Handbook Of Multiphase Flow Assurance [1st ed.] 9780128130636

Table of contents :
Cover......Page 1
HANDBOOK OF
MULTIPHASE
FLOW
ASSURANCE
......Page 3
Copyright......Page 4
Dedication......Page 5
Preface......Page 6
1
Introduction......Page 7
Multiphase production problems: Blockages and restrictions......Page 8
Savings from using flow assurance......Page 9
Examples of flow assurance problems......Page 11
How flow assurance and production chemistry work together......Page 16
When is flow assurance applied......Page 20
Why flow assurance failures happen......Page 21
Flow assurance background......Page 23
Basis of design......Page 27
Introduction to flow assurance risk analysis......Page 28
Cost of subsea hardware related to flow assurance......Page 30
Offshore production......Page 34
Systematic approach to solving flow assurance problems......Page 35
Outlook for flow assurance......Page 36
References......Page 37
2
Initial diagnosis and solution of flow assurance production problems in operations......Page 40
Laboratory analysis......Page 45
Typical blockage remediation plan......Page 47
Phase behavior......Page 48
Special considerations for mercury samples......Page 49
Hydrocarbon fluid sample quality checks......Page 50
Water sample quality checks......Page 55
Fluid properties and measurements......Page 56
Fluid characterization......Page 57
Lumping for different fluids......Page 61
Solid-liquid equilibrium......Page 62
Additional laboratory studies......Page 64
PVT tuning......Page 65
Fluid physical properties......Page 66
Non-Newtonian behavior......Page 68
Emulsion characteristics......Page 69
References......Page 70
Further reading......Page 71
4
Hydraulic and thermal analysis......Page 72
Hydraulic restrictions boundaries and management......Page 73
Hydraulic analysis deliverables......Page 74
Overall design......Page 75
Typical pressure drop......Page 76
Hydraulics technologies......Page 78
Multiphase flow pressure drop—Vertical vs horizontal......Page 79
Designing out severe slugging......Page 84
Multiphase flow liquid holdup—Vertical vs horizontal......Page 85
Heat transfer......Page 86
Correlations......Page 89
Dimensionless numbers......Page 90
Software......Page 91
Multiphase production problems......Page 92
Operation online monitoring for well liquids loading and forming blockages/restrictions......Page 93
Hydraulic management......Page 94
Water injection management......Page 95
Machine learning and artificial intelligence in flow network optimization......Page 96
References......Page 97
Further reading......Page 98
5
Flow restrictions and blockages in operations......Page 99
Frequency of blockage remediations......Page 101
Duration of hydrate and other flowline remediation......Page 102
Hydrate versus other flowline remediation time......Page 103
Introduction......Page 105
Gas hydrate formation......Page 106
Hydrate propensity, subcooling, supercooling and overpressurization......Page 108
Thermodynamic features......Page 110
Problems related to hydrate formation......Page 112
Calculating location of hydrate blockage in a pipe......Page 113
Prevention of hydrate formation......Page 114
Chemical inhibition......Page 115
Hydrate dissociation......Page 121
Hydrate blockage remediation......Page 122
Comparative economics of hydrate prevention methods......Page 125
Environmental impacts of hydrate remediation......Page 126
Effect of hydrates on corrosion......Page 127
Gas hydrate in wells and in nature......Page 129
Hydrate management......Page 131
Biological techniques......Page 132
Modeling of gas hydrates......Page 133
Case studies and process safety......Page 135
Commissioning/dewatering of pipelines to avoid hydrates......Page 143
Introduction......Page 144
Reservoir and wellbore plugging......Page 145
Prediction of asphaltene risk......Page 146
Gas condensate......Page 147
Asphaltene precipitation and deposition in wells and pipelines......Page 148
Monitoring and remote sensing of asphaltenes......Page 149
Modeling of asphaltenes......Page 150
Prevention of asphaltenes......Page 151
Bacterial growth management......Page 152
Diamondoids......Page 153
Water in gas and oil lines......Page 154
Steam (condensed water in oil sands steam injection lines)......Page 155
Liquid accumulation in horizontal and vertical wells......Page 156
Sand transport......Page 157
Minimum transport velocity......Page 158
Erosional velocity limits......Page 159
Introduction......Page 160
Composition......Page 163
Wellbore and reservoir plugging......Page 164
Effect of PVT conditions......Page 165
Tubular plugging......Page 167
Prevention techniques......Page 168
Remediation techniques......Page 171
Measurement techniques......Page 172
Modeling......Page 175
Comprehensive modeling......Page 177
Waxy gels......Page 178
Introduction......Page 180
Treatment of sour production......Page 181
Sulfate......Page 182
Prediction......Page 183
Remedial actions......Page 184
Interaction of flow assurance issues with and effects on produced fluids and flow......Page 185
Seven suggestions from operations in deepwater and onshore......Page 187
References......Page 188
Further reading......Page 192
Sampling fluids......Page 194
Quality: 4Cs of production chemicals......Page 195
Test procedures......Page 196
Product fluid quality......Page 197
Emulsions, foam, topsides separation, water treatment management......Page 198
Properties of naphthenates......Page 200
Viscous oil management......Page 201
Dra......Page 202
Chemical data......Page 203
References......Page 206
Flowline design process......Page 207
Artificial lifting......Page 208
Cold flow and emulsion......Page 209
Emulsion rheology......Page 210
Further reading......Page 211
Phenomena description......Page 212
Stability limits......Page 213
Shut-in and start-up......Page 214
Calculation of slug impact force on Tees and Elbows......Page 215
Calculation of pressure surge on sudden flow shut-in......Page 216
Further reading......Page 217
Introduction......Page 218
Corrosion monitoring methods......Page 219
Integrated models......Page 220
References......Page 221
10
Research methods in flow assurance......Page 222
Importance of studying gas hydrates......Page 223
Hydrates as an environmental buffer for holding CH 4, CO 2......Page 224
Industrial applications for gas hydrates......Page 225
Hydrates as a source of hydrocarbon fuel......Page 227
Properties and structures of gas hydrates......Page 229
Hydrate formation with inhibitors......Page 234
Kinetics of hydrate formation......Page 235
Phase transitions in gas hydrates......Page 236
Data in the literature for methane hydrate......Page 237
Experimental equipment and procedure for methane hydrate......Page 238
Results and discussion for methane hydrate data......Page 239
Data in the literature for Xe hydrates......Page 242
Experimental procedure......Page 243
Results......Page 244
Results and discussion for xenon hydrate data......Page 245
Evaluation of experimental results......Page 250
Evaluation of the biomolecular computer studies......Page 251
Comparison of chemical performance on a solid surface......Page 252
Results of the computer simulation......Page 253
Method of research......Page 254
Data analysis......Page 257
Discussion of polymers docking......Page 258
Conclusions for docking study......Page 262
Introduction......Page 263
Procedure of water models verification......Page 267
Analysis of the water structure for different models......Page 268
Determination of the water hydrogen bonding structure......Page 269
Derivation of hydrogen bond connectivity......Page 271
Results of hydrogen bonded water network study......Page 274
Effect of VC-713 Inhibitor......Page 275
Effect of PVP inhibitor......Page 276
Effect of PVCA Inhibitor......Page 278
Overview of inhibitor simulation......Page 279
Summary of computer modeling......Page 280
Experimental and computer study of the effect of kinetic inhibitors on clathrate hydrates......Page 281
Crystallographic information about hydrates......Page 285
Hydrate crystal growth......Page 287
Inhibition of hydrate formation......Page 288
Structures of liquid water and hydrate......Page 291
Thermodynamic properties......Page 293
Stability of gas hydrates......Page 294
Early modeling of hydrate growth......Page 295
Inhibition of hydrate growth......Page 297
Research objectives......Page 298
Morphology of hydrate crystals......Page 300
THF  +  water  +  inhibitors solution without salt......Page 305
Effect of NaCl salt on THF hydrates......Page 309
Organization of this section......Page 313
Studies of monomers adsorption on hydrate with Cerius2......Page 314
Using the hand-written software for studying interaction of water and monomers......Page 321
Testing the simulation code......Page 322
Using the simulation code......Page 323
Adsorption of monomers on discrete hydrate surface......Page 325
Comparison and contrast with experimental results......Page 328
Adsorption of inhibitor polymers on hydrate......Page 330
Validation of the methane adsorption model......Page 335
Simulation of methane adsorption......Page 336
Using the computer to design inhibitors......Page 337
Summary of simulations......Page 339
Summary based on experiments with THF hydrate growth......Page 340
Summary from the adsorption simulation results......Page 341
Flow loop tests......Page 342
Paraffin cross-polarized microscope CPM......Page 343
Program for generating radial distribution function in water......Page 344
Program for h bonded rings count in water......Page 347
Monte Carlo program for polymer adsorption on hydrate......Page 368
References......Page 437
Further reading......Page 442
Free modeling tool for chemical injection distribution system......Page 444
Free modeling tool for scale stability......Page 445
Free hydrate plug remediation software......Page 448
Free gas, gas condensate and LNG thermodynamic property calculator......Page 449
12
Flow assurance modeling......Page 451
Historic frequency of blockages based on remediation......Page 453
Impact on overall planning......Page 454
PVT gas properties......Page 455
Regulatory requirements and environmental law which may affect flow assurance......Page 460
Advanced flow assurance fluid properties......Page 463
Flow correlations......Page 464
Units and conversions......Page 465
Standard temperature and pressure......Page 467
C......Page 468
F......Page 469
G......Page 470
H......Page 471
I......Page 472
M......Page 473
P......Page 474
S......Page 476
W......Page 477
X......Page 478
Back Cover......Page 479

Citation preview

HANDBOOK OF MULTIPHASE FLOW ASSURANCE

HANDBOOK OF MULTIPHASE FLOW ASSURANCE Taras Y. Makogon

Gulf Professional Publishing is an imprint of Elsevier 50 Hampshire Street, 5th Floor, Cambridge, MA 02139, United States The Boulevard, Langford Lane, Kidlington, Oxford, OX5 1GB, United Kingdom © 2019 Elsevier Inc. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or any information storage and retrieval system, without permission in writing from the publisher. Details on how to seek permission, further information about the Publisher’s permissions policies and our arrangements with organizations such as the Copyright Clearance Center and the Copyright Licensing Agency, can be found at our website: www.elsevier.com/permissions. This book and the individual contributions contained in it are protected under copyright by the Publisher (other than as may be noted herein). Notices Knowledge and best practice in this field are constantly changing. As new research and experience broaden our understanding, changes in research methods, professional practices, or medical treatment may become necessary. Practitioners and researchers must always rely on their own experience and knowledge in evaluating and using any information, methods, compounds, or experiments described herein. In using such information or methods they should be mindful of their own safety and the safety of others, including parties for whom they have a professional responsibility. To the fullest extent of the law, neither the Publisher nor the authors, contributors, or editors, assume any liability for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions, or ideas contained in the material herein. Library of Congress Cataloging-in-Publication Data A catalog record for this book is available from the Library of Congress British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library ISBN: 978-0-12-813062-9

For information on all Gulf Professional publications visit our website at https://www.elsevier.com/books-and-journals

Publisher: Brian Romer Senior Acquisition Editor: Katie Hammon Editorial Project Manager: Joshua Mearns Production Project Manager: Anitha Sivaraj Cover Designer: Christian J. Bilbow Typeset by SPi Global, India

Dedication To my teachers Prof. Yuri F. Makogon, Yakov F. Lerner, Prof. E. Dendy Sloan, and Prof. M. Sami Selim.



v

Preface This handbook is a compilation of reference materials and experiences related to flow assurance collected over the years. This handbook may help the production operator identify and solve issues faster and also help a project development engineer design the most critical flow assurance issues out of the system more cost-effectively. The intent of



this book is to deliver safe, reliable and economic design and operation of multiphase production systems with flow assurance threats. Flow assurance is used in onshore, offshore and subsurface flow of petroleum fluids. This diversity of application of flow assurance control methods motivated the development of this handbook.

xi

C H A P T E R

1 Introduction O U T L I N E Threats to product value or process safety (asset integrity) 24

Multiphase production problems: Blockages and restrictions 2 Savings from using flow assurance

3

Examples of flow assurance problems

5

How flow assurance and production chemistry work together

10

When is flow assurance applied

14

Knowledge required in flow assurance

15

Why flow assurance failures happen

15

Flow assurance background

17

Flow assurance requirements Basis of design Units for fluid characterization

21 21 22

Hardware cost 24 Cost of subsea hardware related to flow assurance 24

Introduction to flow assurance risk analysis 22 Threats to flow are normally attributed to flow assurance 24

Monitoring and data mining

28

Flow assurance in operations Onshore production Offshore production Deepwater production

28 28 28 29

Systematic approach to solving flow assurance problems

29

Process safety

30

System of measures for flow assurance

30

Outlook for flow assurance

30

References

31

Flow assurance aims to make sure oil and gas keep flowing. To achieve that goal, flow assurance relies on the analysis of multiphase flow and on the selection and use of production chemicals. Flow assurance engineers commonly analyze the flow of oil and gas in wells, production flowlines, process facilities and export pipelines. Complex networks of gathering lines feeding into trunk flowlines exist in onshore and offshore fields, and the analysis to optimize flow routing through such networks is equally complex.

Handbook of Multiphase Flow Assurance https://doi.org/10.1016/B978-0-12-813062-9.00001-4

1

© 2019 Elsevier Inc. All rights reserved.

2

1. Introduction

Definitions of flow assurance are numerous, including this one: Flow Assurance is the analysis of thermal, hydraulic and fluid-related threats to flow and product quality and their mitigation using equipment, chemicals and procedure.

Multiphase production problems: Blockages and restrictions Oil and gas are currently produced through wells and pipelines. The lack of flow in wells and pipelines may be due to low reservoir pressure or productivity, due to complete blockages or due to partial restrictions. Flow restrictions may happen in a reservoir, in a well production tubing or a tree, in a jumper between a well and a flowline, in a flowline, in a riser or in an export pipeline. In some cases, restrictions may happen in several locations simultaneously. The largest number I have seen is five blockages in the same production flowline at the same time. Restrictions may also occur in water and gas injection systems as in wells, flowlines or reservoirs. Restrictions may be hydraulic, such as liquid accumulation also known as a holdup in flowlines and risers, liquid loading in wells, or mechanical such as a partly closed valve or a scraper. Restrictions or blockages may also be solid, including organic (e.g., paraffin wax), inorganic (scale) or particulate (sand). The hydraulic, mechanical or solid restrictions may be stationary such as the liquid holdup or moving such as the slugging. A flow assurance practitioner should be able to recognize the signs of and potential for any type of restriction and either economically design it out of a new system or mitigate it in an existing system. In some cases, restrictions may lead to other restrictions. There is an early 2000s example from West Africa offshore production where a wax deposit in a flowline got scraped by a formed hydrate plug into a solid paraffin wax blockage. Similarly, combined hydrate-paraffin restrictions have also formed in the North Sea in the early 1990s and asphaltene-hydrate in the Gulf of Mexico in the 2010s. Paraffin-asphaltene-sand restrictions have been common in Siberian pipelines through the decades. Modeling of multiphase flow can be done to find optimal conditions for a stable production of gas and hydrocarbon liquids with water. When the gas flow rate is not high enough to sweep the liquid hydrocarbons and liquid water from a well or a pipeline, these liquids accumulate in low spots because of gravity. The liquids can accumulate either downhole in a vertical well or at a heel or a toe, whichever is lower, in a horizontal well which is known as liquid loading. Both deepwater and shale horizontal wells are susceptible to liquid loading. Severe slugging is one of the issues in multiphase flow also related to gravity. Liquids can accumulate at a subsea riser base and then get periodically produced to a topsides separator after a sufficient gas pressure has built up behind the accumulated liquids as a large sudden gush of liquid preceded by a period of no or limited flow, which is known as severe slugging. Wells keep producing during severe slugging at a steady rate, but backpressure on wells may change noticeably between slug accumulation and displacement. Severe slugs keep repeating, and slug size and momentum are substantial as to cause vibration at pipe bends in flow geometry, overfill the process vessel or both. Liquids also can accumulate in the low spots of a near-horizontal pipeline and get periodically displaced by a steady flow of gas, which leads to terrain slugging. Terrain slugs keep repeating and are usually smaller in size and don't overfill the process vessel but may cause



Savings from using flow assurance

3

vibration at pipe bends. Hydrodynamic slugging occurs as liquids holdup is displaced by an increasing flow of gas from a flowline in form of a liquid surge. If the surge volume is significant, the hydrodynamic slugs can be as detrimental as severe slugs. Hydrodynamic slugs occur once per a change in production rate and don't repeat. In all three cases of liquid loading, severe slugging and terrain slugging gravity plays the key role in overcoming the energy emerging from the expanding gas or a single phase or supercritical fluid (also known as the dense phase) or an aquifer which is less than sufficient to lift the liquids to the separator or a slugcatcher. Analysis of multiphase fluid flow is in part based on information from reservoir modeling prediction of flow rates and on thermodynamic PVT characterization of produced fluids. Software which tracks and balances masses and velocities of produced fluids is available to help predict and analyze the flow velocities and the quantities of accumulation (also known as holdups) of liquid and other phases in the production system. An accurate prediction allows the design engineer to select proper sizes for the well production tubing and for gathering flow lines, and also to identify which technologies would be necessary and most economically suited to produce gas and oil from a reservoir.

