCK XP, APEX, BOSS, FLUSH, GS, HC, HT, and HT-S; Timed, SF TKC series: Convertible BTC, Convertible EUE, Convertible LTC, MMS EUE, BTC and Plus, LTC and Plus, EUE and Plus, FJ-150, 4040, and Convertible 4040;and JFE-cooperation and development series: FOX and JFEBEAR VAM21, VAMTOP, VAMTOP HT, VAMTOP HC, VAMTOP FE, DINO VAM, BIG OME-GA, VAM FFL, VAM HTF, VAM SLIF-II, VAM MUST, VAM HW ST, VAM HP, CLEANWELL, and TM FOX, JFEBEAR TMK GF, TMK PF, TMK PF ET, TMK, FMC, TMK CS, TMK TTL-01, TMK1 Integral, TMK FMT Tubing, ULTRA-FJ, ULTRA-SF, ULTRAFX, and ULTRA-QX TP-CQ, TP-G2, TP-EX, and TP-FL WSP-1 T, WSP-2 T, WSP-3 T, WSP-F (4 T), WSP-HK, WSP-BIG, WSP-IF4/ IF6/IF8, and WSP-JL BGT1, BGT, and BGC

Drilling Fluid System Optimization Depending on the conditions, including the pressure of the drilled formation, the rock composition, and the formation fluid conditions, different drilling fluid systems should be selected. The selected drilling fluid system must ensure the drilling construction and protect the gas-bearing reservoirs. The drilling fluids used in the construction of gas storage facilities are mainly optimized and designed based on the following factors:

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1. The density of the drilling fluid can be adjusted according to the downhole conditions and the drilling method’s requirements. 2. The inhibiting ability, wall building capacity, and plugging ability of the drilling fluid system meet the requirements of the formation being drilled. 3. The compatibility of the system with the formation water and its ability to inhibit the sensitive minerals in the formation meet the requirements of the formation being drilled. 4. The system should be compatible with the liquid phase in the gas-bearing reservoirs. That is, the fluid system does not precipitate in the formation water, and it is not emulsified with the oil and gas. 5. The system should be compatible with the gas-bearing reservoir’s sensitivity. 6. According to the characteristics of the pore throat structure of the gas-bearing reservoirs, the content and gradation of the solid phase in the drilling fluid are controlled to reduce the damage to the gas-bearing reservoir caused by the solid phase particles in the drilling fluid. 7. The drilling fluid should not corrode the drilling tools and casing. 8. The drilling fluid system does not pollute the environment or the pollution can be eliminated. 9. The fluid system should have a low cost and a simple application process.

Introduction to Drilling Fluid Systems Used in Gas Storage Construction Due to the differences in formations in different regions, the requirements for the selection of the drilling fluid systems for these areas are different. Taking the Dagang gas storage as an example, several field drilling fluid systems are discussed below.

Composition This system was named because its main additive is a polypropylene polymer. The basic components of the system are macromolecular inhibitors, micromolecular antisloughing fluid loss agents, polymer viscosity-reducing agents, antisloughing agents, lubricants, reservoir protection agents, and other additives. Performance Characteristics 1. The solid phase content is low, and the proportion of submicron particles is also low. These basic characteristic of the polymer drilling fluid result in the selective flocculation and inhibition of the cutting dispersion by polymer additives, which are both extremely favorable for increasing the drilling speed. For a drilling fluid without weighting materials, its density is approximately proportional to its solid phase content. 2. A good rheological property is mainly manifested by the strong shear thinning behavior and suitable flow regime. 3. Good thixotropy

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4. The polymer drilling fluid has a low solid phase content, a small proportion of submicron particles, good shear thinning behavior, a low Carson limit viscosity, a strong ability to suspend and carry drilling cuttings, and a good well washing effect. These excellent properties are all favorable for increasing the rate of penetration (i.e., the drilling speed). 5. The strong ability to stabilize the borehole wall and a regular hole diameter. As long as the content of the polymer additives in the filtrates is guaranteed during the drilling process, the water absorption and dispersion of the rocks can be effectively inhibited. Borehole wall erosion can be reduced by reasonably controlling the flow pattern of the drilling fluid. All of these factors stabilize the borehole wall. 6. A small amount of gas-bearing reservoir damage is favorable for protecting the gas-bearing reservoirs. Polymers have a good inhibiting property and can prevent the hydration and dispersion of clay, which is favorable for maintaining an appropriate gradation of the drilling fluid, for reducing the fine particle content, and especially, for the concentration of submicron particles and the bentonite content in the drilling fluid. The drilling fluid system can prevent clay microparticles from blocking the sandstone pore passages and can reduce the amount of reservoir damage caused by the solid phase, and it helps protect the gas-bearing reservoirs. 7. The system can prevent the occurrence of circulation loss. The fluid column pressure of the system is low, which reduces the occurrence of leakage loss. However, the polymer drilling fluid has a low return velocity in the annulus, and it is generally in a state of laminar flow or modified laminar flow, so it is difficult for the drilling fluid to enter the formation’s pores. In addition, the polymer molecules can be adsorbed onto the pore wall in the leaked pores, and thus, it has a blocking effect along with the other clay particles adsorbed on the molecular chains. Considering all of the above factors, the system has a good antileak effect.

Composition of the Organosilicon Antisloughing Drilling Fluid System This system is a new drilling fluid system, which is mainly composed of stabilizers, diluents, and potassium humate silicate. The system is widely used due to its strong temperature resistance and good lubrication and antisloughing effects. Performance Characteristics of the Organosilicon Antisloughing Drilling Fluid System The system has a strong antisloughing capacity. Silicon molecules are adsorbed on the surface of the mud shales, thus preventing the clay from directly coming into contact with the water, reducing the hydration expansion of the clay, and achieving an inhibiting effect. 1. The properties of the drilling fluid are stable. This system plays a role in the cutting encapsulation and shale stabilization. It ensures the very good integrity of the cuttings and prevents the mutual bonding of the cuttings, thus preventing the occurrence of downhole problems.

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2. High permissible solid content: The drilling fluid has advantages such as a high dynamic plastic ratio, a high viscosity at a low shear rate, a good rheological property, a strong capacity for suspending and carrying sands, a strong resistance to cuttings pollution, a stable performance, and easy maintenance. 3. The temperature resistance of the drilling fluid system can reach 200 °C, which basically meets the requirements for operations in deep wells and in high temperature wells. 4. The system uses gas-bearing reservoir protection technology with film plugging additives, which is favorable for protecting the gas-bearing reservoirs and obtaining a high return permeability.

Composition of the Solid-Free KCl Polymer Drilling Fluid System This system is a type of solid-free brine drilling fluid system that uses organic salt as the inhibitor. It is mainly composed of salt-resisting strongly inhibiting encapsulating agents, salt-resisting thickening agents, inhibiting lubricants, inhibiting antisloughing agents, and salt and high temperature resistant fluid loss agents. Performance Characteristics of the Solid-Free KCl Polymer Drilling Fluid System The solid-free KCl polymer drilling fluid system has a strong inhibiting ability, a good antisloughing effect, a strong temperature resistance up to more than 220 °C, a strong resistance to salt and gypsum pollution, and a good reservoir protection function. It is the preferred drilling fluid system for specially drilling reservoirs. Performance Evaluation of the Solid-Free KCl Polymer Drilling Fluid System 1. Antisoil pollution experiment on solid-free KCl polymer drilling fluid system According to the experimental data presented in Table 2, the solid-free KCl polymer drilling fluid has a good inhibiting ability at both room temperature and high temperatures, and it can inhibit the dispersion of the soil phase in the drilling fluid very well, thus keeping the viscosity and shearing force of the system basically unchanged. 2. Soaking experiment and recovery ratio experiment (Table 3). According to the experimental data presented in Table 3, the solid-free KCl polymer drilling fluid has a stronger inhibiting effect on the cuttings than common drilling fluids, and it is second only to an oil-based drilling fluid system. 3. Shale expansion experiment A shale expansion experiment was performed on the cuttings from well K2-1 in the Ban-876 gas storage using the drilling fluid system. According to the

API filter loss (mL) 5.2 4.6 4.8 4.0 4.5 4.2 4.6 4.0 4.2

Note: the aging condition is a constant temperature of 120 °C for 16 h

Optimized formula + +5% bentonite

Optimized formula + +3% bentonite

Optimized formula + +2% bentonite

Formula Optimized formula Optimized formula +1% bentonite

Experimental temperature Room temperature Room temperature Aging Room temperature Aging Room temperature Aging Room temperature Aging

Table 2 Antisoil pollution experiment pH value 8 8.5 8.5 8.5 7.5 8.5 7.5 8.5 7

Apparent viscosity (mPa•s) 30 35 30.5 33 32.5 40 35 42 43

Plastic viscosity (mPa•s) 17 20 17 18 17 23 22 24 23

Dynamic shear force (Pa) 13 15 13.5 15 15.5 17 13 18 20

Initial/final shearing force (Pa) 4.5/7.5 5.0/8.0 5.0/7.5 5.0/8.5 5.0/8.5 6.0/9.0 6.0/8.0 6.5/9.0 5.5/8.5

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Table 3 Soaking experiment and recovery ratio experiment Drilling fluid type Fresh water Amphoteric ion polymer Solid-free KCl polymer Oil-based drilling fluid

Description of the soaking effect of the cuttings from well K2-1 in the Ban-876 gas storage (soaking for 7 days) Disintegrated and pasty after soaking of cuttings Appearance of cracks in cuttings; humid inside after breaking apart cuttings by hand Cuttings remain intact and are externally covered with a polymer film layer. Cuttings remain intact.

Recovery ratio of cuttings (%) 24 87 97 99

Table 4 Shale expansion experiment research Drilling fluid system Expansion quantity (mm/8 h)

Poly-sulfonated 3.21

Polymer 2.87

Solid-free KCl polymer 1.82

Table 5 Static pollution evaluation experiment Core sample No. 1 2

3

Drilling fluid system Polymer Solid-free KCl polymer Oil-based drilling fluid

Gas logging permeability Ka (mD) 71.6 45.9

Oil phase permeability Ko (mD) 46.1 28.16

Oil phase permeability after pollution Kd (mD) 35.96 25.15

Return permeability (%) 78 89.3

110.8

90.7

83.44

92

experimental results, the solid-free KCl polymer drilling fluid has a strong hydration inhibition effect that is significantly better than that of other commonly used drilling fluid systems. The results of this experiment are presented in Table 4. 4. Evaluation of the gas-bearing reservoir protection effect A static pollution evaluation experiment was performed using a core flow device. The experimental results are presented in Table 5. According to the experimental data, the solid-free KCl polymer drilling fluid system can achieve a return permeability of up to 89.3%, and it has a good reservoir protection effect.