Savings from using flow assurance Flow, which may be single phase (natural gas, oil, water, CO2) or multiphase (two or more single phases) is the key metric of the main product of petroleum companies. Those companies which have more barrels of flowing product per employee generally do well, and vice versa. Flow assurance is becoming a critical path discipline when other disciplines such as pipeline engineering, subsea layout, artificial lift equipment, and, in some projects, reservoir engineering, wait for flow assurance to compare and validate the viability of an overall architecture for a concept of field development before proceeding with the design. The accuracy in flow assurance makes a project more, less or not at all profitable. This handbook helps organize and streamline the work in flow assurance, in order to make it more accurate. The use of flow assurance technology saved billions of dollars for oil companies. There are several examples of how multiphase flow tools have resulted in savings for Statoil, Shell, BP, ENI: • Multiphase technology & OLGA—Norske Shell—Troll—30 Billion NOK The flow assurance savings for the Norske Shell—Troll field from multiphase technology and the use of an early version of the OLGA software were 30B NOK which is billions of dollars. “Direct electric heating has saved us billions of kroner on the Norwegian shelf,” said Atle Harald Børnes, who is a specialist at Statoil's Technology and New Energy Business Area. This system has been installed during the laying of pipelines linked to the Åsgard, Huldra, Kristin, Urd, Tyrihans, Alve and Morvin fields. A version of this heating system has also been prepared as a contingency measure for installation on the pipeline leading from the Ormen Lange field to Aukra. The heating system was also installed at the BP-operated Skarv field, which has been put on stream after 2011. The Italian company ENI has also opted to utilize the same system for its Goliat field development offshore Finnmark (Nilsson et al., 2010). • Hydrates and electrical heating—Statoil, BP—N.Sea—Billions of NOK

4

1. Introduction

Construction initiative of the multiphase flow loop at Tiller near Trondheim, Norway was pioneered by Esso Norge looking to evaluate the stability of multiphase oil and gas production from offshore reservoirs, and supported by this and other companies. The cost to construct this flow loop was over 26 million in 1980 US dollars. The choice of location was economically justified because the Norwegian sector of the North Sea showed promising acreage and because the Norwegian law allowed some research cost to be deducted from taxable revenue. Numerous sets of data were collected from this test facility which, to this day, are used to validate multiphase software (Caspersen et al., 2011). The Tiller multiphase flow loop shown in Fig. 1.1 is perhaps the one most important facility used for development of data sets for validation of several multiphase flow models.

Fig. 1.1  Tiller flow loop and tower for multiphase flow research.



Examples of flow assurance problems

5

Flow assurance technology development also has its roots in PROCAP 1000, a technology program executed by Petrobras from 1986 to 1991, comprised 109 multidisciplinary projects. The cost of the program was 68 million USD. The projects developed under PROCAP 1000 gave rise to a significant part of the 251 patents obtained by Petrobras between 1987 and 1992. It also allowed access to subsea oil fields in water deeper than 300 m which could not be accessed through diving, and the development of deepwater assets to a water depth of 1000 m, which led to capital investment in fields such as Marlim and Albacora and multi-billion profits from Petrobras' deepwater projects (Morais, 2013).

Examples of flow assurance problems Solids such as hydrates shown in Fig. 1.2–1.4, wax or scale can form blockages and restrict production. These solids can also affect mechanical integrity of a production system in multiple ways, such as erosion, rupture or collapse of pipelines. For example, hydrates can move as projectiles. In a few instances offshore, a partly dissociated hydrate plug got launched from a platform scraper receiver by gas pressurized behind the hydrate. Ice blockages also can present a problem. In an onshore operation in Alaska, an ice blockage formed in the smaller of the two flowlines operating in parallel due to differences in flow distribution. Freezing caused a 24-in. long rupture as shown in Fig.  1.5 at the bottom of a three-phase common line carrying a mixture of crude oil, produced water, and natural gas. Corrosion caused a similar event in 2007 with imagery available at Alaska (2008). A 6-in. long crack (about 1/8 in. wide at the center) formed in the flow line due to external corrosion. Hydrates can also crush or collapse steel tubing such as a well production tubing as shown in Fig. 1.6 in locations where water and gas accumulate at hydrate conditions in the same way ice can crack an engine block if water is used as a coolant instead of an antifreeze. A paraffin wax deposit can form when heavy hydrocarbon molecules with straight chains of carbon atoms, also known as normal paraffins, precipitate on cold surfaces and

Fig. 1.2  Hydrate slush in a flowline after hydrate blockage was dissociated by depressurization in an onshore Teapot Dome oil field.

6

1. Introduction

Fig. 1.3  Hydrate slush accumulated and compacted in service platform scraper receiver during flowline depressurization offshore Brazil, ca 1992.

Fig. 1.4  Hydrate extracted from service platform scraper receiver after subsea line depressurization. The compacted hydrate remained solid and did not break upon falling from the scraper receiver. accumulate, which restricts normal production. In some cases, condensates produced with free gas from deposits may contain heavier hydrocarbon molecules so wax can deposit from condensate during gas production as well as during oil production. In subsea practice, one solid may lead to another. In the analysis of wax deposition, one should distinguish such fluid characteristics as wax appearance temperature (WAT) when the first visible or detectable solid wax crystal precipitate, and wax dissolution temperature (WDT) when the precipitated wax crystals completely redissolve in the volume of oil from which they crystallized. There is also another term which is important for wax management design: the “wax deposit melting



Examples of flow assurance problems

Fig. 1.5  Thermal image of Alaska hydrocarbon loss of containment caused by ice blockage (Alaska, 2010).

Fig. 1.6  Well tubing collapsed by hydrate formation in a shut-in well annulus between tubing and casing. Onshore Siberia, 1965. T = 8°C, P collapse >800 atm, Tubing wall thickness 6 mm, inside diameter 63 mm. Photo by Yuri F. Makogon.

7

8

1. Introduction

t­emperature” (WDMT). The WDMT occurs at a temperature when a wax deposit accumulated over time in a field flowline melts without added oil or solvent. WDT is typically 10–20 °C higher than WAT, whereas WDMT can be 30–40 °C higher than WAT, depending on how long the wax had to age in the field flowline and how much of the heavy fractions it had concentrated. Crystals of normal paraffin wax, as well as many other crystals, can rotate the plane of light linear polarization and shine. This phenomenon is used in cross-polarized microscopy (CPM) to determine WAT. Networks of waxy crystals called gels, which also shine in a cross-polarized microscope, are therefore composed of wax crystals, not of amorphous non-crystalline material. The term gel is used in relation to wax to signify that the whole bulk of oil converts to a non-flowing material when its temperature drops below pour point and a waxy gel is formed. However, the waxy gel material is not uniform and contains both solid wax and liquid oil trapped between solids. One should recognize when discussing incipient, or initial, wax deposition on a pipe wall that it is wax crystals made up of concentrated normal paraffins or isomerized saturated alkanes that deposit, not a gel which has the same composition as base oil. A combined hydrate and wax blockage formed in the North Sea in the past in the Staffa field led to costly remediation by depressurization to melt the hydrate. After the first blockage got removed, the second blockage formed, which led to an abandonment of the subsea flowline. In another case offshore West Africa, an incompletely dissociated hydrate plug started to move in a pipeline and acted as a scraper, compacting the existing paraffin wax deposit into a solid blockage, which could no longer be melted simply by depressurization, and led to a lengthy process of solvent injection past the low-permeability paraffin plug which eventually got removed. Scale can form as shown in Figs. 1.7 and 1.8 when reservoir water, which may exist near the oil or gas deposit, has some minerals dissolved in it. At reservoir conditions, the formation water is usually partly saturated with salt, or in some cases may be near the equilibrium

Fig. 1.7  Scale buildup inside a heat exchanger tube (Lebedev, 2010).



Examples of flow assurance problems

9

Fig. 1.8  Solid salt scale plug in an Orenburg gas-condensate well, 100 mm diameter. Photo by Yuri F. Makogon, Originally published by PennWell Corporation in Hydrates of Hydrocarbons, 1997 and reprinted with permission. saturation. As water flows from the reservoir with the produced gas or oil, its pressure and temperature change, which affects the solubility of dissolved ions in water. Saturation limit for some ions may also be reached because water composition changes if the water table rises to the produced zone from another zone. Similarly, waters saturated with different ions from different zones mix, some ions combine and solid scale may form and restrict the pores in reservoir rock or in well tubing, thus limiting the productivity. Saturation limit for salt ions in water may also be reached because water molecules get consumed to form a hydrate leading to a concentrated brine, or because of the change of pressure or temperature. Hydrate formation can also lead to precipitation of solid salt scale in small-volume closed systems (Hu et al. 2017a,b, 2018) Petroleum industry access to ultra deep reservoirs often has to deal with high-pressure and high-salinity fluids. Reservoirs with fluid pressure over 180 MPa are in appraisal and development. Fluids in the reservoir may also be nearly saturated with salt in pre-salt deposits located under salt domes and diapirs. This combination of high pressure and high salinity of such fluids presents a unique set of challenges for wellwork and production engineers because in order to complete a well or to produce such fluids, formation of solid phases must be avoided. Solid phases may include gas hydrates or scales such as halite. During well completion, heavy brines are used to offset by their hydrostatic pressure the high pressure of reservoir fluids in order to avoid a well blowout. At the same time,

10

1. Introduction

completion brines must remain hydrate-free at mudline (seabed) conditions in case light hydrocarbon gases migrate from the bottom of the well up the wellbore to the location where well completion fluid is exposed to cold (approx. 277K) seawater if a well is drilled in offshore environment. Thus, accurate prediction of hydrate equilibria in high salinity brines is important. Similarly, during production of reservoir fluids through a completed well, hydrates must still be avoided, lest the well gets plugged with solids. If a chemical, such as pure methanol or a low dosage hydrate inhibitor formulated in methanol, is used to control hydrate formation, this may cause a salting out effect as scale forms due to colligative properties of water and inability to dissolve both salt and methanol simultaneously beyond the solubility limit. This has led to past incidents such as blockage of a North Sea production line with halite scale [ca.2009]. The ability to account for high salinity brines with respect to high pressure hydrate equilibria and scale formation is also important during production. Usually, stability of brines decreases with decreasing temperature. This may lead to precipitation and deposition of solid scale such as halite or barium sulfate. In case of carbonate scales, brine stability decreases with increasing temperature, leading, for example to a calcium carbonate scale in hot systems.

How flow assurance and production chemistry work together Multiphase flow assurance is complemented by production chemistry whose aim is to prevent the reduction of product value and process safety such as water in oil, oil in water, salt in oil, oxygen in water, mercury in fluids, H2S in gas, corrosivity, and/or bacteria. Sour crude is less valuable than sweet, so souring of crude oil in reservoirs may be prevented by using chemistry. Similarly, it is the goal of production chemistry to maintain specified quality of product oil and produced water so they are fit for export to refinery, reinjection into a well or discharge overboard. The chemicals are selected and deployed by chemists in multiple locations including reservoir, wellbore, flowlines, process facilities and export pipelines to help produce oil and gas most economically. The flow assurance and production chemistry work side by side to achieve related goals, and sometimes that work may be performed by the same person if that person has sufficient experience in both disciplines. The combined scope of some of the flow assurance and production chemistry items is shown below in Table 1.1: Many of the items from the above table get summarized in a Basis of Design document for flow assurance work. The allocation between flow assurance and production chemistry is only suggested depending on whether the issue is more flow-transformation or fluid-transformation related, and may vary from project to project. For example, foaming may be caused either by a fluid containing high amounts of natural surfactant or by high shear of flow through a choke or orifice. Foaming may be prevented by the use of production chemistry to improve separation of oil and gas or it may be sought by flow assurance to help lift fluids from a well with multiphase flow. Both flow assurance and production chemistry specialists should be experienced in all of the above items.



11

How flow assurance and production chemistry work together

TABLE 1.1  Combined scope of flow assurance (FA) and production chemistry (PC) FA Asphaltenes precipitation, deposition and remediation Artificial lift or boosting method selection and optimization

PC X

X

Bacterial analysis, modeling and control in flowlines and wells

X

Bacterial biomass accumulation in process equipment

X

Basis of design for flow assurance analysis

X

Chemical selection, dosages and compatibility screening Chemical injection locations, rates and chemical tubing or umbilical sizing

X X

Corrosion analysis, monitoring and treatment

X

Corrosion products accumulation in pipes and in process equipment

X

Cross-flow between wells or multiple zones in a well

X

Diamondoids precipitation from produced fluid (typically gas)

X

Drilling and wellwork fluids formulation for hydrate and scale control

X

Electrical heating analysis for flow lines

X

Emulsion separation in separators, flowlines and wells

X

Emulsified fluids viscosity and flow

X

Erosional velocity analysis

X

Flexible line inflation during filling with fluid

X

Flow metering strategy and locations

X

Fluid sampling plan, PVT analysis and EoS tuning during appraisal

X

Fluid sampling and laboratory planning for process facility in operation

X

Foaming of produced fluids

X

Gelled oil blockage and waxy gel break pressure

X

Glycol or methanol regeneration

X

Hydrate formation prediction, inhibition and remediation planning

X

Ice blockage

X

Joule-Thompson cooling or J-T heating of produced fluids

X

Liquids holdup in produced fluid transport lines

X

Liquids loading of wells during multiphase flow of gas, oil and water

X

Mercury accumulation in flow lines, equipment and product streams

X

Monitoring of flow and blockage detection with online system

X

Multiphase flow and pulsation in wells, flowlines, process equipment

X Continued

12

1. Introduction

TABLE 1.1  Combined scope of flow assurance (FA) and production chemistry (PC)—Cont’d FA

PC

Naphthenate scale analysis and remediation

X

Oil quality non-compliance due to water content

X

Paraffin wax analysis, deposition and remediation

X

Scraping of flowlines and pipelines

X

Pressure drop analysis in single phase and multiphase flow

X

Produced fluids export, discharge or reinjection plan

X

Relief and flare lines flow capacity and blockage potential analysis

X

Sand transport flow velocity analysis

X

Scale precipitation and deposition analysis and remediation plan

X

Souring of reservoir fluids: analysis, modeling and mitigation

X

Sulfur (elemental and organomercury)

X

Sizing of flowlines for control of multiphase flow slugging and erosion

X

Steam condensation and evaporation in distribution lines

X

Stuck scraper during pipeline commissioning or during flow line maintenance

X

Transient surge volume analysis for production separator or slugcatcher

X

Under-deposit corrosion

X

Value loss from hydrocarbon contaminant metals, methanol or water

X

Vibration induced by phase transition in process equipment

X

Viscous oil or viscous emulsion flow

X

Water or gas injection for pressure maintenance

X

Water quality, filtration and treatment with clarifier, oxygen scavenger Water hammer, HIPPS flow analysis

X X

Distribution of items varies by operator company.

An operator company which neglects or misses to check and quantify any one of these items at the project design stage carries a risk of increased cost or abandonment during operation. Some companies maintain internal boundaries between flow assurance and production chemistry disciplines, while others combine the two along with materials and corrosion issues, depending on the company size and the depth of available engineering resources. The American Petroleum Institute have clearly listed nine flow assurance issues as follows: – hydrate formation, – wax formation, – asphaltene formation,



13

How flow assurance and production chemistry work together

– emulsions, – foaming, – scale formation, – sand production, – slugging, – materials-related issues. The API 17 TR4 list above captures most of the scope and is fairly comprehensive for a typical oil or gas field development. Flow assurance prevention methods are usually thermal (insulation or a cooling spool) or chemical (inhibitors) whereas mitigation can be mechanical (pumps), chemical (solvents) or thermal (active heating). Production chemistry prevention is usually chemical (surfactants or inhibitors) or mechanical (segregation of incompatible fluid streams). Mitigation is chemical (chelants, dispersants, dissolvers) or mechanical (milling). Chemical injection dosages are, on average, 100 ppm with typical range of 50–250 ppm, and can be much higher for hydrate inhibitors ranging from 10,000 to 500,000 ppm or much lower at 5–10 ppm for emulsion breakers and corrosion inhibitors. In some sub-cases such as under-treated severe bacterial accumulation or foaming, flow also gets affected. Main focus of production chemistry is on product value including: oil quality (water content), water quality (organics content and total dissolved solids, oxygen content, souring and corrosion potential). Chemicals may be deployed in a variety of locations. Typical ranges of chemical dosages are needed to design a chemical delivery system. Such ranges are shown below in Table 1.2. TABLE 1.2  Initial estimates of chemical dosages and typical locations of chemical injection Chemical

Dosage, ppm mass basis

Place of injection usually

Emulsion breaker

5–10

Downhole, tree, topsides

Reverse demulsifier (water clarifier)

15–50

Topsides

Corrosion inhibitor (liquid and multiphase)

30–200

Tree

Corrosion inhibitor (gas export)

5–10

Topsides, process plant

Wax inhibitors

50–800

Downhole, tree

Wax dispersant

50–1000

Downhole, tree

Asphaltene inhibitor/dispersant

50–800

Downhole

Drag (friction) reducers: oil

100–1000

Process plant

Drag (friction) reducers: water

20–100

Tree, topsides, process plant

Pour point depressant (PPD)

25–1000

Downhole, tree

Scale inhibitors

5–100

Donwhole, tree

Scale dissolvers

Batch

Downhole, topsides Continued

14

1. Introduction

TABLE 1.2  Initial estimates of chemical dosages and typical locations of chemical injection­—Cont’d Chemical

Dosage, ppm mass basis

Place of injection usually

Foamers

5000–10,000

Downhole

Defoamers

100–150

Tree

LDHI: kinetic hydrate inhibitors

10,000–50,000

Tree

LDHI: AA hydrate inhibitors

5000–30,000

Tree

H2S scavenger

5000–10,000

Downhole, topsides

O2 scavenger

5–500

Topsides

Biocides

50–1500 (batch)

Topsides

Methanol or glycol—hydrate inhibition

5000–500,000

Downhole, tree

When is flow assurance applied Flow assurance is commonly applied in project design and/or in operations support. At the project design stage, the engineering talent evaluate several ways of combining different technologies which would allow to extract oil and gas from the reservoir both reliably and economically. Examples of such technologies range from simple methods, such as passive insulation to keep produced fluids as close to the reservoir temperature as possible, to the complex ones, such as subsea processing equipment to separate and pump fluids to their destinations. Flow assurance is also applied in operations to optimize the economics of production by tuning the performance of artificial lift, optimizing the routing of the produced fluids through the flowline network, and by solving the problems of restrictions and blockages or surges in reservoirs, wells, flowlines, processing equipment and in export pipelines using a variety of methods. The tasks for flow assurance and production chemistry in project development design are listed earlier in “How flow assurance and production chemistry work together.” Tasks for flow assurance support in operations: • • • • • • • • • • • •

Production system monitoring for flow assurance model tuning with system data System flow assurance condition surveillance for blockages. Maintenance implementation. Well Start-up temperature insulation performance measurement. Chemical Injection residuals' and performance monitoring. Shut-in cooldown temperature insulation performance measurement. Operator training program implementation and updates. Operating procedures updates and verification. Verification of chemicals performance. Chemicals incompatibility with materials management. Chemicals substitution and field trials. Verification of chemical vendor performance.



Why flow assurance failures happen

15

Knowledge required in flow assurance It is not sufficient to just analyze the flow of fluids, but one must also recognize and predict the temperature and phase transitions as vapor, liquid and solid phases appear at different temperatures and pressures. Therefore, a flow assurance engineer must first be prepared in measuring and calculating fluid properties and phase equilibria, which is commonly taught in chemical engineering, heat transfer, which is taught in mechanical engineering, or chemical engineering, and oilfield process equipment operation which is taught in petroleum engineering, as well as a range of other disciplines such as materials science, biochemistry, chemistry. It is not possible to get trained in all these specialties at once, so a flow assurance knowledge is acquired over time. Flow assurance is a relatively young discipline and only a few universities recently started to teach flow assurance. It is not enough to be skillful in setting up a multiphase flow model, but it is important to understand what can happen to the fluids as they flow from the reservoir to the refinery. Equally, it is not sufficient to know how to set up a scale or asphaltene precipitation model, but necessary to understand the underlying lab work and what eventualities may lead to a change in the steady operating conditions and to design chemical injection program with such eventualities taken into account.

Why flow assurance failures happen Two main reasons which explain the majority of flow assurance related incidents are: incomplete understanding of fluid properties and exceeding the safe operating limits. The first usually happens from lack of training or experience. The second may happen either due to an operator error or from operator's inability to explain to the management how exceeding the designed operating conditions will lead to a failure. Management may be motivated by a short-term incentive to reach a certain production target and request production operations to exceed the pre-determined limits; such operational deviations done without proper laboratory evaluations and technical plan seldom result in sustained improvement but can often lead to production interruptions followed by downtime, costly remediation and/or loss of confidence. A typical subsea blockage related to flow assurance may cause several months downtime plus cost upwards of $15 million, as of the writing of this book, to hire a technology for clearing it if remediation program is successfully implemented, or lead to an even costlier well workover, flowline replacement or well abandonment if remediation is unsuccessful. In extreme cases, flow assurance failure may lead to contractual sanctions stemming from inability to deliver produced oil or gas, which cost may escalate into hundreds of millions of dollars, or to a complete loss of license to operate in a given country. Usually gas hydrate or paraffin wax blockages may lead to such extreme cases. In the most extreme cases, blockages may lead to casualties. In an onshore field, a hydrate blockage driven by pressure differential moved inside a pipeline, ruptured the pipe bend and hit an operator. In the Piper Alpha offshore platform, a hydrate blockage in a condensate

16

1. Introduction

line was considered among the four likely root causes for the condensate leak and fire which sank the platform (Cullen, 1989), with 167 fatalities. In other situations, the disaster caused by solid blockages leading to a pipe rupture and a release of hydrocarbons may be narrowly averted. In one FPSO in West African waters, an ice blockage formed in a flare relief line when a cold gas stream and a warm gas stream carrying water moisture combined, which led to a rupture and formation of an explosive gas cloud, but the wind on that day was blowing away from the furnaces. In another example from US deepwater, nature may intervene to help remove a blockage, such as when a hurricane cleared a hydrate blockage. A deepwater chemical injection system methanol line connected to a scraping crossover valve got plugged as produced fluids hydrocarbon and water back-flowed past a checkvalve into the methanol line and formed a hydrate. The methanol line remained plugged until a hurricane led to an evacuation of the platform. This, in turn, triggered an automated opening of the scraping crossover valve. Warm water, accumulated behind the crossover valve in a dead leg of an actively heated flowline, flowed through the crossover valve and past the methanol line plugged with hydrate. The warm water flow initiated in the automated response to the hurricane heated and cleared the methanol line of hydrate, which was understood upon the restart of the field. This example teaches us to seek sources of energy available and accessible to overcome a blockage. In a yet another example, an onshore oil field in Siberia experienced multiple hydrate blockages in early summer within months of being put on production because the initial water cut was low (under 5%), and methanol was not being injected. Additional resources were provided to supply methanol to treat the produced fluids. However, this was costly as methanol had to be airlifted by a helicopter during the summer months because the roads were impassable. A storage facility was then constructed to provide methanol supply through the year, but a longer-term ingenious solution was implemented, which came from a local technologist, who suggested to convert one of the several producer wells to a water-producer by re-perforating the well in the aquifer zone. Heat carried by water from one well was sufficient to keep produced fluids from all the wells warm and outside of the hydrate stability region. This was possible because all wells were equipped with ESPs for artificial lift. This example not only induces us to seek the nearby energy sources which can be used for flow assurance but also shows that operators of the field have a better understanding of the field's capability and should be consulted with during concept evaluation. Blockages in onshore wells and flowlines are more routine and are much less costly to deal with. In one onshore field in North America, partial hydrate blockages occurred in wells nearly daily during the cold season, and were cleared promptly by methanol injection from a pump truck. Engineers and chemists perform various analyses of properties for reservoir fluids, including hydrocarbons, water and gas. In some cases, the fluids are not sampled adequately, and some properties, such as the presence of H2S or mercury, may be not noticed until after the startup. Retrofitting a facility to take care of such problems, if they are not known at first and discovered later, is both costly and time consuming. Proper sampling is the foundation on which the good flow assurance design and production chemistry selection are based.



17

Flow assurance background

Flow assurance background Prior to petroleum production there was water, and water was produced through wells. There are reports of scale encrustation of water wells in ancient Egypt water production system. Initial small-scale use of petroleum began in Persia and China. Early oil came from natural seeps, and wells were dug by hand or pierced with a spring pole. One of the uses of petroleum was Early petroleum production in Northern Persia, now Azerbaijan was indicated by Marco Polo and other travelers. By the early 1800s production in the region averaged 80–90 barrels per day. Large scale production of petroleum did not start until half a century later driven by increasing demand for petroleum. Around 1853, a modern version of the kerosene lamp was invented by a Polish inventor in Lviv, then part of the Russian empire and Poland, and now located in Ukraine. The reliable kerosene lamp created a steady demand for kerosene and for petroleum. Today, kerosene makes up just over 1% of refined oil products whereas 5% goes to jet fuel and 50% to gasoline (DOE, 2017, 2019). Kerosene lamps still consume as much fuel worldwide as all US jet planes combined. Besides the light, heating and transportation, petroleum also helped to reduce the hunting of whales and the dismantling of forests for fuel. The global production of petroleum kept increasing through the years. The upward inflections as shown in Fig. 1.9 in the cumulative global oil produced observed around 1860, 1910, 1960 represent technology shifts which came in response to the production demand. Below in Figs. 1.10–1.14 are few examples of how the use of technology transformed the industry to make it more efficient. In 1859, the first application of drilling technology and creation of the E&P industry took place. 10,000 1000 100 10 1 1800 0.1

1850

1900

1950

2000

0.01 0.001

Fig. 1.9  World oil produced, Billions of barrels (Azerbaijan, 2017; Geohelp, 2017; Oil150, 2017; TSP, 2017; US EIA, 2017).

Fig. 1.10  Drilling a well with a spring pole.

Fig. 1.11  Well drilled for oil using an engine.

Fig. 1.12  Geophysical survey of a well.

Fig. 1.13  Offshore drilling rig, 1947.

Fig. 1.14  Offshore rig, vessels, and barge in the Gulf of Mexico (BOEM, 1956).

20

1. Introduction

The 1910s saw science and engineering first applied to exploration & reservoir management. In the 1940s and 1950s, after the leftover military equipment and barges became available at low cost, E&P industry moved offshore; first well was drilled beyond the sight of land. The need for dealing with blockages emerged with petroleum production and became more pronounced as the production moved offshore. The paraffin deposition was observed during the early oil production in the United States and in the Russian Empire in Baku. Petroleum was first commercially produced by digging wells with a person inside an oil well bailing out the oil (Said, 1937). Early commercial production through drilled wells started in United States and Baku. Oil in Baku is waxy, but wax blockages were not reported because the oil was transported by barrels and in rail cars and was at ambient temperature, while wax deposition requires cooling. The oil was transported by wooden barrels, and later by a pipeline. The wax deposits formed on barrels and then on pump rods. Oilfield workers noticed that that clear wax helped heal scratches. Wax was then marketed as Petroleum Jelly or as Vaseline. Ludvig Nobel expanded production of petroleum to provide light and energy (it was his younger brother who invented dynamite). He also established laboratories in St. Petersburg and in Baku for research on kerosene and transport of oil in 1880 (Economides and Oligney, 2000). This energy, mainly through availability of hot water and hygiene, increased the living standards and lifespan during the 20th century. The same energy led to cheap transportation, globalization of labor sources and a decline of many developed economies and the rise of the developing countries. Natural gas production has encountered formation of hydrate blockages as early as 1930s in United States (Hammerschmidt, 1934) and 1950s USSR (Makogon, 1965). In the 1930s, natural gas production was increasing in the United States and initial blockages were reported in gas pipelines. By the 1950s, the petroleum industry also developed in Russia, and hydrate blockages also took place. It was not until the 1960s when the gas hydrates in nature were encountered. This event led to a laboratory work in Russia, and proof of the discovery of gas hydrates in nature was made by Prof. Yuri Makogon. The discipline of flow assurance started to coalesce during the 1980s as offshore production encountered phenomena such as severe slugging. Offshore production did not have the technical ability to separate gas from oil at the well site as in onshore production. The reservoir fluids, including oil, gas and water, had to flow together to an offshore platform where the multiple phases could be separated. Severe slugging occurred as liquids accumulated at the riser base when the riser pipe diameter was too large and gas only periodically lifted the liquids to the top of the platform. Engineers realized the need for predicting pressure drop in multiphase flow to select the most economic pipe size for subsea production which also allowed a stable multiphase flow. The formulas for multiphase flow then existed only in the nuclear industry which were used to calculate the flow of water and steam. Those correlations were adopted to calculate the flow of oil and gas, and with more experience and lab tests, new correlations were devel-



Flow assurance requirements

21

oped for petroleum multiphase flow as Beggs and Brill, etc. Vertical flow correlations were developed and updated by Coleman, Turner, which allowed to estimate the gas flow rate at which liquids accumulate at well bottom in a production tubing pipe if gas velocity is insufficient to lift the liquids from a well. Production and process engineers realized that individual aspects of multiphase flow assurance worked together as flow through pipes submerged in cold subsea water and gas expansion in wells and riser caused cooling of fluids which led to the formation of wax, hydrates, and sulfate scale. The term “Flow Assurance” is a literal translation of Portuguese phrase “Garantia de Escoamento.” The term "flow assurance" was coined in 1994, at the Deepstar-PROCAP Technology Exchange Workshop held at Petrobras and focused mainly on paraffins and hydrates, by the lady from Colombia by the name Magali Cotrim, who was the technology program manager for Petrobras (Minami, 2017). The term translated easily and meaningfully into English and took root. Since then, the petroleum industry saw a lot of change. Several companies recently started to use internally a new term Production Assurance. The term “Flow assurance” also exists around the globe. In Hindi, this would translate as “Pravaah Sunishchit Karya” प्रवाह सुनिश्चित करना (flow assurance work), in Russian, it would be “Obespechenie Potoka” Обеспечение Потока (assurance of flow), and in Mandarin it would be “Liu Dong Bao Zhang” 流动保障 (flow security). Prior to the English translation, the term "Garantia de Escoamento" existed as part of the Petrobras PROCAP 1000 program in Brazil (Neto, 2006). The PROCAP program which stands for Programa de Capacitação Tecnológica em Sistemas de Produção para Águas Profundas also promoted the standardization of subsea trees.

Flow assurance requirements With that brief introduction we can discuss what the flow assurance comprises and what information is necessary to perform a reliable analysis of a petroleum system to assure uninterrupted oil and gas production.

Basis of design A document listing all parameters necessary to allow planning of an approach to solving flow assurance challenges usually is known as a basis of design. Key knowledge requirements for flow assurance analysis of a system include: 1. depth profile of a wellbore and an onshore flow line elevation profile or bathymetry of a subsea flow line, a riser and an export pipeline 2. expected flow rate of produced fluids 3. environment properties 4. fluid characterization These four basic categories include multiple sub-elements. Basis of design should have as detailed information as possible about bathymetry, fluids, production profile and environment properties. Often exact information is not readily available or is too costly to obtain. In such cases, field analogs from the region may provide approximate indication of typical

22

1. Introduction

TABLE 1.3  Examples of reference conditions Temperature

Pressure

Standard cubic foot of gas United States

60 °F = 15.555 °C

14.73 psia = 1.002 atm = 101.560 kPa

Normal cubic meter of gas Europe

15 °C = 59 °F

1 atm = 101.325 kPa = 14.696 psia

Stock tank barrel

60 °F = 15.555 °C

1 atm = 14.696 psia = 0.101325 MPa

Stock tank conditions for oil in United States: 14.696 psia = 1 atm, and 60 °F = 15.555 °C. Standard conditions for gas in Russia: 101.325 kPa = 1 atm and 20 °C = 68 °F. Normal conditions for gas: 760 mm mercury = 1 atm and 0 °C. US standard conditions: 1 bar = 100 kPa = 0.1 MPa and 15 °C = 59 °F. Standard conditions NIST, United States, 101.325 kPa = 1 atm and 20 °C. Standard conditions GOST, Russia: 760 mm mercury = 101.325 kPa and 25 °C.

bathymetry, fluid behavior and environment parameters. However, analogs may differ significantly from the target reservoir.

Units for fluid characterization Reference conditions for measurement of hydrocarbon properties vary regionally. It is important to define which system of units will be used in a project. Standard conditions even vary for defining the linked units such as quantities of gas and oil used in the gas oil ratio (GOR). Gas is measured in standard cubic feet, standard cubic meters or in normal cubic meters. However, gas is sold by its heating value because different compositions provide different amounts of heat when combusted Oil can be measured and is sold by stock tank barrels, cubic meters or metric tons, with various quality oils getting different market price. The “standard” conditions at which fluid quantities are defined vary for liquid and for gas. Measurement of liquids by mass usually yields the least error compared to measurement by volume. Several examples are shown below in Table 1.3. An engineer has to verify in any PVT-related fluid analysis work that the units used to describe fluid properties match those used in the project. The reference conditions should be defined in the Basis of Design. Mass definition of a metric ton does not vary with temperature or pressure. The variability of the volume metrics leads to sale contracts for natural gas using caloric or heating value of the gas obtained upon its combustion.