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Determination of the Drilling Fluid Parameters and the Maintenance of the Drilling Fluid Properties Determination of the Drilling Fluid’s Density The drilling fluid’s density is an important parameter related to the downhole safety, drilling speed, and protection of gas-bearing reservoirs. The drilling fluid density is mainly determined using the predicted values of three pressures. In addition, borehole wall stability problems are solved using chemical methods, and the rheological properties are considered. In the case in which borehole wall collapse cannot be solved by means of chemical methods and rheological properties, the drilling fluid’s density can be appropriately increased. Gas-bearing reservoirs have low pore pressures; therefore, on the premise that the drilling fluid’s density can maintain the borehole wall’s stability, a drilling fluid density that is as low as possible is selected to minimize the downhole problems. Drilling Fluid Solid Control The solid particles in drilling fluids have a significant effect on their density, viscosity, and shear force, and these properties are directly related to the hydraulic parameters of the drilling fluids, drilling speed, drilling cost, and downhole conditions. A high solid content in drilling fluids can lead to the formation of thick filter cakes, which can easily cause differential pressure sticking. In addition, the permeability of the filter cakes formed is high and the filter loss is large, causing reservoir damage, hole instability, serious wear to the bits and drill strings, and a decrease in the rate of penetration. Therefore, it is very important to ensure that the drilling fluids have a low solid content throughout the well. Solid control methods include sedimentation in large basins, dilution with clear water, replacement of some of the drilling fluids, and the removal of solids using mechanical equipment. In order to maximize the removal of the useless solids in the drilling fluids and to maintain a low solid content in the drilling fluids, the drilling site of a gas storage facility requires the use five-stage purification equipment, including shaker screens, desilters, desanders, centrifuges, and degassers. In addition, the efficient use of this equipment should be ensured.

Conclusions Based on the successful drilling experience gained from China’s current gas storage reservoirs, a design method and procedure suitable for drilling in China’s drained gas reservoirs was proposed, and two completion methods are recommended: open-hole completion and perforation completion. Three drilling fluid systems, that is, the polymer fluid system, solid-free KCl polymer drilling fluid system, and the organosilicon antisloughing drilling fluid system, were optimized.

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Xinhua Ma, Guosheng Ding, and Ligen Tang

Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reservoir Protection Technique . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reservoir Damage Factors During Drilling and Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Internal Gas Reservoir Damage Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Engineering Factors for Gas Reservoir Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reservoir Protection Measures for Drilling and Completion Engineering . . . . . . . . . . . . . . . . . . . . . Reservoir Protection Measures During Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reservoir Protection Measures During Perforation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Complete Sets of Pressure Sealing Techniques for Gas Storage Construction . . . . . . . . . . . . . . . . Research on the Pressure Sealing Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Occurrence Mechanism of Formation Fracturing (Low Pressure Bearing Capacity) . . . . . . . . . . Causes of Formation Fracturing or Low Pressure Bearing Capacity (Failure to Bear Pressure) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Natural Vertical Fractures, Micro-fractures, and Induced Fractures . . . . . . . . . . . . . . . . . . . . . . . . . . . Wellbore Strengthening Technique . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selection of Circulation Loss Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cementing Technique for Gas Storage Facilities Constructed from Depleted Gas Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Particularity of and Difficulties Involved in the Cementing of Gas Storage Facilities Constructed from Depleted Gas Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tough Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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X. Ma (*) · G. Ding · L. Tang Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China e-mail: [email protected]; [email protected]; [email protected] © Petroleum Industry Press 2022 X. Ma (ed.), Handbook of Underground Gas Storages and Technology in China, https://doi.org/10.1007/978-981-33-4734-2_27

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Complete Sets of Cementing Techniques for the Construction of Gas Storage Facilities from Depleted Gas Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 719 Formulation of the Cementing Technique Specifications and Quality Evaluation Specifications for Gas Storage Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 723 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 724

Abstract

Most of the gas reservoirs in China were constructed from depleted gas reservoirs, which causes many challenges and difficulties in terms of reservoir damage and cementing. Therefore, in order to enable the smooth construction of wells and to protect the seepage capacity of the reservoir, this chapter focuses on the key engineering steps for reservoir protection, pressure sealing, and cementing. Based on an analysis of the internal and external reservoir pollution factors involved in the process of reservoir protection, corresponding measures and suggestions are proposed. For the process of pressure bearing plugging, a recommended plugging material scheme and a corresponding borehole strengthening technique are proposed based on an analysis of the mechanism of the circulation loss due to the pressure bearing. In terms of the cementing engineering, this chapter analyzes the special requirements of special production systems, such as the reciprocating injection and production in gas storage facilities, proposes a ductile cement and other comprehensive supporting measures, and establishes a standard specification for the quality evaluation of the cementing. This chapter provides a good technical model and example for use in similar projects. Keywords

Damage factors · Protection measures · Lost circulation materials · Tough cement · Evaluation specification

Introduction Gas storage facilities are characterized by high construction costs, a long service life (approximately 50 years), and strict safety requirements. Cementing engineering is the core technique used in gas storage construction. However, there are many difficulties in the cementing involves in the reconstruction of depleted gas reservoirs, such as poor borehole quality, a long primary cementing section, and high cementing quality requirements and difficulty levels. Therefore, it is necessary to analyze effective cementing techniques. During drilling and completion, there are many factors that lead to reservoir pollution, which reduces the permeability of the formation near the wellbore and ultimately affects the permeability of the gas injection and production in the later stage of gas storage operation. Thus, it is necessary to analyze the mechanism of and specific measures used to prevent reservoir damage. In addition, circulation loss is a complex downhole problem that is often encountered during oil drilling. It not only affects the normal operation of the drilling operations, but it also often leads to other types of downhole complexity,

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which may cause collapse, sticking, blowouts, and other adverse consequences and can cause a substantial increase in the drilling costs. Most of the gas storage space is fractured and vuggy, so it is difficult to seal the lost circulation under pressure when the lower reservoir has been drilled through. These problems need to be solved.

Reservoir Protection Technique Reservoir Damage Factors During Drilling and Completion The reservoir damage factors involved in the drilling and completion of a gas storage facility include internal gas reservoir damage factors and engineering factors.

Internal Gas Reservoir Damage Factors Internal gas reservoir damage factors are studied and identified by conducting core sensitivity tests coupled with the analysis of the potential reservoir sensitivity based on the geologic data and analytical data for the reservoirs. 1. Potential water sensitivity damage to reservoirs Taking the Dagang gas storage facility as an example, the lithology of the gas-bearing reservoirs is mainly lithic feldspar siltstones and fine sandstones. Argillaceous substances account for about 50% of the cements, and the cementation type is mainly contact type cementation. The content of the clay mineral montmorillonite is high in the gas-bearing reservoirs. If the external fluids are not compatible with montmorillonite, this can cause hydration swelling of the clay and thus reservoir damage. In addition, according to the X-ray diffraction analysis, the clay minerals in the Dagang gas storage space are mainly montmorillonite with secondary intergranular kaolinite, grain surface illite, and chlorite (for specific data, see Table 1), and they have potential water sensitivity characteristics. After water sensitivity damage occurs to the mid-low permeability reservoirs, their effective permeability will decrease. The reservoirs of the Dagang Bannan gas storage facility have porosities of 10.2– 29.3% (generally 20–25%) and permeabilities of 15.4 mD. For the lithology with good physical properties, the maximum connected pore radius is up to 10.62 μm, and the average throat radius is 6.49 μm. For the lithology with medium physical Table 1 Clay mineral contents of the reservoirs Relative clay mineral content (%) Horizon Ban-II 1

S 57.1

I/S 6.6

I 2.5

K 21.9

C 11.9

Mixed-layer ratio 78

Total of the clay mineral contents(%) 6.53

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properties, the maximum connected pore radius is 3.1 μm, and the main throat radius 1–5.4 μm. For the lithology with the worst physical properties, the maximum connected pore radius is 0.88 μm. Due to the small rock pore throats, the solid particles (the size of the clay particles is greater than 20 μm) in the drilling fluids have difficulty entering the deep part of the pore throats due to the bridging theory. Therefore, the main damage factor is the infiltration of filtrates under a high pressure difference. After the infiltration of the filtrates, water sensitivity damage may occur due to the characteristics of the reservoir rocks. 2. Potential leakage damage to partially mid-high permeability reservoirs The reservoirs of the Dagang Ban-876 gas storage facility have an average porosity of 21.1%, an average permeability of 164.5 mD, and a maximum permeability of 2489 mD (according to the analysis of the cores from well K2-4). If the anti-leakage measures used during the drilling of the highpermeability interval are improper, circulation loss occurs easily, causing deep reservoir damage induced by invasion of solids and polymers.

Engineering Factors for Gas Reservoir Damage 1. Completion fluid and cement slurry property factors Improper drilling fluid properties will induce water sensitivity, water lock, chemical incompatibility, and solid blockage. The cement slurry causes water lock damage, alkali sensitivity damage, solid particle invasion damage, and chemical incompatibility damage to gas-bearing reservoirs. Improper perforating fluid properties, i.e., the invasion of the solid phase and liquid phase into perforations, reduce the absolute permeability of the gas-bearing reservoirs and the relative oil-gas permeability. If the perforating charges have penetrated a zone damaged by drilling, the perforating fluids not only further damage the zone damaged by drilling , but they also result in damage to the non-damaged formations outside of the zone damaged by drilling. 2. Engineering factors The drilling engineering factors cause the solid phase and liquid phase to invade the deeper parts of the reservoirs, and they aggravate reservoir damage. A high pressure difference directly affects the filter loss and invasion depth of the drilling fluid filtrates and makes it easier for solid particles to invade the reservoirs. The longer the soaking time, the larger the quantity of the solid and liquid phases of the drilling fluids that invades. The higher the annular up-hole velocity, the more serious the drilling fluid erosion is to the borehole wall mud cakes, the larger the dynamic filter loss of the drilling fluids, and the larger the invasion depth of the solid and liquid phases. The cementing quality factors lead to incompatibility between the series of well fluids and induce various types of damage, such as the formation of organic scales

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and inorganic scales, water locking, emulsification blockage, bacterial blockage, particulate migration, and changes in phase permeability, thereby damaging the gas-bearing reservoirs and affecting the production. Additional damage can be caused by unreasonable perforation completion process parameters. During the perforation process, a compaction zone with an extremely low permeability (permeability Kcz of about 10% of the original permeability Ke) is formed in the ~12.7 mm (1/2 in) thick fracture zone around the perforations, thereby significantly reducing the productivity of the perforated wells.

Reservoir Protection Measures for Drilling and Completion Engineering 1. Reservoir protection measures during drilling Reservoir protection measures taken during drilling are mainly considered in terms of multiple aspects, such as the drilling engineering design, drilling fluid property control, and drilling engineering management. Before creating the drilling engineering design, the three pressures should be accurately predicted in order to optimize the whole structure, determine a reasonable drilling fluid density, and avoid damage to the deep reservoirs caused by drilling fluid filtrates under high density and high pressure differential conditions. The selection and field application of drilling fluid systems should be considered first in order to prevent invasion damage caused by the solid particles and filtrates in the drilling fluid. Before entering the reservoirs, the drilling equipment should be checked to ensure its normal operation, the various materials and tools required should be prepared, the various working procedures should link up well, the ROP should be increased, the gas-bearing reservoirs should be penetrated quickly, logging items should be optimized, and the reservoir soaking time should be reduced. A reservoir protection supervision system should be established and perfected. All of the construction personnel should come to a consciousness regarding the reservoir protection measures taken.

Reservoir Protection Measures During Cementing The reservoir protection measures taken during cementing are mainly considered in terms of multiple aspects, such as the cementing methods, operation parameters, and cement slurry properties. A proper cementing method should be chosen and the circulation pressure during cementing should be calculated in detail to prevent the cement slurry from leaking and causing reservoir damage. The analog computation of the circulation pressure during cementing should be performed, and the displacement and pump pressure should be limited to prevent too high circulation pressure from causing reservoir leakage.

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The control of the filter loss of the cement slurry should be strengthened, and the free liquid content of the cement slurry should be maintained at 0 and the filter loss at 50 ml.