Introduction to flow assurance risk analysis A flow assurance specialist's objective is to make sure that a project is designed for safe and reliable operation in relation to flow assurance issues and that all “boxes are checked.” For that, we first must define what those boxes are because if we can measure, we can improve. Flow assurance becomes an analysis of thermal, hydraulic and fluid-related threats to flow and fluid quality and mitigation of these threats with equipment, chemistry and procedure. This analysis lends itself well to a “bowtie” risk analysis (Fig. 1.15).



23

Introduction to flow assurance risk analysis

Fluid flow

Thermal hydraulic fluid-related

Threats to

Fluid quality Pipe integrity

Equipment Mitigation with

chemistry procedure

Fig. 1.15  Graphic of a bow-tie risk analysis for flow assurance.

The bowtie risk analysis is well suited to look at how well the protective barriers against flow assurance threats are placed, and how well the remediation efforts can prevent the undesirable consequences. Thermal threat may seem redundant as viscosity (hydraulic) and solids (fluid-related) effects emerge as fluids cool down, but one should remember about the high temperature aspects of HPHT. We can't flow if we can't effectively use corrosion inhibition at high temperatures. Flow assurance helps with HPHT as well. An example is the 143 km long Snohvit line in the N.Sea. Typical corrosion inhibitor chemicals may lose efficiency above 250 °F. Snohvit field uses a cooling spool section of flowline long enough to cool the hot produced fluid with seawater to 250 °F before switching to a carbon steel flowline. Regular corrosion-resistant alloys (CRA), which may be used to transport corrosive fluids, also may have temperature limitation of 85 °C. The seven steps to flow assurance risk management include: (1) Define data source (2) Define objects to view (3) Define the factors and threats (4) Describer the mitigations and inspections (5) Create an integrity model (6) Calculate relative risk from threats (7) Assign mitigations and inspections to each threat After the mitigations and inspections are identified, the operations cycle may go into the usual continuous improvement loop of Plan-Do-Check-Adjust to eventually achieve steady quality. Risk analysis aims to quantify threats in order to achieve an economic balance between prevention and cure. Every field is different, and in very remote areas without developed infrastructure, the access to remediation technology for a formed blockage may take a very long time which will significantly affect production and revenue, so less risk may lead to a better project profitability. Conversely, in a region with abundant services, the time to call in blockage removal specialists may be minimal so more risk may be taken and some upfront capital and operating cost may be saved without significant additional impact to the net value of the project. Before one starts to analyze flow assurance risk in order to save cost and optimize budgets, one should develop a list of relevant parameters to allow planning of our approach to solving flow assurance challenges. As said above, the relevant parameters will be region-specific.

24

1. Introduction

Threats to flow are normally attributed to flow assurance Flow assurance aims to achieve an economic balance between prevention and mitigation of mechanical or hydraulic restriction threats to flow such as hydrate plugs, scale plugs, severe slugs, liquids holdup, wax plugs, asphaltene plugs, without reaching the costly remediation stage. The detailed risk analysis of each threat compares the probability or frequency of it happening during the life of field and the cost of the consequence against the cost limit acceptable to each specific operator. Some operators may have a company policy that no risk of blockage is acceptable because the contractual cost of a disruption to production can be very high while others rely on their own experience and laboratory verification to accept some amount of risk. However, risk analysis performed by specialists, who may soon retire, should be viewed with additional independent verification. A detailed understanding of the flow system and fluid properties are required in order to develop a coherent design for field development.

Threats to product value or process safety (asset integrity) Asset integrity or product value also get affected in some cases, such as severe slugging in an un-braced flowline or jumper, a hydrate projectile movement during depressurization, erosion by sand or treatment with methanol. Production chemistry deals with prevention and mitigation of fluid composition threats to product value or process safety (asset integrity) such as water in oil, oil in water, salt in oil, oxygen in water, mercury in fluids, H2S in gas, corrosivity, and/or bacteria.

Hardware cost The cost of hardware keeps continually increasing. The cost of subsea tiebacks has been getting more expensive in the past two decades well outpacing the inflation.

Cost of subsea hardware related to flow assurance It is prohibitively expensive to place a floating host facility with separation and processing of produced fluids over each drill center. Such platforms, like Pompano, do exist in deepwater and use dry trees to produce fluids. It is more economic to use subsea tiebacks to produce hydrocarbons from several drill centers or several neighboring fields to the same host facility. Infrastructure-led exploration (ILX), or looking for more hydrocarbons near the existing facility, is key to deepwater profitability. Not only this allows to tie in new fields to the existing facility, but it also allows export of separated hydrocarbons via existing export lines, which improves project economics. The highest net present value (NPV) deepwater project to-date is Na-Kika (Riazi, 2016) designed by Shell and operated by BP in the US Gulf of Mexico with multiple subsea tie-backs. Na Kika translates as octopus (Encyclopedia Mythica). ILX means that several commercially producible average sized fields must exist within a 10–20 km radius which can be tied back to the common host facility. Production of petroleum from these fields may then be scheduled in phases, allowing less risk in capital investment.



25

Hardware cost

An asset similar to the Na-Kika semi-submersible platform with several gas and gas condensate fields producing to the common host Independence is operated by Anadarko. However, an oil company venturing into deepwater must first be able to find the oil before flow assurance analysis gets done. As a recent example, the largest US exploration and production operator had to exit its deepwater exploration business in 2015 as the costs of several dry hole wells which didn't strike commercial oil quantities and the subsequent contractual costs of the drilling rig termination amounted to near one billion dollars (Conoco, 2016a,b). The deepwater assets also range in quality and range from top-tier assess such as Na-Kika or Atlantis, to technology-intensive and risky Paleogene assets which often carry the whole range of flow assurance fluid problems such as high oil density, asphaltenes, wax, scale and hydrates. ILX is key, but we also need to be smart about how we produce and process multiple fluids because fluids may be incompatible and create flow assurance problems when mixed or comingled. Flow assurance analysis of multiphase flow stability and flowline sizing analysis, together with reservoir model, define production rates and the project NPV. Flow assurance has the tools to optimize the project and to deliver production reliably from nearly any distance. However, average installed cost for longer subsea tiebacks has been getting progressively more expensive in the past. This is not a recent but a sustained trend. A similar trend in pipeline costs as shown in Fig.1.16 is present both offshore and onshore, with offshore costs being roughly double the onshore cost due to the higher cost of installation and insulation. Recent growth in shale production saw the use of less costly fiberglass gathering pipelines in response to the need to rapidly and inexpensively establish a gathering infrastructure. The fiber lines serve well but are not resilient to freezing weather when pipes sometimes fail due to soil heaving. Fiber lines are well suited for service as single phase flow for water or stock tank crude, but their use as gathering flowlines carrying multiphase flow needs to be decided with care and flow assurance analysis because tee fittings at pipe merge points sometimes fail due to the repeated impacts of slugging flow on the tee connections. 8

R² = 0.9948

4

2

1 1990

1995

2000

2005

2010

2015

Fig. 1.16  Cost-per-installed-mile of offshore tiebacks doubles every 8 years (in USD million). 1996 average cost-per-mile for offshore construction was $1.61M. 2001 average cost-per-mile for offshore construction was $2.58M. 2008 average cost-per-mile for offshore construction was $5.37M. 2013 average cost-per-mile for offshore pipeline construction was $7.6M (USAID, 2008; Smith, 2012, 2013).

26

1. Introduction

As of 2017, offshore shelf production is among the most economic sources of petroleum. While it costs US$54 to produce one barrel on average in the world, both offshore shelf and deepwater are below the average as shown in Fig. 1.17. To become profitable, the wells have to produce roughly three times their cost. Average onshore well may cost $3–4 million. Average shale well may cost $6–7 million including drilling, completion and fracturing. A deepwater wells cost significantly more, with a range of $75–175 million depending on depth and time it takes to drill. This means that an average deepwater well must produce, on average, 7 million barrels of oil to bring profit. Deepwater reservoirs are usually prolific, with annual decline rate of around 10%, and last for at least 20, sometimes 30+ years, with typical host facility design life of 25–40 years. If a deepwater well produces for 10 years, it has to flow at least 2000 barrels per day to bring profit. Such rates are on the low side for deepwater, with most wells flowing 10–20 thousand barrels per day (Riazi, 2016, p. 636). Payback time for the best producing wells in deepwater is less than a year. Conversely, shale wells decline rapidly, with first year decline rate of around 60% as shown in Fig. 1.18 and Table 1.4 (meaning production in year 2 is just 40% of production in year 1). However, there is a large resource to tap with shale production, in both oil and gas. If a shale well produces for 10 years, it has to flow at least 628 barrels every day in the first year to bring profit. Such rates do exist in shale production as shown in Table 1.5, but are on the high side, with average new Bakken well producing 476 bo/d in 2016, Wolfcamp in Texas producing 463 bo/d and US-average new 2016 shale well flowing 241 barrels of oil per day in the first year (Shaleprofile, 2017). While comparatively more productive, fields in deepwater present more risk due to its remoteness and cold, deep environment, and require a more thorough engineering design. Flow assurance is applicable both to shale onshore and to deepwater, but the much higher cost of fixing a problem makes flow assurance analysis mandatory if not central in the development of deepwater projects. Of course, flow assurance analysis can only be performed after the oil is found, which leaves the seismic data processing as the most important technology for the deepwater petroleum industry. Average cost to produce 1 barrel of oil, USD 80 70 60 50 40 30 20 10 0 Middle East

Shelf offshore

Russia

Other

Deepwater Shale

Oil sands

Arctic

Fig. 1.17  Cost of oil production, based on Rystad Energy, Morgan Stanley Commodities Research.



27

Hardware cost

Fig. 1.18  U.S. Shale oil production (Shaleprofile, 2017). TABLE 1.4  Unconventional shale production and decline rates Year of start

2010

2011

2012

2013

2014

2015

2016

Wells

5285

8938

11,390

13,140

15,050

11,052

6363

1st year bo/d

335,850

819,919

1,346,022

1,832,589

2,526,619

2,001,761

1,532,171

2nd year bo/d

154,364

346,053

565,828

737,020

1,006,962

789,541

Decline

54%

58%

58%

60%

60%

61%

1st year bopd/well

64

92

118

139

168

181

(Shaleprofile, 2017).

TABLE 1.5  Production rates from prominent shale plays in 2016 Bakken

Wolfcamp

United States

bo/d

235,341

326,847

1,532,171

Wells

494

706

6363

bopd/well

476

463

241

233

28

1. Introduction

Monitoring and data mining A consistent set of metrics allows for lasting risk mitigation, and for the ability to extract value from technology. If we can measure, we can improve. Integrated analysis based on monitoring and modeling would allow near-term forecasting of flow assurance issues with automated response. Realtime monitoring of production allows operator to know downhole parameters, plan the deployment of chemicals and to perform integrated analysis of production & near-term issues forecasting. All fields are equipped with some instrumentation for measurements and automation. Many fields analyze these collected data to forecast the production. Some fields rely on automation to monitor and analyze the data in real time to alert the operator to changes in flow. Few fields actually can automatically predict and alert of an imminent flow assurance restriction or plug so the operator could deploy the mitigation measures such as chemical injection or heating. With time the integrated analysis based on flow monitoring and modeling would allow near-term forecasting of flow assurance issues with automated response in more fields.

Flow assurance in operations Onshore production Common problems encountered in onshore operations are: reservoir souring, liquids loading and slugging in wells, hydrate, scale and paraffin blockages in wells and gathering flowlines, slugging in in-field gathering lines, hydrate blockages in process plant lines and equipment. Asphaltenes can occur in undersaturated reservoirs without gas cap and in wells. Gas fields can experience deposition of diamondoids and elemental sulfur in well tubing. Sour fluids have elevated content of CO2 or H2S or both. Mercury is not uncommon in gas fields near continental rifts such as Asia-Pacific region. Overpressured reservoirs contain fluids at pressure higher than hydrostatic. This is rare but can happen in consolidated reservoirs, fractured reservoirs and in weakly consolidated reservoirs both onshore and offshore. High pressure high temperature reservoirs bring additional constraints on material selection.

Offshore production Shallow water production encounters the same problems as onshore with addition of severe slugging caused by a significant elevation difference between a subsea flowline and the platform topsides. Similar to liquid loading in an onshore well, liquids accumulate at the riser base and get periodically produced by gas backpressure to the topsides separator. Severe slugging affects stability of production in two ways: periodic movement of liquid slugs causes regular impacts at flow path elbows and fatigue of both flexible and rigid risers, and also surge of liquid can overfill the separator volume if the transfer pumps or the separator size or both are undersized.



Systematic approach to solving flow assurance problems

29

Deepwater production Deepwater reservoirs tend to be at pressure higher than bubble point thus undersaturated and can be pre-salt or subsalt. In addition to the above problems, this adds the problems of asphaltene deposition in flowlines and deepwater wells. High salt content in produced water may also affect the potential for scale deposition and limit the types of chemicals which may be brought in contact with produced water without forcing salt to precipitate out of the water as scale. Both onshore and subsea production of oil and gas experience flow assurance issues. The key distinction between the two is the remoteness of subsea equipment. The remoteness of deepwater fields makes fixing any issues much more complex subsea, requiring the development and use of new technologies and significantly more planning in the project development stage not unlike a space station. Attempts to design one piece of equipment and to build many have mostly been uneconomic because the reservoirs and fluids vary from well to well and from zone to zone. However, subsea tree pressure ratings have become standardized in 5000 psi increments. Flow assurance as a discipline started with the needs of subsea production. With the advent of subsea and then deepwater production hydraulic restrictions to flow such as liquid holdup began to affect production causing flow instabilities. Currently the horizontal wells experience similar flow instability and may benefit from the experience accumulated in subsea production.

Systematic approach to solving flow assurance problems The knowledge of all possible flow assurance issues and their interdependence may help correctly identify and treat a problem. Many other aspects of flow assurance exist that are not listed above among threats such as flow performance of various artificial lift methods, performance of various restriction prevention and blockage remediation technologies, multiphase boosting, controlling high fluid temperature and these will be discussed further. Some of the flow assurance threats may appear in any location of the production system: from reservoir pores and production well perforations to topsides or surface process equipment to export or water injection pipelines and injection well perforations. These threats are known to happen onshore or offshore, in surface or topsides lines, in fluid separation process equipment or LNG liquefaction process, flares or any other location where conditions allow any of these threats to appear. Temperature, pressure and fluid composition dictate where one or more of these threats will appear. Therefore it is common to overlay curves showing where each threat may appear (known as phase boundaries) on the Pressure-Temperature chart showing where vapor and liquid coexist (known as a phase diagram or a phase map). The phase diagram may be regarded by a practicing engineer as a map. The more detailed and accurate is the knowledge about fluid and environment properties, the better flow assurance strategy may be developed using that map. Flow assurance analysis may rely on very little knowledge, utilizing rules of thumb or common perceptions about flow assurance threats

30

1. Introduction

for systems where blockages are easily remediated and leaks easily addressed. However, for remote systems in deep and ultra-deep water the amount and the level of detail of required knowledge about the reservoir fluids and the environment is substantial.

Process safety One of the more notable yet sad examples of the interaction of flow assurance and process safety is the 1989 Piper Alpha disaster. The Lord Cullen investigation report named gas hydrates as one of the four potential causes for the condensate leak which was the root cause of the explosion. Loss of primary containment (also known as leaks) are known to have been caused by hydrate or ice blockages formation because both expand upon freezing or by their sudden dislodging and movement, mainly onshore or on topsides. Subsea water may act as a buffer partially absorbing movement of the pipe with blockage moving inside it, thus subsea leaks caused by flow assurance blockages are less known. A field operation example and learning of process safety during depressurization of hydrate blockages has been described by Makogon (ICGH9, 2017).

System of measures for flow assurance Three characteristics named above (safety, reliability and economics) are related to the socalled iron triangle of flow assurance project management which measures are: quality, time and cost. Safety includes both process safety and personal safety. Safety and reliability fall under the quality category; a higher quality system will have fewer incidents and will be safer to operate. Reliability is measured as time and economics is measured as cost; a lower cost system may have more failures, and project economics will be affected. Reliability translates into the expected frequency of failures. Safety and economics also have the time metric; non-­productive downtime and the number of recordable incidents and reportable process excursions are reported per unit time. Thus every component of flow assurance project management is related to time, the only measure not subject to inflation. A flow assurance engineer engaged in a design of a new project has to keep all three metrics in mind, otherwise designs will be too costly and not get sanctioned for implementation. A proper design addresses all personal and process safety threats presented by produced fluids, strikes a price-performance balance between complete prevention and partial control of flow assurance threats for the duration of the life of field, and allows the operator to reliably produce reservoir fluids.

Outlook for flow assurance Easy flow assurance challenges in onshore and deepwater have been solved with multiple technologies developed and deployed over the past two decades. As energy operators may be moving to new ultra-deep basins or to more complex fluids, flow assurance will be faced with new challenges and with their combinations, where one change in fluid composition

References 31

or property may trigger one or more other changes. There will also be an increasing need for the development of more cost-effective solutions for unconventional onshore and then unconventional offshore production. Use of multiphase flow tools to optimize well geometry would extend the time of natural depletion production and generate CapEx savings because fewer wells would be needed. The use of realtime monitoring and multiphase flow modeling for production and chemical deployment optimization would also optimize OpEx. This represents a total net value approach to flow assurance. Similar to the total net value analysis, there is an integrated system or a holistic analysis. As industrial and academic research jointly developed low dosage hydrate inhibitor (LDHI) chemistries, so there is happening a conceptual change where keeping multiphase flow analysis and chemistry selection apart is no longer an affordable approach because project design solutions depend on both multiphase flow and chemistry simultaneously. One example of integrated technology innovation is that service providers are adopting a process to provide integrated solutions for flow assurance and production chemistry. Another example of innovation is finding new uses for existing technology: a subsea scraper launcher historically used for pipeline dewatering after a hydrotest and for wax maintenance scraping; now is used in GoM for hydrate mitigation by untreated produced fluid displacement. Some operator companies, particularly the ones with offshore assets name flow assurance among the technologies strategically important for the growth, along with seismic exploration and drilling wellwork (Murphy, 2015). We have at our disposal the same number of solutions: chemical (alter interface), mechanical (displace, scrape or jet), thermal (heat or cool), and process (separate, depressurize or pump), but just as there can be an infinite number of melodies with only seven musical notes, the industry can combine technologies to move to new harmonious solutions, driven by cost in the coming decades. When a project is borderline economic, a flow assurance specialist can act as an architect arranging the solutions together to help find a field development concept for stable uninterrupted production and make the project economic. Conversely, if the project design is “goldplated” with multiple risk management margins and allowances even a strong project can become uneconomic and not pass the capital allocation sanction review. It is important to keep track of all safety margins added to the design, particularly so in flow assurance and in production chemistry calculations.

References Alaska, 2008. Department of Environmental Conservation. http://dec.alaska.gov/spar/ppr/response/sum_ fy08/071216301/images/flir_071216.jpg. (Accessed 17 November 2017). Alaska, 2010. Department of Environmental Conservation. https://dec.alaska.gov/spar/ppr/response/sum_ fy10/091129301/maps/091129301_FLIR_29Nov2009_01.jpg. (Accessed 17 November 2017). Azerbaijan, 2017. Petroleum industry in Azerbaijan (for years pre-…1850). en.wikipedia.org/wiki/Petroleum_industry_in_Azerbaijan. (Accessed 10 November 2017). BOEM, 1956. Jesse Grice Collection (photo number 242-16). Morgan City Archives. https://www.boem.gov/ ESPIS/4/4530.pdf. (Accessed 7 November 2017). Caspersen, J.H., et al., 2011. Multiphase flow laboratory, SINTEF. https://www.sintef.no/globalassets/upload/petroleumsforskning/brosjyrer/multiphase_flow_laboratory.pdf, accessed 4/7/2019; SINTEF, 2010, http://www. sintef.no/home/sintef-energy/xergi/xergi-2010/artikkel6/. (Accessed 10 November 2017).

32

1. Introduction

Conoco, 2016a. News release. conocophillips.com/newsroom/Documents/2016/2016_0204.pdf. (Accessed 17 November 2017). Conoco, 2016b. Annual report 2015. static.conocophillips.com/files/resources/conocophillips_2015_annualreport. pdf. (Accessed 17 November 2017). Cullen, H.L., 1989. Inquiry in to Piper Alpha Disaster (part II). DOE, EIA refinery yield data, 2017, 2019. US Department of Energy. tonto.eia.doe.gov/dnav/pet/pet_pnp_pct_dc_ nus_pct_m.htm (Accessed 10 November 2017); https://www.eia.gov/dnav/pet/pet_pnp_pct_dc_nus_pct_m. htm (Accessed 4 April 2019). Economides, M.J., Oligney, R.E., 2000. The Color of Oil: The History, the Money and the Politics of the World's Biggest Business. Round Oak Publishers, p. 88. Encyclopedia Mythica English dictionary. https://pantheon.org/articles/n/na_kika.html. (Accessed 4 December 2019). Geohelp, 2017. History of the World Petroleum Industry, The virtual Geology Department, (for years 1814, 1818). www.geohelp.net/world.html. (Accessed 10 November 2017) — for Ohio, Kentucky. Hammerschmidt, E.G., 1934. Formation of gas hydrates in natural gas transmission lines. Ind. Eng. Chem. 26(8), 851–855. Hu, Y., Makogon, T.Y., Karanjkar, P., Lee, K.H., Lee, B.R., Sum, A.K., 2017a. Gas hydrates phase equilibria and formation from high concentration NaCl brines up to 200 MPa. J. Chem. Eng. Data 62, 1910–1918. Hu, Y., Makogon, T.Y., Karanjkar, P., Lee, K.H., Lee, B.R., Sum, A.K., 2017b. Gas hydrates phase equilibrium with CaBr2 and CaBr2 + MEG at ultra-high pressures. J. Nat. Gas Eng. 2, 42–49. Hu, Y., Makogon, T.Y., Karanjkar, P., Lee, K.H., Lee, B.R., Sum, A.K., 2018. Gas hydrates phase equilibria for structure I and II hydrates with chloride salts at high salt concentrations and up to 200 MPa. J. Chem. Thermodyn. 117, 27–32. Lebedev, A., 2010. Scale buildup inside a heat exchanger tube. https://upload.wikimedia.org/wikipedia/commons/0/06/Limescale-in-pipe.jpg. (Accessed 4 November 2019). Makogon, Y.F., 1965. Образование гидратов в газоносном пласте в условиях многолетней мерзлоты. Газовая промышленность, 5, издательство Недра (Hydrate formation in gas bearing strata in permafrost regions, Gazovaya Promyshlennost, Izd. Nedra 5). Makogon, T.Y., 2017. Process safety of hydrate deposition in orifices during a blowdown of line plugged with hydrate. In: Proceedings 9th International Conference on Gas Hydrates, Denver, Colorado. Minami, K., 2017. SPE flow assurance technical section meeting, personal communication. Morais, J.M., 2013. PETRÓLEO EM ÁGUAS PROFUNDAS: Uma história tecnológica da PETROBRAS na exploração e produção offshore, Instituto de Pesquisa Econômica Aplicada. www.ipea.gov.br/agencia/images/stories/ PDFs/livros/livros/livro_petrobras_aguas_profundas. (Accessed 10 November 2017); http://www.ipea.gov.br/ portal/images/stories/PDFs/livros/livros/livro_petrobras_aguas_profundas.pdf (Accessed 4 April 2019). Murphy, 2015. Murphy.com. (Accessed October 2015). Neto, J.B.O., 2006. O processo de aprendizado tecnológico na trajetória do sistema de produção flutuante empreendido pela petrobrás em seu programa de capacitação tecnológica em águas profundas – PROCAP, Masters thesis. Universidade Federal do Parana. http://www.economia.ufpr.br/Dissertacoes%20Mestrado/117%20-%20 José%20Benedito%20Ortiz%20Neto.pdf. (Accessed April 4, 2019). Nilsson, R., et al., 2010. Flow: 25 years of multiphase subsea transport of oil and gas, SINTEF. https://www.sintef. no/globalassets/project/oilandgas/pdf/flow.pdf. (Accessed November 10, 2017). Oil150, 2017. Early crude oil production levels and pricing, (for years 1858–95). www.oil150.com/about-oil/early-crude-oil-production/ (Accessed 10 November 2017), for United States, Canada, Russia. Riazi, M.R. (Ed.), 2016. Exploration and Production of Petroleum and Natural Gas. ASTM International manual, p. 647. Said, K., 1937. Ali und Nino, publisher E. P. Tal & Co / Verlag. Shaleprofile, 2017. shaleprofile.com. (Accessed 16 November 2017). Smith, C.E., 2012. Near-term pipeline plans grow, longer-term projects sag. www.ogj.com/articles/print/vol-110/ issue-2/transportation/special-report-worldwide/near-term-pipeline.html. (Accessed 17 October 2014). Smith, C.E., 2013. Worldwide Pipeline Construction: Crude, products plans push 2013 construction sharply higher, 02/04/2013. www.ogj.com/articles/print/volume-111/issue-02/special-report--worldwide-pipeline-construction/ worldwide-pipeline-construction-crude-products.html. (Accessed 17 October 2014).

References 33

TSP, 2017, Historical Energy Production Statistics, (for years 1900–2014), www.tsp-data-portal.org/EnergyProduction-Statistics#tspQvChart, (Accessed 10/10/2017). US EIA, 2017, United States Energy Information Administraion Historical Statistics, (for years 1981–2010), https:// www.eia.gov/beta/international/data/browser/, (Accessed 10/10/2017). USAID, 2008, Natural gas value chain: pipeline transportation, www.sari-energy.org/PageFiles/What_We_Do/ activities/GEMTP/CEE_NATURAL_GAS_VALUE_CHAIN.pdf (Accessed 17 October 2014), http://sari-­ energy.org/oldsite/PageFiles/What_We_Do/activities/GEMTP/CEE_NATURAL_GAS_VALUE_CHAIN.pdf. (Accessed 8 April 2019).

C H A P T E R

2 Initial diagnosis and solution of flow assurance production problems in operations O U T L I N E Field or laboratory tests for initial solid samples identification Field laboratory initial tests for solid samples identification

Field analysis Laboratory analysis

40 40

40 40

Typical blockage remediation plan

42

An operator may interpret the telltale signs of flow assurance problems to help identify them first and then select the best solution. We can attribute characteristics of flow assurance issues to the two parameters usually measurable in the field: pressure and time. Pressure measurement is commonly available in the field production systems. Operations usually have a limited instrumentation installed on production systems, but most systems have the pressure measured at the tree upstream and downstream of the choke, and some have gauges downhole in a well which measure pressure in real time or as a retrievable recorder. Some chemical skids may have a chart recorder. Any additional available measurements such as temperature, water cut, flow rate, ultrasonic or dielectric signal will help verify whether the initial identification of flow assurance issues makes physical sense. Time is the other parameter commonly measurable in the field. It may be possible to tell which problem is likely taking place by evaluating the time it took for the readings to change. Both time and pressure need to be evaluated together. Hydrate plugs can develop as quickly as in tens of minutes, or as slowly as in days. Scale restriction may form as quickly as in 1 day, or build over the period of weeks. This distinction of time can be used to help differentiate between different types of blockages when conditions for several different blockage types are present in the production system simultaneously. Table 2.1 suggests a preliminary list of possible causes for a pressure change in a flowing system, depending on how quickly that change occurred.

Handbook of Multiphase Flow Assurance https://doi.org/10.1016/B978-0-12-813062-9.00002-6

35

© 2019 Elsevier Inc. All rights reserved.

36

2.  Initial diagnosis and solution of flow assurance production problems in operations

The most common differential pressure increase or no flow during a restart of a shut-in system can be caused by a hydrate formed after MEG supply failure, scale after water breakthrough, by a wax or asphaltene partial restriction cemented by a hydrate, a waxy gel, or by a closed valve. Other types of pressure behavior on a relative timescale with possible causes are described below. Restriction may be partial or complete. If there is pressure communication through a restriction, solvent should be injected if safe to do so, in order to retain the pressure communication. Below is provided a short summary of the general characteristics of each type of flow assurance issues, deposits or flow restrictions. Additional characteristics of the flow assurance problem may be obtained from deposits collected at a separator inlet screen, or from the observation of system behavior. Some general characteristics listed below may be used to confirm the possible cause. Asphaltene—hard and dark in color, heavier than water. Occurs in both light and heavy oils. Common locations are in reservoir, in well production tubing, at subsurface safety valve, in tree and in flowline. Bacterial deposit—can be a soft accumulation in pipe or process equipment, or a hard biodome inside a line pipe. Typical location is in surface water processing equipment. Corrosion products—usually nonmagnetic. Can occur in any part of the production system from well bottomhole to export pipeline when a chemical is present which takes TABLE 2.1  Types of pressure behavior on a relative timescale with possible causes Type of differential pressure change

Time of differential pressure change Minutes to hours

Hours to days

Days to weeks

Weeks to months Wax, liquid (water or condensate) holdup in long export line

Single increase

Mechanical, stuck Scale, hydrate scraper, closed valve, plugging a gas line leak with seawater ingress

Asphaltene, liquid holdup in intrafield line

Multistep increase

Hydrate plugs forming in oil line

Multiple hydrate plugs dissociating

Sand in intrafield line

Single peak

Water hammer, liquid surge

Injector well damage Waxy gel breaking with relief

Multiple oscillations

Slugging, well liquid Severe or terrain loading, choke PID slugging controller

Single decrease

Leak, hydrate plug movement

Hydrate with wax compaction

Hydrate forming in a Scale formation shut line damage

Multistep decrease

Controlled depressurization

Single trough

Asphaltene formation damage with subsequent relief downhole

Pressure buildup from gas hydrate deposit Reservoir depletion



2.  Initial diagnosis and solution of flow assurance production problems in operations

37

electrons from the production system wall material and dissolves it. Iron sulfide (black powder) can be pyrophoric when exposed to air. Diamondoids deposition (adamantane, diamantane, triamantane)—looks as a white solid. Diamondoid deposits commonly occur in gas and gas condensate pipelines. Emulsions are fluid but can be very viscous if stabilized by solids. Stability is caused by asphaltenes, chemical inhibitors, mineral fines or waxes. Emulsions commonly occur from wellbore to surface or topsides process equipment, but can also be present in reservoir. Erosion of pipes, pipe elbows or valves—caused by droplets and solids. Typically occurs at locations where flow changes direction. Erosion corrosion can occur where a fluid flow at high velocity strips away the protective film of corrosion product or inhibitor from a pipe wall. Flow assurance solids such as hydrate can contribute to corrosion and to erosion. Fines produced from reservoir accumulation in lines or process equipment—common in weakly consolidated reservoirs such as deepwater Gulf or Mexico, South America or West Africa. Usually mineral fines accumulate in locations where flow velocity is insufficient to fluidize and carry the solids. Flow-induced vibration or pulsation of flow line or jumper—caused by higher than designed flow. Can occur in jumpers and locations where flow changes direction and bracing is insufficient to keep the flow path rigid, usually above flow rates of 2 mbd/in.2 or 58 GPM/in.2. Foaming—can be caused by high flow, shear, incompatible fluids, improperly mixed chemicals. Can occur downhole, in flowlines or in process equipment. Holdup of liquids in flow lines or in pipe lines—can be caused by flow velocity insufficient to sweep liquids as in flow turndown scenario, or triggered by pressure oscillations. Usually occurs in low spots and can cause terrain slugging. Hydrate blockage—occurs in vertical, horizontal and inclined lines. Accumulates in low spots. Occurs where five conditions are met: high pressure, low temperature, presence of water (as liquid, vapor or ice), presence of hydrocarbon (gas or oil with dissolved gas), and flow shear insufficient to sweep the solids. Hydrate is usually more thermodynamically stable than ice and can form in LNG process equipment. Hydrate is translucent and usually dissociates with bubbles when exposed to atmosphere. Ice blockage—can occur in low-flow or dead leg line pipe. Also can happen downstream of a flow restriction, or in flare relief lines when two streams, cold and moist, combine. Injectivity damage for injector wells—caused by biofilm or unfiltered solids or high dosage chemicals. Can occur over time as unfiltered solids accumulate in the injection well perforations, or from a sudden flow rate change as solids settled in the water injection pipeline get fluidized and transported downhole. Joule-Thomson cooling or J-T heating of produced fluids—caused by thermodynamic response of hydrocarbon fluid to pressure change. Saturated fluid below the bubble point pressure experience J-T cooling upon pressure decrease. Undersaturated or supercritical fluid experiences heating upon pressure decrease as in well flow. Loading of wells with liquids during multiphase flow occurs when gas kinetic energy is insufficient to overcome liquid gravity. Typically occurs when gas flow velocity is below 2 m/s or 7 ft/s but depends on interfacial entrainment of liquid by gas (related to surface tension).