Reservoir Protection Measures During Perforation The reservoir protection measures taken during perforation are mainly considered in terms of aspects such as the perforation technique, perforation parameters, and perforating fluid properties. (1) Perforation technique selection The negative differential pressure perforation technique should be used, and a reasonable negative differential pressure value for the perforation should be selected to ensure that the perforations are completely clean and unobstructed. This is because the fluids in the gas-bearing reservoirs flow into the wellbore at the moment the perforations are formed, which has a cleaning effect on the perforations. (2) Optimization of the perforation parameters The perforation parameters mainly include the perforation depth, perforation density, perforation diameter, phase angle, and compaction damage. As the scientific and technological level increases, the research into the impacts of the perforation parameters on productivity has also gradually deepened. Two main research methods are used: (1) the electrolytic model simulation method and (2) the numerical simulation method. (3) Optimization of the perforating fluids The gas-bearing reservoir damage caused by the perforating fluids includes two aspects: solid particle invasion and liquid phase invasion. The basic requirements of the perforating fluids are as follows: to ensure its compatibility with the rocks and fluids in the gas-bearing reservoirs, to prevent further damage to the gas-bearing reservoirs during the perforation and subsequent operations, to meet the perforation operation requirements, and to achieve low costs and convenient preparation. The perforating fluid property requirements are as follows: the pressure coefficient of the gas-bearing reservoirs is low during construction of a gas storage facility from a depleted gas reservoir. Therefore, the design focus of the perforating fluids is to control filter loss, prevent water sensitivity, and improve the cutting carrying performance. Recommendation of a perforating fluid systems: The current typical perforating fluid systems mainly include the solid-free brine system, the solid-free polymer system, the polymer temporary plugging system, the oil-based perforating fluid system, and the acid-based perforating fluid system.

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Complete Sets of Pressure Sealing Techniques for Gas Storage Construction Circulation loss is a downhole problem often encountered during petroleum drilling. It not only affects the normal drilling operations, but it also tends to cause other types of downhole problems. Serious circulation loss can cause severe consequences, such as hole sloughing, pipe sticking, and blowouts, and a significant increase in drilling costs. The formations in most gas storage facilities are fractured and porous formations. The lower reservoirs that easily leak are penetrated for intermediate casing cementing, so it is difficult to stop the leakage under pressure.

Research on the Pressure Sealing Mechanism In drilling engineering, the formation’s fracturing pressure is often taken as a sign of the formation’s pressure bearing capacity, that is, the pressure caused by the drilling fluid column’s pressure (static + dynamic) can fracture the formation, causing leakage. It is evaluated in terms of leakage or no leakage. The formation pressure or bearing capacity refers to the ability of the wellbore formation to prevent (bear) hydraulic fracturing caused by the drilling fluid column, which would lead to leakage during the drilling and completion stages.

Occurrence Mechanism of Formation Fracturing (Low Pressure Bearing Capacity) There are defects and flaws on the surface of the borehole wall’s formation rocks, including cleavage planes, bedding planes, and fissures (which can guide the liquid phase into the formations) in the formation rocks. Various micro-fractures naturally exist in formations, and those that form on the borehole wall during drilling are referred to as prominent defects and flaws. pmud (static + dynamic) is larger than the tensile strength of the formation rocks (the tensile strength of rocks that are mainly brittle is not large). In addition, pmud (static + dynamic)>Pformation. pmud is the drilling fluid column pressure, and Pformation is the formation’s fracturing pressure. Due to the positive pressure difference between the formations, the drilling fluids or drilling fluid filtrates enter the formations along the fractures. If the velocity of the entry of the liquid phase of the drilling fluids as they enter the fractures is larger than the velocity of the filtration loss of the liquid phase of the drilling fluids along the fracture surfaces, the volume of the liquid phase in the fractures continuously increases, tensile stress (its magnitude depends on pmud and the fracture surface size) is generated in the formations along the direction parallel to the fracture surfaces, and stress concentration occurs at the tips of the fractures.

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When this stress is greater than the tensile strength of the formations, hydraulic wedging occurs. The tips of the fractures continue to develop and spread towards the deeper parts of the formations, forming induced fractures and fracturing the formations. In addition, the fractures continuously expand, and their opening degree increases in order to reach the leak-induced width. Moreover, the length of the fractures increases, and they extend towards the inside, finally connecting the leakage passages inside the formations and causing to leakage. This shows that the formations are fractured and fail to bear the pressure.

Causes of Formation Fracturing or Low Pressure Bearing Capacity (Failure to Bear Pressure) Formations have defects and flaws, and the impact of various micro-fractures is particularly prominent. pmud is greater than the tensile strength of the rocks. The Differential pressure of the drilling fluid column on the formations is positive. The velocity of the liquid phase of the drilling fluids as it enters the fractures is greater than the velocity of the filtration loss along the fracture surfaces. Therefore, the fundamental reason for formation fracturing or a low pressure bearing capacity (failure to bear pressure) is the result of the hydraulic wedging of the drilling fluid column’s pressure on the various existing fissures and fractures in the formations, and it is not necessarily related to the type of formation rocks (i.e., the mineral composition).

Natural Vertical Fractures, Micro-fractures, and Induced Fractures (1) Natural vertical fractures with widths of greater than 0.1–0.2 mm Natural vertical fractures (referred to as natural leak-induced fractures) with widths of greater than 0.1–0.2 mm and that can directly cause drilling fluid leakage are distributed throughout the formations. When such fractures are drilled and there is a positive pressure difference, leakage occurs immediately. pformation can be regarded as the leakage pressure, and the leakage velocity is determined by factors such as the fracture width, fracture length, leakage area, positive pressure difference, drilling fluid rheology, drilling fluid pump pressure, and displacement. Theory and practice show that if the total length of a 0.5 mm wide fracture reaches a few meters, it can cause significant leakage. When the leakage is unobstructed, the drilling fluid column’s pressure is high, the positive pressure difference is large, the high pressure of the drilling fluid column is transmitted into the fractures, the pressure is large enough to cause the fractures to further open and expand (i.e., the naturally lead-induced fractures expand due to induction), the leakage velocity is increased, and the leakage worsens. Therefore, such leakage must be stopped in time. Timely and effective

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plugging of this part of the natural leak-induced fractures and resolving the resulting leakage problem are the primary tasks in drilling such formations. When severe leakage occurs immediately after drilling through large fractures (greater than 2 mm), the drilling must be stopped until the leakage is stopped. Thus, stopping the severe leakage that occurs in fractured formations is a difficult problem. Drilling of small bridge plug fractures (less than 2 mm): For the case in which the leakage gradually decreases or even stops during the drilling (circulating), normal drilling can be maintained, but the formations do not necessarily have a higher pressure bearing capacity. After this, the leakage is gradually aggravated and even worsened during drilling (circulating). (2) Natural vertical micro-fractures (micron level) with widths of less than 0.1 mm When these fractures are drilled, leakage cannot be directly induced, and thus, they are called non-leak-induced natural fractures. However, the liquid phase of the drilling fluids enters the formations under the action of the positive pressure difference, and hydraulic wedging occurs in the formations due to the high pressure of the drilling fluid column, and thus, fractures are generated, opened, and expanded to a leak-inducing degree, thereby resulting in (induced) leakage. In the same way, the continual action of the too high positive pressure of the drilling fluid column may lead to further opening and expansion of the fractures, and therefore, the leakage velocity may continue to increase (inducing further leakage). (3) Induced fractures The entry of the liquid phase of the drilling fluids into the formations due to the positive pressure difference and the induced leakage resulting from the hydraulic wedging caused by the high pressure of the drilling fluid column affect the various fractures (including plugged fractures). This action may occur at any position on the borehole wall within the drilled interval (including fractured that have leaked and then been plugged and fractures that have not leaked) at any time during and after drilling, so leakage occurs and is worsened and the entire interval fails to bear pressure. This is also the main reason why multi-point leakage and repeated leakage occur throughout the entire interval. Other positions may leak after the leakage at one position stops, and the position of the leakage point does not exhibit regularity. Leakage caused by pmud > pleak and leakage caused by pmud > pfracture often coexist. pleak is the formation leakage pressure; and pfracture is the formation’s fracturing pressure. That is, the problem of a low formation pressure bearing capacity is often the result of a combination of the two types of leakage.

Wellbore Strengthening Technique At present, pressure sealing techniques have been studied in detail in many countries. In the 1990s, the concept of wellbore strengthening was first proposed, and then some scholars proposed the stress cage model to describe the wellbore

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Fig. 1 Description of the wellbore strengthening phenomenon using the stress cage model. ( pt - in-situ stress; pp - formation fracturing pressure; pm - drilling fluid column’s pressure)

strengthening phenomenon (Fig. 1). When the drilling fluid column’s pressure is greater than the formation’s fracturing pressure, a fracture will be generated. After the fracture is formed, solid particles and filter cakes quickly block the fracture near the wellbore and become wedged into the fracture, thus compressing the formation. In this case, the drilling fluid column’s pressure acts on both sides of the fracture near the wellbore’s end through the wedging motion, forming a compression ring, i.e., a stress cage. The generation of this stress cage increases the wellbore’s strength. When the drilling fluid column’s pressure is greater than the closure pressure at the tip of the fracture, leakage will occur. Therefore, preventing the transmission of the fluid column’s pressure to the fracture tip is the key to leakage stoppage under pressure.

Selection of Circulation Loss Materials In order to plug the tip of a fracture, the bridging materials must deeply enter the fracture as far as possible to form a bridge. In addition, high fluid loss materials quickly end filtration loss so as to deposit a very thick filter cake in the fracture. Once the fracture is filled with this tough filter cake, the wellbore’s strength will increase.

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The properties of most bridging materials are basically unchanged below 120 °C, but the properties of some materials change at temperatures of greater than 120 °C. When the temperature reaches 180 °C, the strengths of walnut shells, bagasse, and chaff decrease; and sawdust, paper scraps, and cottonseed hulls are partly scorched. Therefore, in order to improve the temperature resistance of bridging materials, it is necessary to develop bridging materials with a temperature resistance of more than 200 °C. At present, the main material types used include rigid granular materials, elastic granular materials, fibrous materials, deformable filling materials, and high fluid loss materials.

Cementing Technique for Gas Storage Facilities Constructed from Depleted Gas Reservoirs Gas storage facilities have characteristics such as high construction costs, long life cycles (50 years), and strict safety requirements. Cementing engineering is the core technique in gas storage construction. In response to the difficult problems involves in converting depleted gas reservoirs into gas storage facilities, including the complex geologic conditions, poor hole quality, long sections cemented at once, and high requirements for cementing quality, a tough expansive cement slurry system reaching the advanced world level and a DRC high-efficiency flushing spacer fluid have been developed, technical specifications for the cementing of underground gas storage facilities constructed from oil and gas reservoirs have been produced, and complete sets of cementing techniques centering on balanced pressure cementing and guaranteed wellbore sealing for gas storage spaces have been developed. The tough expansive cement slurry system and the complete sets of cementing technologies have been successfully applied in the Huabei Suqiao, Chongqing Xiangguosi, Xinjiang Hutubi, Dagang Bannan, Liaohe Shuang-6, and Changqing gas storage facilities, and the difficult problems, such as the large difficulties in ensuring cementing operation safety, the poor cementing quality, and the failure to effectively ensure wellbore sealing, have been solved, thereby laying a foundation for the safe operation of gas storage facilities.

Particularity of and Difficulties Involved in the Cementing of Gas Storage Facilities Constructed from Depleted Gas Reservoirs The life cycle of a gas storage facility is long (50 years), which is equivalent to the time it takes to build up one gas field and mine it out within 1 year. Gas storage facilities are located in densely populated regions and have high requirements in terms of wellbore sealing properties and cementing quality. If gas channeling occurs in the wells of a gas storage facility, there are large difficulties in the annular treatment under pressure, the cost is high, and the risks are high, and they can even affect the safe operation of an entire gas storage group. It can be said that the

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cementing quality is closely related to the service life and long-term safe operation of a gas storage facility, and it is the core technique in gas storage construction. 1. Characteristics and quality requirements for injection and production wells in gas storage facilities The effective working gas volume of a gas storage facility constructed from a depleted gas reservoir needs to be produced within a very short period of time (3– 4 months in general). In addition, the gas storage needs to be filled up with gas within 6–7 months in order to reach its full storage capacity. The wells in gas storage facilities have a long life and the pressure in the wellbore changes frequently. Therefore, ensuring the safe operation of gas storage wells is the first principle of gas storage construction. The wells in gas storage facilities need to withstand the alternating loads caused by gas injection and gas production during operation, and they have high requirements in terms of the primary cementing quality and wellbore sealing properties (casing strings and cement sheaths). If the cementing quality of a single well is poor, it can affect the safe operation of the entire gas storage group. In addition, if gas channeling occurs, there are large difficulties in the treatment under pressure, the management is complicated, and the cost is high. In various gas storage engineering operations, the cementing quality is closely related to the life and long-term safe operation of the gas storage facilities. A good annular sealing property should be achieved first in order to ensure the long-term safe operation of the gas storage wells and to ensure that no serious accidents such as annulus under pressure or natural gas leakage occur. 2. Difficulties in gas storage cementing and early problems During the 25-Year Plan period, China began to construct the Huabei Suqiao, Dagang Bannan, Changqing, Chongqing Xiangguosi, and Liaohe Shuang-6 gas storage facilities. The target formations of these gas storage facilities included sandstone formations and carbonate formations. In addition, the formation pressure coefficients were 0.1–0.9, the pressure was generally low, the formation pressure-bearing capacity was low, and the section cemented at one time was long, thus posing severe challenges in terms of the safety of the cementing operations and in guaranteeing the cementing quality. (1) Main technical difficulties in the cementing of gas storage facilities in China It is difficult to develop a tough cement that is suitable for gas storage cementing, has a good comprehensive performance, and can guarantee the cementing quality and long-term sealing properties. It is difficult to improve the displacement efficiency and ensure good interface cleaning under the conditions of a complex wellbore and long cemented sections. It is difficult to choose supporting site techniques that will ensure both construction safety and cementing quality. It is difficult to ensure wellbore sealing under the conditions of intensive cyclic injection and production of gas storage wells.

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There are no cementing quality evaluation specifications and cementing technique specifications suitable for gas storage facilities, resulting in a lack of guidance for the design, construction, and quality evaluation of gas storage facilities. (2) Main technical difficulties in the cementing of ultra-deep gas storage facilities in China Taking the Huabei Suqiao gas storage facility as an example, it has a large well depth, a high bottom hole temperature, and the burial depth of the reservoirs is up to 5500 m. It is the gas storage with the highest temperature and the most complex geologic conditions in the world at present, thereby imposing higher requirements for cementing techniques, cementing tools, cement slurry, prepad fluid systems, supporting cementing measures, and site construction. The hole structures of the directional wells and horizontal wells of the Huabei Suqiao gas storage facility are shown in Figs. 2 and 3. It is difficult to improve the displacement efficiency. The effective displacement of the drilling fluids is seriously affected by factors such as complex geologic conditions, easy formation collapse, a low pressure bearing capacity, and the difficult adjustment of the drilling fluid’s properties. It is difficult to optimize the formula of a high-performance cement slurry. It is difficult to optimize the high-performance additives and cement slurry systems because of the high bottom hole temperature, the long section lengths cemented at once, and the large temperature difference between the top and bottom of a cement slurry column. It is difficult to ensure safe cementing construction. Due to the low pressure bearing capacity and easy leakage of the formations in the Suqiao gas storage facility, the density of the cement slurry and the construction displacement are limited, and problems such as cement slurry leakage and the channeling of drilling fluids easily occur during slurry displacement. It is difficult to ensure the sealing properties of the cement sheaths. The cement sheaths need to withstand repeated changes in gas injection pressure of up to 49 MPa and alternating stress, thereby requiring the set cement to have a high strength, elasticity, toughness, and compactness. Therefore, it is difficult to ensure the longterm sealing properties of cement sheaths under high temperature conditions. Foreign countries have more than 50 years of gas storage cementing experience and have developed supporting cementing techniques. However, foreign gas storage facilities have relatively small well depths, relatively simple geologic conditions, and low bottom hole temperatures. Foreign countries have not developed techniques for the cementing of geologically complex, deep gas storage facilities such as the Huabei Suqiao gas storage facility. Practice has demonstrated that the techniques developed abroad are not completely suitable for the cementing of the gas storage facilities in China. Therefore, independent innovation and the development of new techniques for the cementing of gas storage facilities in China are needed. These new techniques should be able to ensure the cementing quality of the gas storage

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Fig. 2 Schematic of the hole structure of a directional well in the Huabei Suqiao gas storage facility

facilities, to support the construction of gas storage facilities, and to reduce gas storage construction costs.

Tough Cement 1. The purpose and role of developing tough cement (1) Definition of tough cement The development of high-performance toughened materials and tough expansive cement and the modification of set cement are the keys to

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Fig. 3 Schematic of the hole structure of a horizontal well in the Huabei Suqiao gas storage facility

ensuring wellbore sealing in gas storage facilities. Tough cement has a larger deformation capacity than ordinary oil well cement under the same stress state. The main mechanical characteristics of tough cement are as follows. The Young's modulus of tough cement is significantly lower than that of ordinary oil well cement, and there is a small difference in their compressive strengths and tensile strengths. (2) Main difficulties in the development of tough cement The technical key to the development of tough cement is to optimize toughened materials with good comprehensive properties. In order to select

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suitable toughened materials, the following three problems need to be solved. The contradiction between increasing the toughness of a set cement and its compressive strength: increasing the amount of toughened materials reduces the Young's modulus of the set cement, but it will also reduce its compressive strength. The contradiction between the use of tough cement and safe construction: when the quantity of toughened materials added is small, the degree by which the toughness of the set cement is increased is limited. The addition of a large quantity of toughened materials will affect the uniformity of the cement slurry’s density and the smooth pumping of the cement slurry during cementing. The contradiction between the compatibility of the additives and elastic materials: the cement additives should be compatible with the toughened materials, the stability of the cement slurry should be good, the volume of the set cement should not shrink, and the early strength should develop quickly and have a long-term stability. Otherwise, the slurry, set cement, and its sealing properties will be affected. The developed suitable tough expansive cement should be able to ensure both safe construction and short-term (24–72 h) and long-term cementing quality, and the set cement should have a high compressive strength, a low elastic modulus, a strong impact resistance, and should be compatible with the formation’s lithology. 2. Measures and precautions in the use of tough cement When tough cement is used, appropriate and ideal elastic materials should be selected. The requirements for the properties and particle size of an ideal toughened material are as follows. It has a good affinity for the cement slurry, that is, it is soluble in the cement slurry system. It has good elastoplastic properties, that is, it enhances the elastic properties of the set cement without destroying the other properties. It has a good temperature and alkali resistance. It has a good particle size distribution, that is, it can be uniformly dispersed in the cement slurry system. It is compatible with the additives in the cement slurry; i.e., it has no side effects. 3. Technical scheme and main performance requirements for tough cement (1) Determination of the elastoplastic modification scheme for set cement In order to improve the liquid state performance and toughness of set cement, the designed tough cement consists of toughened materials, ultrafine active materials, and matching additives. The toughened materials are mainly used to improve the toughness of the set cement. In addition, the toughened materials are compatible with the cement slurry and with the other additive systems. The purpose of adding ultra-fine active materials to the cement slurry is to improve its suspension stability, increase the solid

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content and compressive strength of the set cement, and improve the overall performance of the cement slurry. Based on this, the properties of the cement slurry and the set cement are adjusted according to the specific well conditions, thereby meeting both the safety construction requirements and the need for long-term safe operation under the conditions of annulus isolation and long-term alternating loads. (2) Main properties of tough cement Through detailed and continuous research, four high-performance toughened materials for use in set cement have been developed in China, and they are used in DRE medium temperature tough expansive cement (30–100°C) and high temperature tough expansive cement (100–200°C). – The applicable temperature of the medium temperature toughened material is 30–120°C. It has a strong alkali resistance (pH of 11–14), is compatible with the cement slurry additives, has a small impact on the thickening time of the cement slurry, and is compatible with the set cement matrix. – The applicable temperature of the high temperature toughened material is 90–200°C. It has a strong alkali resistance (pH of 11–14), is compatible with the cement slurry additives, has a small impact on the thickening time of cement slurry, and is compatible with the set cement matrix. – The adjustability of the thickening time of the low-density tough cement slurry system is good. Within the range of the temperature difference, it has a compressive strength of greater than 10 MPa/48 h, an elastic modulus of less than 4 GPa/7d, a permeability of less than 0.05 mD, and a linear expansion rate of greater than 0. – The adjustability of the thickening time of the conventional density tough cement slurry system is good. Within the range of temperature difference, it has a compressive strength of greater than 16 MPa/48 h, an elastic modulus of less than 6 GPa/7 d, a permeability of less than 0.05 mD, and a linear expansion rate of greater than 0. 4. Tough cement and its main properties Due to the existence of certain pores in set cement, the particles of added toughened materials fill the pores, forming bridges and inhibiting the development of fissures. When external forces act on set cement, the toughened materials reduce the transmission coefficient of the external action due to their low elasticity modulus, and they weaken the external action’s destructive force on the set cement matrix, thus achieving the purpose of protecting the mechanical integrity of the set cement. Based on the above principle, a large number of laboratory experiments have been performed. The four toughened materials developed (DRT-100L, DRT-100S, DRE-100S, and DRE-200S) for use in set cements can be used at a maximum temperature of 200°C, and the elastic modulus of the set cement added containing the toughened materials is 20–40% lower than that of conventional set cement. (1) Selection of fluid loss additives

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Table 2 Influence of fluid loss additive DRF-300S on the performance of the cement slurry Quantity of DRF-300S added (%) 0 1.2 1.6 2.0 2.5 0 1.2 1.6 2.0 2.5

Temperature (°C) 50 50 50 50 50 70 70 70 70 70

Water cement ratio 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44

Thickening time (min) 118 142 145 146 152 90 118 114 120 127

Compressive strength (MPa/24 h) 17.4 17.6 18.0 18.1 17.9 20.1 21.2 21.5 20.8 21.0

At present, the fluid loss additives commonly used in China can be divided into two types according to the mechanism of fluid loss: ultra-fine solid particle materials and water-soluble polymer materials. The PVA (polyvinyl alcohol) fluid loss additive DRF-300S and the AMPS (2-acrylamido-2-methylpropane sulfonic acid) fluid loss additive DRF-120L are suitably used as matching fluid loss additives based on the comprehensive consideration of their effect, and sensitivity, adaptability according to the cementing requirements of wells in gas storage facilities constructed from depleted gas reservoirs. The DRF-300 fluid loss additive has excellent fluid loss control properties. The addition of more than 2.0% (BWOC) of DRF-300 can keep the API (American Petroleum Institute) filter loss to 50 ml and can meet cementing requirements very well. In addition, DRF-300 has a small impact on the compressive strength and thickening time of the cement and can effectively improve the stability of the cement slurry (Table 2). The fluid loss additive DRF-120L can still keep the API filter loss of the cement slurry to 100 ml at high temperatures; however, it has a certain setting retardation property at low temperatures. Therefore, DRF-120L is used in cooperation with other additives to adjust the filter loss of cement slurry. As is shown in Table 2, the addition of DRF-300S at 30–70°C has a small influence on the thickening time of the cement slurry, and it has almost no influence on the strength development of the set cement. (2) Optimization of the toughened materials – Latex DRT-100L and latex powder DRT-100S. Both latex DRT-100L and latex powder DRT-100S play a certain role in anti-channeling and toughening. When the temperature is less than 120°C, the latex powder maintains a good elasticity and plays a certain filling role, and the latex still has a high performance at high temperatures. Therefore,