38

2.  Initial diagnosis and solution of flow assurance production problems in operations

Mercury accumulation in flow lines, process equipment and product streams—occurs where mercury or organomercury is not soluble in the produced stream, usually at low temperature. Mercury is a shiny liquid. Organomercury is clear volatile liquid, strong neurotoxin and easily penetrates some PPE such as latex gloves. Mercury compounds in hydrocarbons commonly occur in continental rim areas. Naphthenates deposition in flow lines and process equipment occurs when produced fluids have both natural acids dissolved in oil and metals such as calcium dissolved in water. Deposits are highly viscous. Oil quality noncompliance due to water content—occurs in surface process equipment due to insufficient residence time or insufficient temperature to resolve water-in-oil emulsion. Productivity damage for producer wells—occurs when solids or liquids adsorb on rock surface and reduce the pores cross section area and permeability. Deposits may be organic such as asphaltenes, heavy oil fractions and inorganic such as sand or scale. Flow shear and pressure drop caused by higher flow velocity in the near-wellbore zone may cause asphaltenes precipitation. Subsequent well workover with an acid may further destabilize asphaltenes. Sand deposition in lines, process equipment or valves. Sand can be produced from wells where rock consolidation or cementing was lost, such as in wells ramped up quickly, or wells which have experienced reverse flow (bullheading) through a gravelpack completion. Cementing of sand grains in near-wellbore zone can be lost during production of gas hydrate deposits where hydrate was the cementing agent but dissociated to recover natural gas. Also cementing can be lost in regular oil or gas wells if a chemical which can dissolve water such as methanol or methanol-based chemical is pumped to and stays in the perforations. Methanol dehydrates rock, and sand production may start or productivity damage may occur. Scale deposition and scale products accumulation in flow line and process equipment— happens when temperature, pressure and composition of both produced hydrocarbons and produced water are such that all mineral dissolved in water at reservoir conditions cannot remain dissolved in water at wellbore, flowline or separator conditions. Seawater injection can cause barite scale deposition. Barite has toxic barium ions but is nearly insoluble in water so does not affect health. Barium carbonate scale is toxic and strontium sulfate scale can be radioactive. Slugging: severe (terrain-induced) and hydrodynamic (gas flow-induced)—results in significant pressure oscillations and in impacts of liquid slugs at bends and process equipment. Typically occurs in near-horizontal gas and gas condensate production both onshore and subsea, and in horizontal-come-vertical flow geometries such as in deepwater multiphase tiebacks and in shale horizontal well production. Terrain-induced or severe slugging is caused by insufficient energy of gas to lift liquids from a low spot such as riser base, similar to well liquid loading. Hydrodynamic slugging occurs during a change in gas flowrate (usually ramp-up or increase) when gas at higher velocity sweeps liquid from its steady-state holdup locations and brings the surge of liquid to a bend or to an outlet. Slugging can occur with time period of minutes to days. Souring of produced fluids can occur when water injected into the reservoir to maintain reservoir pressure brings sulphates which is food for sulfate-reducing bacteria present in



2.  Initial diagnosis and solution of flow assurance production problems in operations

39

the reservoir. SRB bacteria flourish in reservoir zone with temperature between 10 and 50 °C and generate sour chemicals. Seawater treated with desulfation has less impact on souring. Usually it takes several years for sour components to migrate through the reservoir to producer wells. Faster souring may occur if there is streaming from injector to producer wells. Stuck scraper during pipeline commissioning or during flow line maintenance—can occur when the energy of fluid propelling the scraper (a piston) is insufficient to overcome the viscosity or Young's modulus of material being scraped. Can also happen when a scraper gets tilted in a valve cavity, in a wye or on a deposit or obstruction and loses seal against pipe wall allowing propelling fluid to freely bypass it. Sulfur deposition in well tubing or in flow line—occurs when solubility of elemental sulfur S8 in produced fluid at reservoir conditions is higher than at well or flowline conditions. Elemental sulfur is yellow, not transparent and in its solid form is not toxic. Underdeposit corrosion generally occurs from neglect for regular maintenance cleaning of the flowline during its operation, or from inability to clean the line if it was designed without such ability. Deposits of sand, precipitated wax, asphaltene, scale and their combinations occur where flow velocity is low, usually less than 1 m/s. Deposits prevent corrosion inhibitor from reaching the pipe wall, or allow bacteria to grow depending on conditions. Viscous oil or viscous emulsion flow—usually occurs in wells where viscosity at reservoir conditions exceeds 200 cP. Significant pressure drop reduces production from such wells and may require artificial lift. Wax deposition—can occur in subsea, deepwater and onshore fluids when flowing oil or condensate cools below temperature of normal (straight chain) paraffin wax freezing or crystallization. Wax appearance temperature depends on content of normal paraffins and typically ranges from 10 to 50 °C. Wax is a soft pliable material. Typical wax melting temperature ranges from room temperature (for a waxy gel) to over 80 °C (for a wax deposit aged 2+ years). Wax deposition from gas is less common than from oil but possible when reservoir fluid and hydrocarbon condensate liquid contain normal paraffins heavier than C18. Wax deposition requires both a heat loss and replenishment of waxy components to be present, thus a wax deposit can only form during flow. Without flow, wax can precipitate in the liquid but cannot be replenished. Without heat loss, wax cannot precipitate. Water quality noncompliance due to organic content—occurs in topsides or surface process equipment due to insufficient residence time or insufficient temperature to resolve oil-in-water emulsion or due to high concentration of water-soluble organic (negatively charged acid groups or aromatic) components which cannot be separated by mechanical means and require water clarifier (reverse demulsifier) chemical and water polisher (sorbent) filter. Offshore discharge of water with oil causes a sheen layer on seawater with colors. Water with water-soluble organics causes a gray sheen. Either can result in a noncompliance. Each of the possible flow assurance issue causes needs to be evaluated to determine if the production system entered the pressure-temperature-composition conditions for stability of each cause. If samples are available for laboratory analysis, the sample identification should be performed.

40

2.  Initial diagnosis and solution of flow assurance production problems in operations

Field or laboratory tests for initial solid samples identification Once a closed valve was ruled out as the possible cause of a suspected blockage, the separator inlet strainer should be inspected for any accumulated solids. Solids carried by produced fluids to the separator may help understand what processes happen upstream.

Field laboratory initial tests for solid samples identification Solids can be analyzed to help identify a flow assurance problem and develop the best solution. Although a specialized lab testing is preferred, a number of tests can be performed in the field to analyze the solid deposit using readily available chemicals such as water, table salt, diesel fuel, and simple instruments such as polarized sunglasses.

Field analysis Very preliminary analysis may be performed in the field using just water if getting the sample to the lab is prohibitively far or would take a long time. Hydrate: use an inverted graduated transparent cylinder to measure the volume of gas from a known volume of hydrate sample. Place a sample into the graduated cylinder filled with water. Place the upside-down graduated cylinder containing sample into an upright glass filled with water. If enough gas evolves from the sample to displace all water from the cylinder, it is hydrate. Wax: if the sample floats in water it is likely wax. Viscosity: use a calibrated cup viscometer with a hole of a known diameter in the bottom to measure time of sample outflow. Asphaltene: check sample density. If the sample sinks in water it is likely asphaltene.

Laboratory analysis Table 2.2 lists a number of simple tests which can be conducted in the field, ordered from simple to more complex. Any preliminary analysis information should be shared with the professional laboratory along with the sample as the initial measurements on solids which rapidly dissociate or melt can make a difference in the proper identification of the flow assurance issue. Inspired by The total systems approach process, Baker Hughes Inc., 2013. Note: As sample can release a poisonous vapor, all tests must be done in a vent hood! If a partial solid residue remains during any test it may be filtered, weighed and subjected to additional tests. 100 °C temperature was selected for ease of obtaining this temperature in the field conditions using boiling water (at sea level); at elevation the water will boil at a lower temperature, but the test results will remain valid. CPM (cross-polarized microscope) is useful for analysis of paraffin wax and other solids.



TABLE 2.2  Simple tests to help identify a solid

Ice

White

Stable

Hydrate

White

Diamondoid

Place in xylene or toluene 0.86 mg/L

Place in 11% HCl acid 1.05 mg/L

Place in 15 wt% NaCl 1.12 mg/L

See in CPM

Falls

Falls

Floats, dissolve

Floats, dissolve

Light

Melts with Floats, active gas bubbles release of gas bubbles

Falls, releases gas bubbles

Falls, releases gas bubbles

Floats, dissolve with gas bubbles

Floats, dissolve with gas bubbles

No light

White

Stable

Sublimate

Dissolve

Dissolve

Paraffin wax

White, brown, black

Stable

Floats, dissolve Falls, slowly dissolve

Falls, dissolve

Halite Scale

White

Stable

Falls, solid

Solid

Solid

Carbonate Scale

White, brown

Stable

Falls, solid

Falls

Falls

Dissolve with gas bubbles

Falls

Barium Sulfate scale

White, brown

Stable

Falls, solid

Falls

Falls

Falls

Falls

No light

Calcium Sulfate scale

White, brown

Stable

Falls, solid

Falls

Falls

Slowly dissolve

Falls

No light

Iron sulfide

Black

Heats or ignites

Falls, solid

Falls

Falls

Dissolve, releases H2S

Falls

No light

Naphthenate

Brown, white

Stable

Stable

Falls

Floats

Floats

No light

Corrosion products

Brown

Stable

Falls, solid

Falls

Falls

Falls, dissolve

Falls

No light

Asphaltene

Black, glossy

Stable

Falls, solid

Falls

Falls, dissolve

Falls

Falls

No light

350 °C coked asphaltene

Black

Stable

Falls, solid

Falls

Falls

Falls

Falls

Light

Sand

Brown

Stable

Falls, solid

Falls

Falls

Falls

Falls

No light

Floats, melt with little or no gas release

Floats Floats

Floats

Light

Slowly dissolve

Field or laboratory tests for initial solid samples identification

Color

Expose to air

Place in Heat to 100 °C/ kerosene place in or diesel boiling water 0.82 mg/L

41

42

2.  Initial diagnosis and solution of flow assurance production problems in operations

In absence of a proper laboratory CPM, a field-grade cross-polarized microscopy may be performed using two polarizer camera filters or two pairs of polarized eyeglasses. A thin sample of solid (such as wax) is placed between the two polarizers, and polarizers are turned relative to each other until no visible light passes through the assembly. Some crystals such as wax or ice can rotate the plane of light polarization, which can be observed in CPM as light passing through the crossed polarizers. A light shining through the sample in a CPM helps tell whether this flow assurance sample is one of the deposits which can rotate light polarization.

Typical blockage remediation plan 1. Gather system knowledge: fluids, samples, profile, insulation, internal and ambient conditions identify possible incompatibilities (wet gas + cold T, methanol + brine, LDHI + CI, etc.) in system identify probable locations (T  309 K. SG at 20° C  = 0.615 + Tb [ K ] / 3642 for C5 + or Tb > 309K Once the specific gravity information is derived from the True Boiling Point analysis, the critical properties for the Equation of State may be estimated by method of Riazi and Daubert (1980) Tc  ° R  = 24.2787 Tb  ° R 

0.58848

Pc [ psia ] = 3122810000Tb  ° R 

∗ SG  at 60° F 

−2.3125

0.3596

∗ SG at 60° F 

2.3201

Molecular weight may be estimated from SG using Pedersen (1989). MW = 14∗ carbon number − 4

56

3.  PVT and rheology investigation

Viscosity A number of correlations exist for dead oil viscosity as function of temperature and density. A summary overview of these correlations is provided in Bergman and Sutton (2007). Based on over 9000 viscosity measurements from over 3000 oil samples, they proposed a correlation:

(

)

Viscosity [ cP ] = exp exp ( 22.33 − 0.194 ∗ ρ + 0.00033 ∗ ρ 2 − ( 3.2 − 0.0185 ∗ ρ ) ∗ Ln ( TLM + 310 ) ) − 1 ρ = density, [API°], TLM = log-mean temperature [°F] for fluid between inlet and outlet. TLM = exp(average(Ln(TINLET),Ln(TOUTLET))). A simplified correlation is proposed here for stock tank oil viscosity at 60 °F for initial estimates, based on their correlation. Measured data should be used when available.

(

)

STO Viscosity [ cP ] = exp 194.3 / ρ  API°  / 27.47 Pseudocomponents and lumping In order to speed up the compositional analysis reservoir simulation specialists lump multiple components together. For example, components C12 through C15 may be lumped into a single pseudo-component C12–C15, etc. Properties of such pseudocomponents including critical temperature, critical pressure, acentric factor, molecular weight, boiling temperature etc. are calculated using the EOS tuning process. In early days of computer application for reservoir simulation as few as three or four components were used, as C1–C2, C3–C6 and C7+ in order to accelerate the vapor liquid equilibrium computation. Today using 15 pure components and 10 pseudocomponents is not uncommon. When two or more zones produce into the same well tubing, each zone gets characterized with a different set of pseudocomponents. This progressively increases the number of pseudocomponents and decreases the speed and accuracy of fluid property prediction. Typically five or more pseudocomponents, in addition to pure components (from C1 to C7) provide adequate ability to characterize a hydrocarbon fluid while maintaining reasonable computation speed. Usually software optimizes the lumping and pseudocomponent selection automatically, but this can be changed if necessary.

Lumping for different fluids It is preferred to have the same set of pseudocomponents for all fluids. Dedicated PVT tools which are used for fluid characterization for reservoir simulation have the capability to lump and tune different but similar fluids using the same set of pseudocomponents, which is preferred because it improves accuracy of blended fluid properties and improves computation speed. The accuracy of fluid behavior prediction improves substantially if the binary interaction parameters or kij are also supplied along with the properties of pseudocomponents and entered in the PVT simulation software. The binary interaction parameters are the additional adjustable coefficients in the equations of state which allow a more accurate prediction of fluid properties in multi-component mixtures. Flow assurance specialists usually receive fluid characterization information from the reservoir engineers who used the fluid properties to model the multiphase flow in the reservoir. The range of temperatures of interest to reservoir engineers is usually different from that of the flow assurance engineers. While XHPHT or extra high pressure high temperature



57

Fluid characterization

r­eservoirs may be as warm as 350–400 °F, the flow assurance systems may be exposed to temperatures as low as 0°C to −40°C in Arctic onshore or subsea environments. Typical deepwater temperature is near +4 °C or 40 °F, and the fluid characterization developed for the reservoir engineers may predict fluid properties accurately at high temperatures, but noticeably less accurately at lower temperatures. Fluid characterization should be done with both temperature ranges in mind so that the same parameters of the equation of state could apply to fluid property prediction by both reservoir and flow assurance disciplines. It is advisable to keep the same characterization of the fluid as the one used for reservoir analysis even if there are some inconsistencies in the VLE or other properties of the fluids at a different conditions, in order to maintain consistency of the project analysis. However, if the discrepancy is very significant and the flow assurance results would be significantly improved with more accurate fluid properties, the fluid may need to be re-characterized for flow assurance analysis using the laboratory data from the PVT report. The degree of discrepancy is to be determined by each individual project.

Solid-liquid equilibrium Flow assurance and production chemistry add a number of other liquid and solid phases to the diagram such as water, sand, hydrate, asphaltene, scale. The graph below illustrates a diagram where various phases coexist. Each phase has a label on the side of the boundary curve where the phase or a phenomenon appears, for example ice is on the colder side of the ice phase boundary. A flow assurance specialist or a production chemist could use the phase diagram in Fig. 3.9 like a map in order to get reservoir fluids efficiently from point A (well perforations) to point B (the separator). Fluid temperature is shown as increasing from reservoir past the wellhead and to the phase envelope to illustrate that in dense phase fluids Joule-Thompson effect causes Pressure Reservoir Early Life Wellhead Early Life

Reservoir Late Life

Separator Separator Late Life Early Life

Wellhead Late Life Temperature

FIG. 3.9  Phase diagram for various flow assurance issues. Fluid behavior and solid phases appearance are shown on a phase diagram versus time and location in the production system. Each phase is expected to appear on the labeled side of the curve.

58

3.  PVT and rheology investigation

heating. This effect can cause a hot reservoir fluid become even hotter during production and has to be taken into account for material selection and well design. In late life reservoir pressure declines but reservoir temperature remains the same so additional phases may become stable or unstable. Several solid phases can be present simultaneously if there are both sufficient fluid and appropriate conditions present to form those solids. Solids usually form from liquids by crystallization or by amorphous freezing. Examples of crystals are hydrate, ice, paraffin wax. Examples of amorphous solids are asphaltenes and some forms of wax and naphthenates. Scales are also crystals. In some cases petroleum solids can form from the gas phase such as diamondoids composed of adamantane, diamantane and heavier molecules. Diamondoids are also crystals and they photoluminesce (Clay et al., 2011) which may help identify them among other petroleum solids. Naphthenates are liquid crystals or micelles (Havre, 2002). Naphthenates have complex and little studied phase diagrams, and also can form amorphous solid films (Magnusson and Sjöblom, 2008). Two structures of hydrate commonly occurring in production operations are shown in the figure above to illustrate that when water is abundant for a hydrate to form, the propane and heavier components will be depleted first to form structure II hydrate, and if pressure is still sufficient to form more hydrate, the lean gas can keep forming structure I. This can happen when the number of moles of water is approximately six or more times greater than the combined number of moles of light hydrate forming hydrocarbons such as methane, ethane and propane. Similarly, if all gas is consumed into an exothermic hydrate and water is still present, ice can form if temperature is below freezing. Thermodynamically hydrate is more stable than ice at higher pressure because pressure helps water molecules in hydrate stay connected at higher temperatures, whereas in ice pressure distorts the crystal. However, kinetically ice forms faster than hydrate because it takes several types of molecules to get organized in order to form a hydrate crystal, while ice crystal forms with just water. Thus in an LNG process ice can form together with hydrate from an off-spec stream of hydrocarbon with a sufficient moisture content. Furthermore, in colder arctic environments hydrate can be dissociated by pressure reduction, while ice cannot if ambient temperature is below 0 °C. Depressurization is endothermic or consuming heat and should be done with care if ambient temperature is below freezing as hydrate upon dissociation releases mainly pure water. If fresh water released from dissociated hydrate converts into an ice blockage one would need to wait for the summer. Phase boundaries in the figure above are qualitative and intend to highlight the relative dependence of phase stability on changes in pressure or in temperature. For example, BaSO4 scale is less sensitive to changes in pressure than to changes in temperature. As pressure increases, less barite forms and as temperature increases, less barite forms. CaCO3 scale is sensitive to changes in both temperature and pressure. As temperature increases, more calcite would form. Also as pressure drops more calcite forms, mainly due to CO2 evolving from water and hydrocarbon phases. Carbon dioxide, if present in water and hydrocarbons, helps dissolve calcite in water, not too dissimilar from resins stabilizing asphaltene in oil. CaCO3 also can form a film on pipe surface which can reduce corrosion, unless the film gets sheared away by the flow. There is a continuous interaction between solid and fluid phases. Solids can act as diffusion barriers or as capillary channels to conduct less or more molecules in the liquid or gas



Fluid characterization

59

phases. This alters the rate of processes such as corrosion or formation of hydrate, deposition of wax or asphaltene. One should keep in mind that predicted stability of a solid phase does not guarantee solid formation at exactly the predicted condition because nucleation kinetics may be delayed, and formation of a solid does not always lead to a deposition and a blockage. At the same time, if a phase is not stable, it does not mean that it could not form in real operations. The software predictions and laboratory measurements can provide a warning for a specific set of conditions and fluid compositions. However, operations in the field can show that reality is more complex because not all factors and phase transitions were taken into account by a software or a lab such as reaction kinetics, solids nucleation and metastability, and the influence of one solid phase on another. As an example of such influence, in a system where scale is not stable, a hydrate formation can remove some water from a system. Hydrate consumes pure water and leaves salt in the remaining water. If a nearly saturated brine is present and the hydrate forms, it will cause water to become supersaturated with salt, leading to scale precipitation and deposition. Similarly, injection of methanol to inhibit hydrate into a produced fluid, which included a brine nearly saturated with NaCl, had led to a change is salt solubility and an unexpected halite scale blockage in a North Sea pipeline.