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Table 3 Evaluation of the mechanical properties of set cements at different confining pressures Cement slurry system Pure cement Pure cement Pure cement Latex cement Latex cement Latex cement

Length (mm) 50.50 50.29 49.86 51.10 51.21 51.036

Diameter (mm) 24.89 24.89 24.82 25.02 25.02 24.94

Confining pressure (MPa) 0.1 20 40 0.1 20 40

Elastic modulus (GPa) 7.90 5.4 3.7 5.0 3.7 2.7

Maximum axial stress (MPa) 30.08 58.28 52.28 20.71 39.55 33.72

Postexperiment state Damaged Undamaged Undamaged Damaged Undamaged Undamaged

latex powder DRT-100S is used at medium and low temperatures and latex DRT-100L is used at a high temperatures to improve the anti-channeling property and toughening property of the cement slurry (Table 3). – Toughening materials DRE-100S and DRE-200S The toughening materials DRE-100S and DRE-200S reduce the brittleness of set cement by filling the pores with rubber particles. The stretching effect of DRE-100S can prevent the development of fractures, and it has a good elasticity. The DRE-200S material itself has a strong high temperature resistance. Therefore, DRE-100S is used at medium and low temperatures and DRE-200S is used at high temperatures to improve the toughness of set cement. According to a comparison of the fragmentation state of pure set cement and that of set cement containing DRE-100S after destruction, the addition of DRE-100S to the set cement reduced the brittleness of the set cement and it broke without fragmenting after destruction. This is because after it is dispersed in the set cement, the DRE-100S absorbs the stress and plays a role in arresting the development of cracks at the crack tips. In addition, because of its high elasticity, DRE-100S has a stretching effect on the generated crack.

Complete Sets of Cementing Techniques for the Construction of Gas Storage Facilities from Depleted Gas Reservoirs There are large difficulties in and high requirements for the cementing of the Huabei Suqiao, Chongqing Xiangguosi, Xinjiang Hutubi, Dagang Bannan, and Changqing gas storage facilities due to their complex geologic conditions and wellbore conditions, so it is difficult to ensure the safe construction and cementing quality of these gas storage facilities. In response to the cementing difficulties encountered in the construction of gas storage facilities from depleted gas reservoirs and the problems encountered in early-stage cementing, research has been conducted on cementing techniques, tough cement slurry systems, leakage prevention during cementing, cementing quality evaluation, ensuring wellbore sealing, preventing annulus under pressure, and supporting site cementing measures. Then, complete sets of cementing

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techniques suitable for use in constructing gas storage facilities from depleted gas reservoirs were developed, thereby laying the foundation for the long-term safe operation of gas storage facilities constructed from depleted gas reservoirs. 1. Hole preparation and drilling fluid property adjustment (1) Hole preparation A drilling fluid system should be optimized to prevent borehole wall instability, to ensure a regular hole diameter, and to create good wellbore conditions for cementing. The well trajectory monitoring should be strengthened to understand the changes in the hole deviation and the azimuth in real time and to ensure a smooth hole and a regular hole diameter during drilling. The hole diameter enlargement rate should be less than 15% in the well section of each spudding and 10% in the reservoir section. The maximum outer diameter and stiffness of the bottom hole assembly (BHA) during drifting before running the casing should be greater than the outer diameter and stiffness of the casing run in the hole. In order to ensure that the casing of the gas storage well can be run safely and smoothly, 3 rounds of drifting should be performed for a general well. One centralizer is used during the first round of drifting, two centralizers are used during the second round of drifting, and three centralizers are used during the third round of drifting to flatten the hole inflection points, destroy the cutting beds, and ensure an unobstructed hole. Thick mud with a funnel viscosity of about 120–150 s is used to carry the sand during the last round of drifting to remove the cuttings trapped in the non-round oversized hole and to ensure a clean wellbore. Full circulation is performed at a displacement 1.2 times that used during the drilling completion. (2) Drilling fluid property adjustment When the hole conditions permit, the drilling fluid properties should be properly adjusted before cementing to achieve a low viscosity and shearing force and a good rheological property. The recommended drilling fluid properties during the cementing operations are as follows. When the drilling fluid’s density is less than 1.30 g/cm3, the yield value is less than 5 Pa, and the plastic viscosity should be 10–30 mPa·s. When the drilling fluid’s density is 1.30–1.80 cm-3, the yield value is less than 5 Pa, and the plastic viscosity should be 22–30 mPa·s. When the drilling fluid’s density is greater than 1.80 g/cm3, the yield value is less than 5 Pa, and the plastic viscosity should be 40–75 mPa·s. 2. Technical measures for increasing the formation pressure-bearing capacity and their applications (1) Technical measures for increasing the formation pressure-bearing capacity Early treatment should be carried out, including strengthening the formation leakage stoppage measures under pressure and increasing the formation pressure-bearing capacity (carry out sealing immediately after the leaking begins, and change from one-time leakage stoppage under pressure to staged leakage stoppage while drilling).

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The drilling fluid properties and density should be adjusted with time according to the characteristics of the formation drilled, and leakage stoppage should be performed while drilling and leakage stoppage under pressure should be conducted to create good wellbore conditions for cementing. The formation pressure-bearing capacity should be tested before running the casing to meet the requirements of the expected pressure for running the casing and the cementing operations; otherwise, leakage stoppage operations should be performed. (2) Measures taken to increase the formation pressure-bearing capacity of the Liaohe Shuang-6 gas storage facility According to the formation characteristics and actual drilling conditions of the Shuang-6 gas storage facility, targeted technical measures for leakage stoppage while drilling and leakage stoppage under pressure were taken, and the drilling fluid properties and density were adjusted in a timely manner. Leakage stoppage measures were taken while drilling and biodegradable lost circulation materials were added to the drilling fluids while drilling, thus solving the leakage problems. In addition, attempts were made to increase the drilling fluid’s density to enable leakage stoppage while drilling. Before cementing midway through the drilling, leakage stoppage under pressure was performed according to the formula determined in the laboratory. Leakage stoppage under pressure was performed an average of 3–4 times for each well and the pressure-bearing capacity was increased from 1 MPa to 5.5–6.5 MPa, thereby ensuring safe cementing construction. (3) Measures taken to increase the formation pressure-bearing capacity of the Huabei Suqiao gas storage facility Leakage occurs easily in the glutenite strata of the Es Formation, the C-P coal measure strata, and the disclosed buried hill section in Huabei Suqiao gas storage facility. On the basis of carefully summarizing the previous experience in leakage stoppage gained from the construction of this gas storage facility, the formation pressure-bearing capacity was analyzed carefully, the leakage stoppage mode was changed from one-time leakage stoppage under pressure before cementing to staged leakage stoppage while drilling, thereby increasing the pressure-bearing capacity of the glutenite strata of the Es Formation, the C-P coal measures strata, and the disclosed buried hill section and creating good conditions for cementing. Through analysis and practical research, the method of improving the pressure-bearing capacity and achieving balanced-pressure cementing was adopted in the late stage. The pressure-bearing capacity is not affected by the hydrostatic column pressure, which was increased by the cement slurry. Instead, as long as the formation pressure-bearing capacity can reach more than 2 MPa, according to the part of the hydrostatic column pressure of the cement slurry exceeding the pressure-bearing capacity, the method of reducing the ahead drilling fluid density and the prepad fluid density is used, and the density is set to about 0.10 g/cm3 less than the drilling fluid density in order to achieve balanced pressure cementing, reduce the pressure-bearing requirements and the difficulty in leakage stoppage under pressure, save leakage stoppage time, and prevent hole diameter enlargement.

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3. Hermetic seal test technology for hermetically sealed casing and during casing running (1) Design and detection requirements for hermetically sealed casing used in gas storage wells The materials used to make the production casings used for gas storage wells should be designed according to the properties of the reservoir fluids, the properties of the external gas, and the injection and production technique in order to meet the requirements of the corrosion conditions. The production casing should use hermetic seal threads, the upper layer of the intermediate casing should use hermetic seal threads, and the mechanical parameters and thread sealing property of the casing accessories should match those of the casing. In order to ensure the hermetic sealing property of the hermetic seal threads, the casing running operation should be completed with special tools, and reasonable make-up parameters should be adopted according to the hermetic seal test (helium test) results. The production casing should be subjected to individual site hermetic seal tests of the threads, and the test pressure should be 1.1 times the maximum operating pressure of the gas storage facility. (2) Hermetic seal testing method The hermetic seal testing method is an effective means of ensuring the longterm sealing integrity of a casing string. Both the intermediate casing and the production casing of the gas injection and production wells of a gas storage facility are subjected to hermetic seal testing to ensure the sealing property of the threads of each piece of casing run in the hole and to minimize the potential risk of accidents caused by the failure of the casing threads. For example, the TP-CQ hermetic seal thread casing was used for φ244.5 mm liner cementing of well XC-8 in the Chongqing Xiangguosi gas storage facility and a total of 26 pieces of casing with unacceptable hermetic seals were found during the casing running. Hermetic seal testing of 8 wells and 576 threads was completed for the Xinjiang Hutubi gas storage facility in 2011. Thirty-five leaking threads were found, and 1 piece of casing (φ177.8 mm casing tieback) was replaced due to leakage after thread tightening. Hermetic seal testing of 23 wells and 6608 threads was completed in 2012. Two hundred and twenty leaking threads were found, and 16 pieces of casing (φ177.8 mm casing + φ244.5 mm casing) were replaced due to leakage after thread tightening. The potential risk of accidents caused by casing thread leakage was significantly reduced after the hermetic seal testing of the casing. 4. Main measures for improving displacement efficiency and site construction (1) Comprehensive measures for improving displacement efficiency The number and mounting positions of the centralizers should be optimized to ensure the centering of the casing. Pre-flushing fluids with low viscosities and shearing forces should be used in cooperation with high-efficiency flushing spacer fluids (increasing their consumption). For oil-mixed drilling fluids, the spacer fluids should have a strong oil washing ability.

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An appropriate displacement should be determined according to the pressure bearing conditions of the strata, and a large displacement should be carried out instead of turbulence displacement. (2) Comprehensive measures for improving the cementing quality under the conditions of a narrow safety density window and a long cemented section A pressure bearing test should be conducted before cementing to improve the pressure-bearing capacity of the strata. Comprehensive measures should be taken to improve the displacement efficiency. The cement slurry formula with good comprehensive properties should be used. Matching balanced-pressure cementing construction techniques Effective measures are taken during site construction to reduce the impact of each factor on the cementing quality. The technology + management method is strictly implemented during site cementing construction. Their successful application in multiple wells demonstrates that the developed comprehensive supporting cementing techniques have correct and reasonable schemes, and they have obtained remarkable site application effects. (3) Main measures for site cementing construction The drilling fluid, prepad fluid, and cement slurry column structure should be optimized, and the balanced-pressure cementing technique should be used. The rechecking of the cement slurry on site should be improved. The reliability of the cementing tools and accessories should be ensured, and their inspection before RIH (run in hole) should be improved. Joint cement injection should be carried out using multiple cementing trucks, and the batch slurry mixing technique should be used to ensure the uniformity of the cement slurry’s density. The construction equipment and continuous construction should be ensured, and an emergency plan for cementing should be created.

Formulation of the Cementing Technique Specifications and Quality Evaluation Specifications for Gas Storage Facilities 1. Formulation of cementing technique specifications for gas storage facilities Based on the characteristics of the geology, gas reservoirs, drilling, and cementing of the gas storage facilities under construction and those scheduled to be built in the future, the Technical Specifications for Cementing of Reservoir Type Gas Storages (Tentative) (YK [2014] No.122) was created starting with the design, preparation, construction, and quality inspection links. These specifications were also provided for the first time. The specifications mainly include five parts: the cementing design; the casing, tools, and accessories; the cementing preparation; the casing running and cementing construction; and the cementing quality inspection and evaluation. The specifications were issued and implemented. These specifications are very important to strengthening cementing

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work management of gas storage facilities and to ensuring the cementing quality of all gas storage facilities constructed in the future. 2. Evaluation of the cementing quality of gas storage facilities constructed from depleted gas reservoirs The specifications for the evaluation of the cementing quality of gas storage facilities should be scientific and reasonable and should consider the differences between gas storage facilities and their continuity. Based on these specifications, problems with the cementing can be identified, and the cementing quality of gas storage wells can be comprehensively and objectively evaluated. (1) Evaluation basis: the relevant cementing quality requirements in the YK [2012] No. 32 Technical Requirements for Drilling and Completion of Reservoir type Gas Storages (Tentative). (2) The evaluation scope mainly covers the cementing quality of the intermediate casing within the caprock, the cementing quality of the production casing within the caprock, and the sealing quality of the effective caprock section. (3) The cementing quality of a gas storage facility is comprehensively evaluated in terms of three aspects: the caprock section cementing quality, the target interval cementing quality, and the entire section’s cementing quality. The cementing quality is scored as good (excellent), medium (acceptable), or poor (unacceptable). The electrical logging interpretation is based on the CBL/VDL (cement bond log/variable density log) interpretation, and the other interpretation results are comprehensively considered. The formulated cementing quality evaluation specifications for gas storage facilities have been applied to 76 completed wells in gas storage facilities, such as the North China Suqiao, Dagang Bannan, Liaohe Shuang-6, Xinjiang Hutubi, Chongqing Xiangguosi, and Changqing gas storage facilities. The specifications have been endorsed by the management, employers, and construction teams of these gas storage facilities, and they have now been fully promoted and applied.

Conclusions Reservoir protection measures are mainly considered in terms of multiple aspects, such as the drilling engineering design, drilling fluid property control, drilling engineering management, cementing methods, operation parameters, cement slurry properties, perforation techniques, perforation parameters, and perforating fluid properties. At present, the types of material used mainly include rigid granular materials, elastic granular materials, fibrous materials, deformable filling materials, and high fluid loss materials. The tough expansive cement slurry system and complete sets of cementing techniques have been successfully applied in the construction of many gas storage facilities in China.

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Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hermetic Seal Test Equipment for Tubing and Casing Threads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technical Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technique Principles and Equipment Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technical Breakthroughs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technological Measures for Running Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Identification of the Risks During Casing RIH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technological Guarantee Measures for Casing RIH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . The Efficiency of the Tubing and Casing RIH Operations Should be Improved . . . . . . . . . . Completion Tool RIH and Wireline Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Annulus Protection Fluid Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Packer Setting Through the Wireline Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Analysis and Evaluation of the Sealing Integrity of the Cement Sheath . . . . . . . . . . . . . . . . . . . . . . Gas Storage Well Operation Characteristics and Requirements for the Sealing Property of the Cement Sheath . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Analysis and Evaluation of the Sealing Integrity of the Cement Sheaths in Gas Storage Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Post-cementing Quality Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wellbore Safety Pressure Test Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wellhead Equipment Optimization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wellhead Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wellhead Safety Control System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Anticorrosion of the Tubing and Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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X. Ma (*) · G. Ding Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, China e-mail: [email protected]; [email protected]; [email protected] © Petroleum Industry Press 2022 X. Ma (ed.), Handbook of Underground Gas Storages and Technology in China, https://doi.org/10.1007/978-981-33-4734-2_28

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Abstract

With the extension of the injection and production operation cycle, the phenomenon of an annulus under pressure in natural gas wells and injection and production wells in gas storage facilities has become serious in China. In view of this situation, in order to maintain the wellbore’s integrity, in this chapter, a series of wellbore integrity measures based on 20 years of gas storage construction experience in China is proposed, including thread tightness detection, casing running process measures, cement sheath post evaluation, wellbore sealing testing, wellhead equipment selection, and corrosion protection. Specifically, the hermetic seal test equipment and techniques for the threaded connections of DRGLI tubing and casing are developed. This chapter introduces the wellbore integrity of horizontal injection and production wells in terms of string integrity and outer cement sheath integrity. The specific steps involved in the wellbore safety pressure test, a series of measures for wellhead equipment selection, and successful practices in China are described. After several years of continuous research and field tests, six domestic gas storage facilities have developed targeted tubular product selection procedures and methods for different corrosive environments in various oil and gas fields. Keywords

Hermetic seal test · Running casing · Cement integrity · Wellbore pressure test · Anticorrosion

Introduction It has been demonstrated that one of the important issues is the leakage of the threaded connections of the tubing and casing. Therefore, it is necessary to research and develop testing equipment and techniques for the evaluation of oil and casing thread connection gas seal with independent intellectual property rights in China. Production casing and tubing are the channels for gas injection and gas production in injection and production wells in the late stage; therefore, ensuring the safe and favorable running of the production casing and tubing in the hole is very important to the favorable implementation of subsequent operations. Since gas storage facilities have a long design life cycle (generally 50 years), during gas storage running, the cement sheath needs to bear the impact of the alternating injection and production loads for a long period of time, and the pressure in the wellbore changes frequently. Thus, there are high requirements for the primary cementing quality and long-term sealing property of the cement sheath of a gas storage well. In order to ensure the long-term safe operation of the gas storage facility, it is necessary to ensure the primary cementing quality, the sealing integrity, and the long-term sealing property of the cement sheath. In conclusion, it is necessary to systematically analyze the relevant measures and techniques for ensuring the wellbore’s integrity.

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Hermetic Seal Test Equipment for Tubing and Casing Threads Technical Background According to incomplete statistics, there are currently more than 2,000 high-pressure natural gas wells in service in China, and there are more than 300 injection and production wells in these gas storage facilities. With the extension of the injection and production operation cycle, the phenomenon of an annulus under pressure in natural gas wells and injection and production wells in gas storage facilities has become serious. One of the important reasons for this is the leakage of the threaded connections of the tubing and casing.

Technique Principles and Equipment Composition The hermetic seal test for the threaded connections of the tubing and casing is designed to determine the sealing property of the threads by testing the threads’ high-pressure helium gas permeability. The entire test operation process includes running a test tool with double packers into a tubing string or casing string, injecting helium-nitrogen mixtures into the test tool, and pressurizing the tool to set it, pressurizing to the specified test pressure value, and determining the sealing property of a threaded connection by detecting helium gas leakage outside the threaded connection using a highly sensitive helium gas detector[1]. The molecular diameter of helium gas is very small, and it easily permeates hermetically sealed threads, so this technique can be used to accurately determine the sealing property of the threaded connections of the tubing and casing. The core of the hermetic seal test for the threaded connections of the tubing and casing includes the single-thread test time, the test tool life, achieving detection under service conditions or not, safety improvement, and cost reduction. The principles of the technique are shown in Fig. 1. The hermetic seal test equipment for threaded connections of tubing and casing consists of a hydropneumatic power system, a pressurized energy storage system, a detection execution system, a control system, and an auxiliary system. The equipment is shown in Fig. 2.

Technical Breakthroughs In order to meet the needs of the Chinese market, the hermetic seal test equipment and technique for the threaded connections of DRGLI tubing and casing have been developed, so that China has the ability to independently design and manufacture the equipment for testing the threaded connections of the tubing and casing and for carrying out hermetic seal testing of the tubing and casing. The main technical innovations include two aspects.

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Fig. 1 Principle schematic of the hermetic seal test technology for the threaded connections of the tubing and casing

Fig. 2 Schematic of the hermetic seal test equipment for the threaded connections of the tubing and casing

1. Development of a set of hermetic seal test equipment for the threaded connections of the tubing and casing Compared with similar techniques and equipment in China and abroad, the developed hermetic seal test equipment includes features such as a compact system, simple installation, a short testing time, large pressure bearing times for the packer

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Table 1 Comparison of the hermetic seal test equipment for threaded connections of the tubing and casing of Chinese and foreign products Compared property Test pressure (MPa) Test accuracy (Pa•m3/s) Rubber life (times) Operation time Accumulator index Automation degree of data acquisition Safety

Foreign (Loomis, etc.) 140 1.0  10

8

Chinese or others Imitated products, no independent products, no pressure vessel use qualification

CNPC Drilling Research Institute 140 1.0  10

8

80

120

3 min

2 min 40 s

4–7 m  0.9 m  2 m

1 m  0.9 m  1.8 m

Manually read

Acquired using professional software

Safety is not high, and tools are easy to produce quickly

Adoption of compression type setting and asymmetrical unsetting design, high safety

rubber, a high unsetting safety level, a high operating efficiency, and accurate recording. The key technical indexes of the equipment have reached the advanced international level, thus solving the problems involved in the transportation, installation, and rapid testing. A specific comparison of this equipment with Chinese and foreign products is presented in Table 1. (1) The overall design + joint commissioning method is used to optimize the configuration of each component, so that the entire equipment system is compact, safe, and reliable. A vertical accumulator (Fig. 3) is used, thus achieving safer and more stable inflation, a small equipment volume (reducing length by 3–6 m), a small weight, and simple hoisting. The console (Fig. 4) is semi-closed to effectively isolate the draw works and other components from the operator and to ensure safety. (2) A new pipe-cable rapid connection mode is used. The gas injection and drainage parameters have been optimized, data acquisition software has been developed, and the site test efficiency has been improved. The control module (Fig. 5) uses air pipe cables and pinboards, which makes the site installation and operation simple and convenient. The size of the gas injection and drainage valves and pipelines has been optimized and improved, so that the pure test time is 160 s. A mathematical model of the helium-nitrogen ratio has been

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Fig. 3 Vertical accumulator effect

Fig. 4 Console effect

established, and data acquisition software (Fig. 6) that can collect, record, and save the original data in real time has been developed. 2. The concept of nonsimultaneous unsetting has been innovatively proposed. Compression type double packers have been designed, thus solving the technical problems posed by rubber being used at few sites and the easy and fast production of the tool and improving the service life and operation safety of the test tool.

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Fig. 5 Control module effect

Fig. 6 Data acquisition software interface

(1) Compression type packers have been designed, thereby changing the stress in the maximum stress mode and at the maximum stress position of the rubber from tension to compression, improving the stress environment of the rubber, and increasing its service life. (2) The nonsimultaneous unsetting design concept has been adopted, thus improving safety during packer unsealing. No accident of fast tool production of casing occurred during the site testing of more than 10,000 threads. Figure 7 shows a schematic of nonsimultaneous unsetting. (3) The rubber material’s formula, machining processing, and structural protection have been optimized in order to increase the service life of the rubber, which is up to 204 times the expansion setting testing. (4) A hermetic seal testing technique for the threaded connections of the tubing and casing under service conditions has been developed, thus ensuring the reliability of the test results and meeting the site operation requirements.