Additional laboratory studies Additional laboratory studies which may accompany a PVT report may include: Oil pour point temperature Oil HTGC or high-temperature gas chromatogram to resolve amounts of wax-forming components Oil emulsion stability study Oil TAN total acid number and TBN total base number analysis Oil SARA or saturates, aromatics, resins, asphaltenes content analysis Oil foaming study Wax appearance temperature measurement in CPM or cross-polarized microscope or DSC differential scanning calorimeter at stock tank conditions Wax appearance temperature measurement at pressurized conditions with reservoir fluid with either DSC or CPM Wax deposition study in a bench-scale mini-loop or a filter-plug apparatus Wax deposition study in a pilot-scale loop Wax deposition study in a cold finger apparatus with effect of chemical inhibitors Wax deposition study in a pressure cell Wax content from a cold solvent filtration study Wax dissolution study with dispersant chemicals or solvents Wax melting study for hot-oiling process Waxy gel strength test in a small diameter tube Asphaltene titration study for stock tank oil Asphaltene isothermal depressurization for live reservoir fluid under pressure

60

3.  PVT and rheology investigation

Asphaltene deposition study in a pressure cell Asphaltene deposition study in a mini-loop or a filter-plug apparatus Corrosion rate metal loss study with a static cell Corrosion rate study with a rotating linear polarization electrode at atmospheric pressure to measure the effect of shear on chemical performance Corrosion rate with a rotating electrode under high temperature and high pressure Corrosion rate from analog field metal coupon weight loss Scale precipitation study in a static cell Scale deposition in a mini-loop at high temperature to mimic reservoir condition Scale deposition in a mini-loop at low temperature to mimic wellhead & flowline condition Hydrate stability study with reservoir fluid and formation water Hydrate stability study with reservoir fluid and wellwork fluid Hydrate deposition study in a pressure autoclave, a rocking cell, a flow wheel or a flow loop, with or without chemical thermodynamic or kinetic inhibitors Hydrate dispersion study in a rocking cell with antiagglomerant chemicals Among the above tests, there are some indirect correlations: Hydrate nonplugging oil tendency may be related to TAN acids content and surfactants content as investigated by J. Sjoblom, where surfactants content may be analyzed based on emulsion stability study Naphthenate tendency may be related to TAN acids content Asphaltene tendency may be determined from SARA analysis Production chemicals viscosity as function of pressure and temperature Production chemicals vapor pressure analysis There are numerous alternatives available to measure wax appearance and wax disappearance temperatures, which should be used depending on fluid type (e.g. regular or biodegraded): - - - - - - -

CPM—visual detection of microscopic crystals assisted by polarized visual or IR light DSC—exothermic detection of solids, applicable to regular or biodegraded oils Viscometer or rheometer—detect a change in slope of Ln(viscosity) vs temperature Cold finger—visual detection of solids Cold filter plug—pressure differential detection of solids Cloud point—visual detection of crystals by eye—less accurate but field-usable Ultrasound change in wave frequency with temperature—applicable to live oil (Jiang et al., 2014) - Light scattering—applicable to wax appearance and wax disappearance Compressibility.

PVT tuning Binary interaction parameters kij serve as the tuning factors for the equations of state when properties of multicomponent mixtures are calculated. These BIPs are regressed for multiple



61

Fluid physical properties

(pseudo)component—(pseudo)component pairs to achieve the best fit between measured data and predicted values. Each group of regression, such as on liquid density, can have its own regression tolerance. Typical tolerance targets for regression during PVT tuning shown in Table 3.3 are as follows: TABLE 3.3  Tuning target tolerances Density

+/− 1–5%

Pressure of liquid saturation with gas

+/− 2–10%

Gas-oil ratio or RS (solution ratio)

+/− 1–5%

Liquid viscosity

+/− 5–20%

Parameters and acceptable tolerances of the fluid characterization are also illustrated in section 4.7 of the Phase Behavior monograph by Whitson and Brule. Fluid tuning process is available in multiple commercially available software packages. One would normally start with the most relaxed tolerances and repeat tuning the fluid several times while reducing the tolerance and noting the overall errors in property prediction at different temperatures and pressures. Default value for kij is zero because kij enters the equation of state in a form (1−kij), so a default value gives a complete contribution of a given pair of components to the interaction energy parameter in the equation of state. Normally the values of interaction energy (a) and molecule size (b) are calculated from the properties of components such as critical pressure and critical temperature which can be measured in the laboratory and acentric factor which can be calculated from the molecular structure. BIPs (kij) provide the ability to adjust the contribution of each component's interaction energy (a). Besides kij, there are also characteristic constant (kappa), volume shift parameters for density match improvement and other methods. As a final resort, when tuning of the GOR or density cannot be achieved with the provided composition, some of the component contents may be varied by 1–5%. This variation must be documented in the fluid characterization report. Example component properties are shown in Table 3.4.

Fluid physical properties TABLE 3.4  Component properties Formula

Name

Molecular weight

Density (g/L)

V (L/mol)

Melting point

g/mol

at 1 atm, 15.5 °C

Air

29

1.225

23.67

−215

N2

Nitrogen

28

1.183

23.68

−210

CO2

Carbon dioxide

44

1.869

23.55

−56.6

H2S

Hydrogen sulfide

34.1

1.451

23.49

−82

°C

(Continued)

62

3.  PVT and rheology investigation

TABLE 3.4  Component properties—cont’d Formula

Name

Molecular weight

Density (g/L)

V (L/mol)

Melting point

C1

Methane

16

0.679

23.63

−182.5

C2

Ethane

30.1

1.281

23.47

−182.8

C3

Propane

44.1

1.896

23.26

−188

iC4

i-Butane

58.1

2.524

23.03

−159.6

nC4

n-Butane

58.1

2.531

22.96

−140

iC5

i-Pentane

72.2

623.9

0.116

−160

nC5

n-Pentane

72.2

629.7

0.115

−130

iC6

i-Hexane

86.2

657.1

0.131

−153

nC6

n-Hexane

86.2

662.2

0.130

−95

C6

Methylcyclopentane

84.2

753.3

0.112

−142

C6

Benzene

78.1

885.3

0.088

5.5

C6

Cyclohexane

84.2

782.2

0.108

6.5

C7

Heptane

100

687.0

0.146

−90.5

C7

Methylcyclohexane

98.2

774.1

0.127

−126

C7

Toluene

92.1

870.1

0.106

−95

iC8

Iso-octane

114

702.6

0.163

−107

C8

Octane

114

706.0

0.162

−57

C8

Ethyl benzene

106

873.0

0.122

−95

C8

m-Xylene

106

866.9

0.122

−48

C8

p-Xylene

106

866.9

0.122

13

C8

o-Xylene

106

882.9

0.120

−25

C9

Nonane

128

720.7

0.178

−51

C10

Decane

142

732.6

0.194

−30

C11

Undecane

156

742.5

0.211

−26

C12

Dodecane

170

750.4

0.227

−10

C13

Tridecane

184

758.3

0.243

−5.5

C14

Tetradecane

198

765.2

0.259

5.9

C15

Pentadecane

212

771.2

0.275

10

C16

Hexadecane

226

775.1

0.292

18.2

C17

Heptadecane

240

779.5

0.309

22

C18

Octadecane

255

783.4

0.325

28.2

C19

Nonadecane

269

787.3

0.341

32.1

C20

Eicosane

283

785.6

0.360

36.8



63

Non-Newtonian behavior

TABLE 3.4  Component properties—cont’d Formula

Name

Molecular weight

Density (g/L)

V (L/mol)

Melting point

C21

Heneicosane

297

793.5

0.374

40.5

C22

Docosane

311

795.6

0.390

44.4

C23

Tricosane

325

798.7

0.406

47.6

C24

Tetracosane

339

800.8

0.423

50.9

C25

Pentacosane

353

802.3

0.440

53.7

C26

Hexacosane

367

805.9

0.455

56.4

C27

Heptacosane

381

807.1

0.472

59

C28

Octacosane

395

806.9

0.489

61.4

C29

Nonacosane

409

808.5

0.506

64

C30

Triacontane

423

811.5

0.521

66

C40

Tetracontane

563

817.0

0.689

82

C50

Pentacontane

703

824.0

0.854

91

CH3OH

Methanol

32

795

−98

C2H6O2

MEG

62.1

1117

−12.9

Hydrate structure1

17.7

916 at 129 atm

−81 at 1 atm

Hydrate structure2

19.1

958 at 22 atm

−44 at 1 atm

Light n-paraffin wax

400

910

66

Microcrystalline wax

800

940

78

Asphaltene

700

1100

not applicable, pyrolizes on heating

Non-Newtonian behavior Viscosity of oil is measured at a range of temperatures and pressures. Viscosity of gas is usually calculated using a correlation. Waxy crudes may also exhibit a pour point which can be measured and reported. The pour point is a measure of temperature at which a fluid in an inclined flask does not flow for a prescribed period of time. Non-Newtonian fluid rheology behavior is observed in viscosity measurement if solids such as wax precipitate in the liquid. If viscosity is plotted against temperature for a Newtonian fluid, usually a plot of natural logarithm of viscosity vs temperature is linear. When solids are introduced, the viscosity increases. This is exhibited as a nonlinear plot of logarithm of viscosity versus temperature. This nonlinearity may be used as one of the methods to determine wax appearance temperature of the fluid if more accurate data are not available.

64

3.  PVT and rheology investigation

There are various correlations for the effect of slurry solids volume fraction on viscosity. Nuland and Vilagines (2001, BHRG) proposed to use such correlation for hydrate slurries, which is based on the correlation by Mills (1985) for apparent shear viscosity, which in turn was based on the works of Einstein and Batchelor.

µr =

1 −Φ  Φ  1−  Φ max  

where µ r = µslurry / µ fluid , Φ = solid volume fraction , Φmax = maximum packing solids colume fraction = 4 / 7 for spheres. Other non-Newtonian behavior is also associated with wax crystals forming a gel. When slurry becomes so concentrated that crystals overlap and form a network, a waxy “gel” forms. The term gel is used in this context to signify that the whole fluid becomes nonflowing and non-Newtonian in its rheology. A gel exhibits a yield stress, which means that some force needs to be applied to disrupt the network before a gelled fluid starts to flow. In some cases waxy crudes with 3% or greater wax content (measured by cold filtration) may exhibit gelling behavior. Gel strength may vary depending on the cooling rate of the fluid. So, faster cooling (near a pipe wall) results in smaller wax crystals and a weaker network. Conversely, core of the gelling waxy oil cools at a relatively slower rate and grows larger crystals which form a stronger network. This effect becomes most pronounced in larger pipelines. It is not uncommon to see in a medium-diameter 2-in. pipe gel test that gel breaks near the pipe wall circumference, and the gelled oil core is extruded from the test pipe. To overcome the discrepancy between gel strength measured in a small laboratory tube and observed in a large diameter pipeline, gel strength may also be measured in a temperature-controlled rheometer with a cone-and-plate geometry to accurately reproduce the cooling rate history of a large diameter pipeline to obtain a more accurate gel strength reading. Alternatively, larger size test tubes or field pilot test sections may be used.

Emulsion characteristics Emulsion stability is commonly measured and reported for new oil samples. The time it takes to resolve an emulsion by gravity into oil and water layers is reported. Emulsion stability is particularly important for offshore operations as residence time in a separator is limited by size and weight of the separator to 5–10 min. Water-in-oil emulsions are prepared by mixing for a prescribed time at several shear rates and different water cuts and are allowed to resolve at different temperatures. Foaming of the oil may also be reported if observed. Formation of slop or solids-stabilized layer between oil and water layers may be reported if observed. Inversion point for an emulsion may be reported if observed at some water cut.

References 65

Oil-in-water emulsions are prepared at different water cuts between 50% and 90% at different shear rates for a prescribed time, and oil content of water is reported in ppm. The reported oil content should include both oil and water-soluble organic components. Rheology or viscosity of emulsions formed at different shear rates is reported for different temperatures and water cuts.

Biodegradation Crude biodegradation may be exhibited by the absence of n-paraffin peaks in gas chromatogram or in high-temperature gas chromatogram. Bacteria present in the reservoir consume normal paraffins and only branched or isomerized paraffins remain. This makes wax deposition prediction more complex as most modern wax deposition models are based on a solubility prediction method developed by Erickson (Erickson et al., 1993) which is applicable to n-paraffins. It also makes some laboratory studies such as CPM more complex as isomerized paraffins may form less crystalline and more amorphous solids which would not rotate the plane of light polarization. DSC or other methods to detect wax onset may then be used. Laboratory studies for the wax deposition then become necessary if wax appearance temperature is in the range of operating temperatures.

References Bergman, D.F., Sutton, R.P., 2007. A consistent and accurate dead-oil-viscosity method, SPE110194. In: SPE Annual Technical Conference and Exhibition, Anaheim, 11-14 November. Clay, W.A., Sasagawa, T., Iwasa, A., Liu, Z., Dahl, J.E., Carlson, R.M.K., Kelly, M., Melosh, N., Shen, Z.-X., 2011. Photoluminescence of diamondoid crystals. J. Appl. Phys. 110 (9), https://doi.org/10.1063/1.3657522. Erickson, D.D., Niesen, V.G., Brown, T.S., 1993. Thermodynamic measurement and prediction of paraffin precipitation in crude oil. In: SPE 26604, Annual Technical Conference and Exhibition, Houston, 3–6 October. Fiotodimitraki, T., 2016. Quality controlled oil reservoirs PVT data. Masters thesis, University of Crete. Accessed 12/12/2018, dias.library.tuc.gr/view/manf/63591. Havre, T.E., 2002. Formation of Calcium Naphthenate in Water/Oil Systems, Naphthenic Acid. Chemistry and Emulsion Stability. Thesis Submitted in Partial Fulfilment of the Requirements for the Degree of DOKTOR INGENIØR Department of Chemical Engineering. Norwegian University of Science and Technology, Trondheim. Hu, Y., et al., 2017a. Gas hydrates phase equilibria for structure I and II hydrates with chloride salts at high salt concentrations and up to 200 MPa. In: Physical Chemistry Chemical Physics. Royal Society of Chemistry. Hu, Y., et al., 2017b. Gas hydrates phase equilibrium with CaBr2 and CaBr2 +MEG at ultra-high pressures. In: Physical Chemistry Chemical Physics. Royal Society of Chemistry. Jiang, B., et al., 2014. Measurement of the wax appearance temperature of waxy oil under the reservoir condition with ultrasonic method. Petroleum exploration and Development 41 (4). Joback, K.G., Reid, R.C., 1987. Estimation of pure-component properties from group-contributions. Chem. Eng. Commun. 57, 233–243. Katz, D.L., Firoozabadi, A., 1978. Predicting phase behavior of condensate/crude oil systems using methane interaction coefficients. J. Petrol. Tech. 20, 1649–1655. SPE-6721. Magnusson, H., Sjöblom, J., 2008. Characterization of C80 naphthenic acid and its calcium. J. Dispers. Sci. Technol. 29 (3), 464–473. Mills, P., 1985. Non-Newtonian behavior of flocculated suspensions. J. Physique Lett. 46, L-301–L-309. Nuland, S., Vilagines, R., 2001. Gas hydrate slurry flow – A flow modeler looks at the state of slurry rheology modelling. In: BHRG Multiphase International Conference proceedings, Cannes, France.