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Fig. 7 Schematic of the nonsimultaneous unsetting of packers

The main features of the testing technique include a sealing property test can be conducted on the threaded connections of the tubing and casing in a state of stress on the drill floor, the test conditions are closer to the actual service state of the tubing and casing, and the test results are more credible.

Technological Measures for Running Casing Production casing and tubing are the channels for gas injection and gas production in injection and production wells in the late stage; therefore, ensuring the safe and favorable running of the production casing and tubing in the hole is very important to the favorable implementation of subsequent operations. This is described by taking the Changqing gas storage facility as an example.

Identification of the Risks During Casing RIH Each horizontal injection and production well in the Changqing gas storage facility contains more than 300 pieces of production casing. Including the hermetic seal detection time of the string and the equipment maintenance time, the casing RIH (run in hole) operation time can reach 4–5 day, which is 1–2 day more than that of a conventional development well. The soaking time of the borehole wall in the open

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hole section increases, and thus, the risk of casing RIH increases significantly. If accidents such as borehole wall collapse occur and result in blockage and sticking of the production casing, there is a need for back-off to lift out the casing in some cases, thereby leading to damage or scrapping of a large quantity of casing. All of the casing of the gas storage facility is imported hermetically sealed anti-sulfur casing, e.g., super 13Cr, which is very expensive. In addition, the number of spare casing pieces is limited. The back-off conducted to lift out the casing results in huge economic loss and a great deal of operation time. Moreover, the risk of the subsequent remedial measures is also very high, and in serious cases, the wellbore is scrapped.

Technological Guarantee Measures for Casing RIH According to the casing RIH risk identification result, the key to ensuring favorable casing RIH is sufficient preliminary preparation work. The inspection work should be strict and meticulous, and all of the work should be carried out around the core to reduce the amount of unnecessary operation time. The overall idea of these guarantee measures is quick stabilization. The specific method is to attach importance to the details of each step of the operation, to prepare in advance, to strictly check the steps, to explain the technical details, and to focus on all of the parties involved in the construction. 1. Ensure a clean wellbore and a stable borehole wall. A good hole environment is the best guarantee for casing RIH. Importance should be attached to the following aspects during drilling and completion. (1) Based on the geologic design and early construction experience, the drilling and completion fluid systems should be optimized to ensure the borehole wall’s stability during the drilling process. (2) A great deal of attention should be paid to the well trajectory control technique to avoid a hole with severe doglegging. The construction must meet the requirements of the drilling engineering design for hole quality. (3) Before running the casing, drifting with multiple centralizers should be carried out in strict accordance with the engineering design. It should be confirmed that the hole is clean before proceeding to the next operational step. (4) The detection and analysis of the hole data should be improved. The hole diameter data and well trajectory data should be collected and analyzed through logging before running the casing in order to provide a basis for the installation of the casing centralizers. (5) Importance should be attached to the property parameters of the drilling and completion fluids before running the casing. It is strictly forbidden to adjust the drilling fluid’s properties and especially the drilling fluid’s density to a large extent, thus ensuring no leakage, no collapse, and no blowouts and maintaining the borehole wall’s stability. According to the actual wellbore conditions, if necessary, a certain amount of lubricants can be added to reduce the friction resistance while running the casing. The proportion added should take into account of the impact of the addition of the lubricant on the later cementing.

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Highly inhibitive thick slurry slugs can be injected into well sections where collapse and block falling easily occur or have occurred. 2. Preparation and inspection of the casing and the supporting tools in advance. The operation team should check all of the casings, joints, and subs; number all of the casings individually, accurately measure the casing lengths, drift all of the tubing and casing individually using a drift diameter gauge, and check the tubing and casing threads on the ground to ensure smooth tubing and casing. Before running the tools, the model, ID, OD, and the length of the tools to be run in hole should be measured and recorded on the engineering tour report form. The supervising party should supervise and recheck the accuracy of the data throughout the process, and the project supervisor should randomly check the implementation of the work and the data for consistency. (1) Key points of string data acquisition and inspection: The drilling crew and the geologic logging party jointly complete the numbering and measurement of the string, and the supervisor supervises the entire process. (2) Thread inspection key points: Note that any scratches, bump pits, and rust pits crossing the sealing surface are unacceptable defects. Any burrs on the thread entry surface and load bearing surface must be removed. Large pits on shoulders are also unacceptable. There should be no black leather or obvious pits within the thread length range. If there is severe corrosion of the casing body, the casing should also be replaced. (3) Key drift diameter inspection points: The drift diameter inspection should meet the requirements of the engineering design. Special attention should be paid to the outer diameter and length of the drift diameter gauge. All of the tubing and casing should individually be subjected to drift diameter inspection without omission. For safety reasons, before lifting the tubing and casing onto the drill floor, throw an ~1 m long cylinder with an outer diameter of 5–10 cm (such as a mop handle) into the tubing or casing to check for blockage and to prevent gloves, towels, and other items from entering the tubing and casing by mistake. (4) Key tool inspection points: After the tools arrive at the site, their number should be checked against the list. In addition, the material number and technical parameters should be individually checked to ensure correctness. The outer diameter, inner diameter, and length of the tools should be checked to ensure that they are undamaged and their type is correct. 3. The construction team should check and ensure that the wellhead and BOP (blowout preventer) are normal and effective. The ram should match the size of the string to be run in the hole, and it should pass a pressure test according to the design requirements to ensure that the wellhead is fastened without piercing and leakage and that the pressure gauges and weight indexes are complete and undamaged. The supervising party should supervise and check the work, make a record, and give a special report to the project supervisor detailing whether or not the wellhead and BOP are in good condition. 4. The tubing plug valves and the corresponding crossover subs should be prepared. The machined crossover subs should meet the API (American Petroleum Institute) standards.

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5. The casing tongs, elevators, and slips for the tubing and casing and the supporting tools for the special pipes (such as super 13Cr) should be prepared. It is better to use undented casing tongs. Suitable and easy-to-use dies and metal-lined meshes should be optimized for undented casing tongs (if used).

The Efficiency of the Tubing and Casing RIH Operations Should be Improved 1. The project management party should assemble all of the construction parties to explain the technical details before the tubing and casing RIH. 2. The tubing and casing RIH procedure should be reorganized to improve the operation efficiency and to reduce non-operation time. 3. The wellhead should be cleaned before running the casing. Unnecessary tools should be stored in the tool room. A handover record should be made and antifalling measures should be taken for common tools to ensure construction safety. 4. All of the threads of the string to be run in the hole should be tightened strictly according to the specified torque, and the acceptability of the make-up torque curve should be checked. 5. The hermetic seal testing of the string threads should be performed according to the design. Improving the operation efficiency in this stage can effectively reduce the risk involved in the casing RIH operations. 6. The casing running speed should be reasonably controlled according to the design. Violent lifting, violent braking, and violent lowering are strictly forbidden while running the casing. 7. The casing make-up quality should be ensured and reduce the time lost during the frequent replacement of the tubing and casing due to quality problems. Scrapping of too many pieces of tubing and casing may also result in an insufficient number of spare pipes at the site and can affect the progress of the construction.

Completion Tool RIH and Wireline Operations The completion tool RIH and wireline operations occur in the final stage of the completion engineering of an injection-production well, and they involve processes such as pipe scraping, drifting string running, running of tubing and completion tools, wellhead installation, well cleanout, annulus protection fluid displacement, and packer setting. The working procedure of this stage is the most complicated, the construction parties are the largest in number, and the operation risks are high and cannot be ignored. 1. Pipe scraping and drifting A casing scraper of the designed size and a scrape casing should be run repeatedly in the packer setting section and within the 5 m above and below it. A drift diameter gauge of the designed size should be run to carry out drifting to the packer setting

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position, and then, the drifting should be carried out three times within the 50 m above and below the position. 2. Running completion tools (1) Any well completion tool should be lowered carefully and slowly when passing through the BOP and the casing spool. In addition, during completion tool running, the changes in the hang weight should be closely observed to avoid colliding with and scratching the downhole tools, e.g., the packers and safety valves. (2) Before the safety valve is connected to the hydraulic control line, a pressure test should be performed. The safety valve is run under pressure. (3) Key safety valve inspection points: The safety valve should be checked for damage, and the safety valve protective nut should be removed to check whether or not the chamber inside is clean. An HIF joint should be installed and the air should be removed from the hydraulic control line and chamber. The hydraulic control line should be connected to the safety valve and the HIF joint should be tightened as required. A pressure test should be conducted. (4) The setting position of a permanent packer should meet the following conditions: the hole deviation should generally be less than 35°; the dogleg severity should be less than 10°/30 m; the setting position should be more than 2 m from the casing collar; and the cementing quality of the production casing near the setting position should be acceptable. 3. Injection-production wellhead installation (1) The downhole safety valve should be closed and the tubing pressure and casing pressure should be observed. After confirming it is safe, the BOP should be disassembled and the injection-production wellhead should be installed. (2) The mud proof umbrella, the overflow tee, the BOP stack, and the drilling spool should be disassembled. (3) When installing the Christmas tree, attention should be paid to the installation direction, all of the fastening bolts should be tightened according to the API standards, and a pressure test should be conduct on the entire Christmas tree. 4. Reverse circulation well cleanout. The downhole safety valve should be kept open, and reverse circulation well cleanout with active water should be conducted until acceptable conditions are obtained. During the reverse circulation well cleanout, a great deal of attention should be paid to the well control safety, the monitoring of toxins and harmful and combustible gases, and the preparation of emergency plans. The pump starting pressure may be too high when the pump is started for the circulation well cleanout. If the safety valve, surface valves, and pipelines are all normal, this may be because the completion and drilling fluids have been stationary

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for a long time. In this case, the circulation process should be reversed into a positive circulation process, and then, the pump should be started. After solving this problem, the circulation should be returned to the reverse circulation process. If there is a need to displace the positive circulation fluid before the packer setting, the pump displacement should be strictly maintained at less than 0.3 m3/min. During the setting and checking the setting of the packer, it is necessary to ensure that the cement truck operates smoothly and the pressure control is accurate.

Annulus Protection Fluid Injection The annulus protection fluids should be injected through the reverse circulation as per the designed displacement from the wellhead. The Christmas tree wing valve should be closed, and the change in casing pressure should be observed. It should be confirmed that there is no anomaly before performing the wireline operation.

Packer Setting Through the Wireline Operation Selection of the wireline: The specifications of the wireline should be carefully checked to ensure that they meet the design requirements and to determine if the wireline body is rusted at this site. In addition, the number of wireline operation wells should be determined, and fatigued wireline should never be run in the hole. During the wireline operation, it is necessary to ensure that the downhole safety valve is fully opened. It is strictly forbidden to half-open or half-close the safety valve or to release the pressure in the middle of the operation, which would close the safety valve and cut off the wireline. The operator should always have wire rope heads and finding and fishing tools on hand. The inspection of wireline operation tools should be improved before the RIH to prevent downhole accidents.

Analysis and Evaluation of the Sealing Integrity of the Cement Sheath Gas Storage Well Operation Characteristics and Requirements for the Sealing Property of the Cement Sheath 1. Gas storage operation characteristics For an underground gas storage facility, it is required that repeated intensive injection and production be carried out in a short period of time. Therefore, the underground gas storage facility must meet the requirement that gas can be injected into, stored in, and produced from the facility, and it must have a capacity suitable for

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short-term high production, repeated variations between high and low pressures, and long-term use. The operating pressure of the Huabei Suqiao gas storage facility is 19.0– 48.5 MPa; the operating pressure of the Xinjiang Hutubi gas storage facility is 18.0–34.0 MPa; and the operating pressure of the Liaohe Shuang-6 gas storage facility is 10.0–24.0 MPa. During long-term natural gas injection and production operations of gas storage facilities, the internal pressure and temperature of the casings in the wells alternate. This alternating pressure can cause the micro-fractures inherent in set cement to slowly expand and interconnect, thereby leading to fatigue failure of the set cement. 2. Requirements for the sealing integrity of the cement sheath The sealing integrity of a cement sheath means that the cement sheath can maintain a good sealing integrity, structural integrity, and functional integrity throughout the life time of the gas storage well. According to the sealing integrity requirements of the cement sheath, in order to ensure the effective short-term and long-term sealing properties of the cement sheath of a gas storage well, the solid performance of the set cement should meet the following three requirements. (1) The set cement should have a high strength, a good compactness, and a high corrosion resistance (to acidic medium, heat, self-stress). (2) The set cement should have a certain toughness and should be able to resist drilling vibrations and the impacts of perforation detonation stress waves. (3) The deformation capacity of the set cement should be controlled to ensure the coordination of the mechanical deformations of the casing, cement sheath, and formation. 3. Research progress on the mechanical properties of set cement in gas storage wells In recent years, in response to the problem caused by the easy failure of the cement sheath during the long-term operation of gas storage wells, the failure mode of the cement sheath’s integrity in gas storage wells has been investigated, an elastoplastic finite element mechanical model considering the interactions between the casing, the cement sheath, and the formation has been established, and the impacts of the elastic modulus and yield strength of the set cement on the sealing integrity of the combination have been analyzed. Based on the results of these studies, when the elastic modulus of the set cement is small, the deformation ability of the set cement is strong, hard crushing failure does not easily occur under the action of loads, and the interface is not easily torn after unloading. The higher the yield strength of the set cement, the better the tearing resistance of the interface after unloading, and the higher the load on the cement sheath. In addition, it should be noted that in addition to the properties of the cement sheath itself, parameters such as the mechanical properties of the formation and the casing size also have important impacts on the wellbore’s integrity, and thus, further research is needed.

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Analysis and Evaluation of the Sealing Integrity of the Cement Sheaths in Gas Storage Wells 1. Requirements for cementing design To ensure the sealing integrity of the cement sheath, full consideration should be given to from the cement sheath during the cementing design stage. According to the geologic characteristics of the gas storage facility and the drilling difficulties encountered, detailed and operable requirements should be formulated in terms of the displacement efficiency, cement slurry system selection, and supporting technical measures to ensure the sealing integrity of the cement sheath. 2. Requirements for the cement slurry Tough cement should be used in the cementing of the production casing and caprock sections. Set cement is a brittle material that contains a large number of micro-cracks and defects, and ordinary cement slurry systems have difficulty meeting the technical requirements for the long-term sealing of gas storage spaces under long-term alternating stress conditions. Therefore, it was necessary to develop new toughening materials to achieve the high strength and low elastic modulus required. The high strength of the cement resists the formation loads, and its low elastic modulus reduces the load transfer coefficient, thereby maintaining the mechanical integrity of the set cement, enhancing the cementing of the cement sheath and casing, and ensuring the stability of the coupling between the casing, cement sheath, and formation. Tough cement should be used for the cementing of the production casing and caprock sections in gas storage facilities. The technical key to the development of a tough cement is to optimize the toughening materials with good comprehensive properties. In order to select suitable toughening materials, the four problems that follow should be taken into account. The selected toughening material should have a small impact on the 24–72 h, 7 day, and long-term compressive strengths of the set cement. The addition of the toughening materials to the cement slurry should not affect the cementing operation’s safety or the uniformity of the cement slurry’s density. The selected toughening material should be compatible with the other additives and admixtures, the stability of the cement slurry should be good, the volume of the set cement should not shrink, and the early strength should develop quickly and have a long-term stability. After adding the toughening materials to the cement slurry system, the set cement should achieve a high compressive strength, a low elastic modulus, and a strong impact resistance, and it should be compatible with the mechanical properties of the formation lithology.

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3. Improving the mechanical properties of the set cement Obtaining a cement with a high performance, high strength, and low elastic modulus that can effectively seal the annulus is a bottleneck problem that restricts the cementing of gas storage wells. The poor cementing quality of the well parts in the early construction stage of gas storage facilities is mainly due to not using a good cement slurry. The principle for set cement modification is that based on the premise of ensuring the comprehensive properties of the cement slurry, the mechanical properties of the set cement are modified, and the elastic modulus of the set cement is reduced to solve the problems caused by the impact of the long-term alternating injection-production stress. The other properties of the cement slurry cannot be destroyed while modifying the mechanical properties of the set cement. The quality of the cement should be significantly improved after the modifications by applying high-performance tough expansive cement and by strengthening the wellbore preparation and tool reliability.

Post-cementing Quality Evaluation 1. Overall requirements for the cementing quality of gas storage wells A CBL/VDL (cement bond log/variable density log) should be selected for the cementing quality inspection. Ultrasonic imaging logging should also be performed when cementing the production casing and caprock sections. The logging data should be processed in accordance with the corresponding technical requirements. The processing results should include the cementation degrees of the first and the second interfaces and the quality of the cement sheath and the interlayer isolation should be comprehensively evaluated. The length of the acceptable cemented section of the production casing and the intermediate casing used to cement the caprock section should be greater than 70%. The length of the continuous high-quality cemented section in the caprock section above the reservoir’s top should be greater than 25 m. 2. Casing string pressure test requirements A pressure test should be performed on the production casing with clear water, and the test pressure should be 1.1 times the maximum operating pressure at the wellhead, but it should not exceed the minimum yield pressure at any point in the production casing. In addition, the impact on the cement sheath’s integrity should be taken into account. If the pressure drop within 30 min is less than 0.5 MPa, the pressure test is acceptable. If the bottom hole pressure is large during the casing pressure test, the casing can be tested using the staged pressure test method.

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3. Cementing quality methods and requirements. Injection and production wells in gas storage facilities have a long life cycle and bear alternating stress; therefore, higher requirements have been proposed for the casing sealing property, caprock section, and the entire well section. The cementing quality evaluation of gas storage wells is designed to check whether or not the purpose of the cementing has been achieved. CBL, VDL, SBT (segmented cement bonding tool), or IBC (international building code) are generally used to evaluate the cement sheath’s quality.

Wellbore Safety Pressure Test Technology The test pressure value of a gas storage facility constructed from a depleted gas reservoir is jointly determined based on the operating pressure of the gas storage facility and the string strength. According to the provisions of the Technical Specifications for Drilling and Completion of Gas Storages in Depleted Gas Reservoirs (Q/SY1561–2013), a pressure test on the production casing should be performed using clear water, and the test pressure should be 1.1 times the maximum operating pressure at the wellhead, but it should not exceed the minimum yield pressure at any point on the production casing. In addition, the impact on the cement sheath’s integrity should be taken into account. For a deep well, a staged pressure test can be performed, a staged pressure test with packers can be conducted, or a joint pressure test using clear water in the lower part and gas in the upper part can be carried out. For a deep well, an integral pressure test with gas can be performed using the method for salt cavern gas storage facilities, but the pressure test cycle is extended, and the investment in the pressure test surface equipment needs to be increased. During a pressure test conducted on a salt cavern gas storage facility, the pressure on the production casing shoe should be 1.1 times the designed upper limit of the operating pressure of the gas storage facility, but it should not exceed 80% of the minimum internal yield pressure of the casing. The readings of the wellhead pressure gauge should be recorded and the position of the GWC (gas-water contact) should be measured once an hour. The effective time of the continuous detection should be greater than or equal to 24 h. It should be ensured that the surface wellhead equipment and the manifolds are sealed during the detection process. After the detection is completed, the gas in the annulus should be uniformly released until the liquid returns, and the pressure drop rate at the casing shoe should be less than 0.3 MPa/h. The observation should be continued for 0.5 h and it should be confirmed that the wellhead is in a safe state before proceeding to the subsequent operation. If the detection is acceptable, it should not be performed again within 21 day.

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Wellhead Equipment Optimization Wellhead Equipment Gas storage operations alternate between gas injection and gas production. Thus, the wellhead must be able to withstand high pressures and high temperatures, and it must have a certain corrosion resistance and a good hermetic seal performance, which is convenient for operation management. 1. Basic requirements The wellhead equipment should be set to the working conditions of the gas storage facility, such as the temperature, pressure, production, corrosive gas, and dynamic monitoring requirements after operation. All of the main seals should be metal-to-metal seals. The seal between the tubing head spool and the production casing should be an all-metal seal. An overall underwater hermetic seal test must be performed before delivery to ensure the quality of the Christmas tree. The gate valve should be a two-way floating full-bore sealing valve. The main drift diameter should match the production string. The downhole safety valve control pipeline should achieve overall crossing and should be connected with the surface safety control system. 2. Optimization of the technical parameters (1) Pressure rating The pressure rating should be selected according to the Specifications for the Wellhead Equipment and Christmas Tree (API 6A) (Table 2). (2) Temperature rating The temperature rating of the wellhead equipment should be selected according to the minimum ambient temperature and the highest temperature of the fluid flowing through the gas production wellhead equipment. The temperature rating should be selected according to the Specifications for the Wellhead Equipment and Christmas Tree (API 6A (Table 3). Table 2 Pressure rating according to API 6A

API pressure rating (psi) 2000 3000 5000 10,000 15,000 20,000

API pressure rating (MPa) 13.8 20.7 34.5 69.0 103.5 138.0

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Table 3 Temperature rating according to API 6A

No. 1 2 3 4 5 6 7 8

Temperature type K L P R S T U V

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Applicable temperature range (°C) 60–82 46–82 29–82 RT 18–66 18–82 18–121 2–121

(3) Material grade The material grade should be optimized according to the operating conditions of the injection and production wells and according to Tables 4 and 5. The optimized material grade of the wellhead equipment of the injection and production wells of the gas storage facility should be safe, applicable, and economical and should comprehensively consider the operation of the injection and production wells and the changes in the corrosive environment. (4) Product specification level (PSL) The Specifications for the Wellhead Equipment and Christmas Tree (API 6A) describes the selection criteria for the lowest product specification level (PSL) for the wellhead equipment (Table 6). This parameter is a requirement for product quality control. The higher the PSL, the more the items need to be tested. (5) Product quality requirements (PR) The PR described in the Specifications for the Wellhead Equipment and Christmas Tree (API 6A) are divided into two levels (PR1 and PR2), and their respective specific requirements are determined. The PR should be determined according to the application conditions of each part of the wellhead. The safety valves must meet the PR2 requirements. Figure 8 shows the crisscross gas production wellhead equipment.

Wellhead Safety Control System The injection and production wells in gas storage facilities produce high-pressure natural gas for long period of time, the surface environment is complex, and the safety and environmental protection requirements are strict. Therefore, the wellhead safety system should have the functions that follow. It can automatically close a well in the event of a fire. It can automatically close the well when the wellhead pressure is abnormal.

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Table 4 Optimization of the material grade of wellhead equipment (table provided by CAMERON)

Material grade AA (alloy steel) Noncorrosive operating conditions BB (alloy steel, stainless steel) Medium corrosive environment conditions CC (all stainless steel) Corrosive environment conditions DD (NACE alloy steel) Noncorrosive acidic environment EE (NACE alloy steel, stainless steel) Medium corrosive acidic environment FF (NACE all stainless steel) Medium corrosive acidic environment HH (full inlaid nickelbased alloy) Extremely corrosive acidic environment

Partial pressure of H2S (psi) 0.05

Partial pressure of CO2 (psi)