66

3.  PVT and rheology investigation

Pedersen, K.S., et al., 1989. Characterization of gas condensate mixtures. In: Chorn, L.G., Mansoori, G.A. (Eds.), C7+ Fraction Characterization. Taylor & Francis, New York, pp. 137–152. Peneloux, A.E., Rauzy, E., Freze, R., 1982. Fluid Phase Equilib. 8, 7–23. Riazi, M.R., Daubert, T.E., 1980. Prediction of the composition of petroleum fractions. Ind. Eng. Chem. Process. Des. Dev. 19, 289–294. Whitson, C.H., Brule, M.R., 2000. Phase Behaviour, Richardson (TX). Society of Petroleum Engineers.

Further reading Landt, L., Kielich, W., Wolter, D., Staiger, M., Ehresmann, A., Möller, T., Bostedt, C., 2009. Intrinsic photoluminescence of adamantane in the ultraviolet spectral region. Phys. Rev. B 80, 205323. Pedersen, K.S., et al., 1991. Wax precipitation from North Sea crude oils. 4: Thermodynamic modelling. Energy Fuel 5, 924–932. Riazi, M.R., 1979. Prediction of Thermophysical Properties of Petroleum Fractions. PhD Thesis The Pennsylvania State University, PA.

C H A P T E R

4 Hydraulic and thermal analysis O U T L I N E Introduction

68

Hydraulic restrictions boundaries and management Scope Hydraulic analysis deliverables Overall design Other considerations Typical pressure drop Hydraulics technologies

68 69 69 70 71 71 73

Hydrodynamics of multiphase flow Multiphase flow pressure drop—Vertical vs Horizontal Designing out severe slugging Multiphase flow liquid holdup—Vertical vs Horizontal

74

Thermal effects Heat transfer Joule-Thomson effect

81 81 84

Flow modeling Correlations Dimensionless numbers Software

84 84 85 86

Handbook of Multiphase Flow Assurance https://doi.org/10.1016/B978-0-12-813062-9.00004-X

74 79 80

Erosion modeling Multiphase production problems

87 87

Operation online monitoring for pipeline 88 Correlations 89 Software 89 Operation online monitoring for well liquids loading and forming blockages/restrictions Correlations Software Design of oil/gas development project Hydraulic management Water injection management Flow restriction and blockage monitoring

88 89 89 89 89 90 91

Machine learning and artificial intelligence in flow network optimization

91

References

92

Further reading

93

67

© 2019 Elsevier Inc. All rights reserved.

68

4.  Hydraulic and thermal analysis

Introduction Hydraulic analysis is used to calculate and optimize pressure loss, holdup accumulation, vibration, water hammer and surge exceeding normal operating parameters during steady and transient flow operations. Sensitivity to the amounts of produced water should include an assumption for planned and deferred water injection for pressure support, based on reservoir simulation production profiles. Thermal analysis predicts the temperature changes in the produced fluid and in the producton system as heat is lost to ambient cooling or to JT expansion in multiphase flow or gained from JT heating in supercritical (dense phase) fluids. Thermal analysis in wells is also related to mechanical integrity if annular spaces are filled with fluids with low compressibility. Both thermal and hydraulic analysis are performed simultaneously, coupled through location in the system. Fluid properties depend both on temperature and pressure, and proper fluid characteristics and phase transitions rely on accurate calculation of both temperature and pressure. Hydraulic analysis results are supplied to operability design analysis which aims to ensure that temperature, pressure and flow are within normal operating limits for the production system at any stage in field development life. Flow lines from trees to manifolds and from manifolds to hubs are usually routed predominantly uphill to minimize pressure losses due to terrain liquids holdup in low spots, in order to maximize overall fluid recovery by limiting backpressure on wells, and also to avoid slugging induced by liquid accumulation in low spots and to enable uniform subsea chemical distribution in produced fluid, and to reduce fatigue from cyclic slug impacts on pipe elbows at bends and crossings. Detailed field layout should ensure that both production and chemical injection systems can operate with acceptable pressure drop and chemical stability in subsurface, subsea, topsides and export systems conditions. Single line tieback concepts are economically attractive and may be considered for early production systems if reliable ways to mitigate the risk of solids restriction are in place.

Hydraulic restrictions boundaries and management Besides the regular solid blockages which derive from a phase transition such as solid crystallization of normal paraffins as wax there also may be hydraulic restrictions in the pipelines. Such hydraulic restrictions may occur both with and without phase changes, merely due to accumulation of a gas or a liquid in a pipe due to variations in geometry or due to evaporation or condensation. Such examples may include water or liquid holdup in a low spot creating resistance to flow, a viscous emulsion accumulation in a process vessel reducing its effective volume or a vapor lock at the intake of a centrifugal pump breaking fluid continuity. Each may restrict or interrupt flow. Additional cases of restrictions pertain to fluids flowing outside their normal operating conditions. Such examples include production chemicals slack flow which may cause a blockage in a chemical delivery umbilical tube. Slack flow is a generalization term which means the fluid flows at a pressure below its vapor pressure or bubble point. This may occur in late life production in deep water ­operations when produced fluid has a lower density than the production chemical injected at the subsea tree, and the flowing wellhead pressure is lower than the hydrostatic pressure



Hydraulic restrictions boundaries and management

69

of the p ­ roduction chemical. Normally the chemical backpressure is controlled by a chemical injection valve, but a valve set for operation in early life at initially higher wellhead pressure may need to be recalibrated for late life lower pressure, and if that maintenance is deferred the chemical may experience vacuum conditions at the top of the umbilical riser, causing carrier solvent in the chemical to vaporize and leaving the viscous or solid active ingredient residue in the chemical tube gradually blocking it. These static hydraulic restrictions such as a holdup may be easier to plan for than dynamic flow resistances such as hydrodynamic slug flow because static restrictions are caused by localized conditions such as pressure, temperature or geometry and thus can be designed out of the planned system. Dynamic restrictions emerge during the course of production, and planning of the optimum balance of the production system capacity versus its cost is the main focus of hydraulic analysis in flow assurance which relies on the anticipated production flow rates derived from reservoir modeling that carries inherent uncertainty. The same may be said about hydraulic design of production chemical injection systems.

Scope Hydraulic assessment and management has the principal priority in flow assurance work scope. The flow assurance analysis relies on fluid properties from reservoir model or laboratory data and on a production profile from a recent reservoir model, and latest surface geometry or subsea bathymetry. Liquid holdup accumulations forming a hydraulic restriction to flow and erosional velocity limits for liquid and gas production need to be evaluated. For a tieback to an existing facility, matching of hydraulic and insulation performance should be included to calibrate the effective roughness and thermal insulation U-value based on existing operations data from operations and third party engineering vendor experience. Note that the theoretical roughness and insulation values of a system provided by vendors may be more optimistic than field performance under subsea or onshore operation. Actual insulation performance may be affected by flooded sections in pipe-in-pipe insulation or water ingress into the wet polymeric insulation. Actual roughness is affected by corrosion and erosion. Both insulation performance and roughness become worse with time.

Hydraulic analysis deliverables The engineering analysis needs to identify when the system selected in early design operates with a hydraulic restriction or excessive velocity threats, quantify the duration of system operating with flow instability, and provide a design for the selected one or more technically mature technologies to mitigate the identified threats and to remediate the hydraulic restriction, flow instabilities or surge. Deliverables of hydraulic analysis include the recommended in-field flowline network and export pipeline sizes with updated corrosion and erosion allowances to permit maximum uninterrupted production during the life of field, maximum flow velocities for produced fluids, mitigation method and intervention frequency for liquid inventory management in flowlines based on transient modeling of scraping and estimated based on historic analogs, liquid surge capacity for onshore or topsides facilities sizing, chemical injection requirements (location, dosage, storage, compatibility with materials and with other chemicals) if a chemical is used to manage liquid inventory (such as a foamer).

70

4.  Hydraulic and thermal analysis

Analysis provides gas and liquid flow velocity upper boundaries for erosion, flow induced vibration, and thermal material limits for JT expansion cooling (e.g. gas in Deepwater riser). No credit should be taken for ability to monitor erosion in a dry tree vs subsea tree system and the erosional analysis should provide the same gas and liquid flow velocity upper boundaries. Guideline chosen for the project needs to be used for erosion engineering analysis. There are several erosion guidelines available such as DNV-0501, API-14E or NORSOK P-001. Additional models such as SPPS are also used for analysis. A summary overview of the models is presented by Arabnejad et al. (2015). Hydraulic multiphase flow analysis needs to be aligned with surface or topsides process design procedures to make sure the flow rates at the outlet of the production system are compatible with the flow rates at the intake of the process system. A slug catcher may act as a surge suppressor if the production system output may have sudden high flow rates such as during scraping or severe slugging. An overview of occurrence and solutions for severe slugging is presented by Montgomery (2002). A turndown analysis indicates what lowest flow rate is sustainable in the production system. Deliverables of a turndown sensitivity study relative to the design production profile indicate when produced fluid flow remains above slug flow onset, and when start-up or ramp-up surge volume exceeds the facilities process capacity. Analysis also provides updated steady state temperature and pressure profiles through time, including turndown sensitivity relative to the design production profile.

Overall design Overall design for hydraulic management needs to rely on using proven technology to avoid holdup accumulation irreversible by normal operating procedure. Sensitivity to produced water cut should include an assumption for planned and deferred water injection for pressure support, based on reservoir simulation production profiles. Operations with flow instability may include producer or injector well transient operation such as cold or warm start-up, planned or unplanned shut-in, and steady operation. During FEED phase, at least steady operation and start-up surge analyses need to be performed. Depressurization analysis should be performed if hydrate management relies on it. Mitigation of severe slugging and liquid surges may include topsides choking, riser base gas lift, sufficiently sized slug catcher, subsea pumping, pressure management, etc. Use of novel methods such as actively controlled topsides choke valve for riser severe slugging is growing in acceptance in Deepwater and may be considered as technically mature. Remediation methods used to control hydraulic losses may include scraping to sweep accumulated liquids, drag reducing agent chemical injection, or foamer to control liquid inventory. Mechanical removal of liquids with swabbing has not been widely used in Deepwater, but has been used successfully in onshore wells, and may be applicable to dry tree risers in late life. Mechanical methods to reduce flow line cross section such as velocity strings or a­ rtificial lift such as ESP or multiphase pumps to propel liquids may be used both in onshore and offshore production. Combinations of the methods may also be used such as an ESP on a coiled tubing velocity string in onshore wells or in offshore risers.



71

Hydraulic restrictions boundaries and management

EXA M PLES OF UNSTAB LE F LOW M I TI G ATI O N An example of a Deepwater system properly designed for hydraulic management may be a flow line selected with predominantly uphill geometry to mitigate terrain slugs to ensure flow stability for a longer portion of the field life and with a separator sufficiently sized to receive liquid surges in late life. Another example as in Table 4.1 is a single line tieback with an artificial lift to mitigate severe slugging.

Other considerations Transient commercially available or custom-developed models should to be used for hydraulic analysis, upon performance verification against publicly available or commercial flow data sets and after approval of the relevant project authority. In general it takes between 3 and 10 years to develop a multiphase flow analysis tool, so the task is manageable for a capable individual in an academic setting or for a large corporation research team. Transient multiphase flow analysis is complex, and tools which have not been verified by the user should not be considered for application in production system design. Verification itself is a complex and time consuming undertaking, and it may need to be outsourced to qualified engineering vendor which has experience in multiphase flow analysis but no vested interest in a particular tool. Impact on production should be determined and accounted for if the choking option was selected in early design for slug mitigation.

Typical pressure drop One commonly used frictional pressure drop correlation applicable to single-phase flow is Darcy-Weisbach: ∆P [ Pa ] = Lf Moody ρV 2 / ( 2D ) L = pipe length [m], f = friction factor, ρ = fluid density [kg/m3], v = fluid velocity [m/s], D = inside diameter [m].

TABLE 4.1  Examples of hydraulic instabilities and their mitigation and remediation Hydraulic examples (from reservoir to process)

Mitigation examples

Remediation examples

Flow instability in wet gas wellbore (i.e., FBHP < Lift curve minimum P)

Reduce wellhead choke opening

Reduce tubing size or use Artificial lift (boost)

Flow instability in wet gas flowline (i.e., FWHP < P_dew)

Periodically sweep liquids to slugcatcher

Use partial separation

Flow instability in riser (severe slugging) Reduce boarding choke opening

Artificial lift (gas lift or boost)

72

4.  Hydraulic and thermal analysis

If the Reynolds number is below 2100, the laminar Moody friction factor as a function of Reynolds number is f Moody = 64 / Re f Fanning = f Moody / 4 Many different friction factor correlations are available for turbulent flow but the simplest of these is the Blasius (1913) correlation. f Moody = 0.3164 Re −0.25 For turbulent flow it is convenient to determine friction factor f from a non-recursive formula (Swamee and Jain, 1976)

(

f Fanning = f Moody / 4 = 4 × log ( ε / ( 3.7 D ) + 5.74 / Re0.9 )

)

−2

.

ε = pipe wall roughness [m]; typical aged carbon steel roughness is 45 μm or 45 × 10−6 m. Re is Reynolds number. For hydraulically smooth pipes fFanning = 0.0791/Re0.25. For flow analysis it is helpful to estimate shear of fluid acting either on a solid or on pipe wall. We summarize several shear correlations. Shear_rate γ [1/ s ] = shear_stressτ [ Pa ] / dynamic_viscosity µ [ Pa s ] ( for Newtonian fluids ) . Shear rate for laminar flow γLaminar = 8 vAve/D. Average flow velocity vAve = Q/A. Shear stress exerted by flowing fluid on pipe wall τwall = D ΔP/(4L)

τ Laminar_ at_ wall = 8 µ VAve / D τ Turbulent _at _wall = ρ V 2 fFanning / 2 τ wall = D∆P / ( 4L ) For single-phase flow we can illustrate that laminar pressure drop is inversely proportional to pipe diameter to the power 4, whereas turbulent flow is inversely proportional to diameter to the power 5. ∆PLaminar = 32 µ Lv Ave / ( D 2 ) = 128 µ LQ / (π D 4 )

∆PTurbulent = 4Lρ v Ave 2 fFanning / ( 2D ) = 32 ρ LQ 2 f / (π 2 D 5 ) Other equations such as Weymouth or Panhandle may also be used to calculate pressure drop in gas flow. Panhandle B formula (1956) is for gas flow with medium Reynolds number values. Q [ MMscf / d ] = 0.028ED 2.53

(( P

1

2

− P2 2 ) / ( S 0.961 ZTL )

)

0.51



Hydraulic restrictions boundaries and management

73

E = efficiency, typically E = 0.92; D = diameter [inch], L = length [miles], Z = gas compressibility at average conditions, T = inlet gas temperature [°R], S = gas gravity relative to air, P1 = upstream pressure, P2 = downstream pressure [psia]. Average conditions for gas compressibility are estimated as log-mean temperature and line-average pressure. TAVERAGE = TAMBIENT + ( TIN − TOUT ) / ln ( ( TIN − TAMBIENT ) / ( TOUT − TAMBIENT ) ) PAVERAGE = 0.667 ( PIN 3 − POUT 3 ) / ( PIN 2 − POUT 2 )

Compressibility may be estimated with McCain or Hanafy correlations. Alternatively it may be looked up in property tables. Typical pressure drop for a gas flow line from a well to a processing facility is around 0.5 bar per km or 12 psi per mile. For multiphase lines the pressure drop may be as high as 10 bar per km, but typically is less. If the pressure drop is higher than this, then the backpressure on the wells is high and reservoir may produce less. If the pressure drop is lower, then the pipe may be oversized and capital cost may reduce profitability. Export pipelines will have different pressure drops. A similar performance comparison is possible for a multiphase flow line from a well to a processing facility. The main objective of a multiphase flow calculation similarly is to find pressure drop in a line of a given size. Secondary objective is to forecast conditions to minimize the occurrence of a slugging flow regime. Evaluation of a multiphase flow pressure drop is more complex than for a single phase flow and involves series of formulaic or graphic-­ analytical computations, with or without account for the gas-liquid dispersion flow regime. Virtually all multiphase flow pressure drop calculations are done by computer software, with the account for the flow regime.

Hydraulics technologies A number of technologies may help economically produce fluids from a distant asset. Technologies which should be considered in formulating an asset development project concept may include the following: • • • • • • • • • • • • •

Hydraulic lines of different size and insulation type and thickness Slug catcher vessel HIPPS system Periodic scraping Production chemical Subsea booster pump Subsea multiphase pump Subsea gas separator if proven for use in the region Subsea water separator if proven in the region Riser base caisson gas separator if proven in the region Downhole and/or riser base gas lift Drag reducing agent chemical Active heating of flowlines with electrical energy or with heating medium fluid

74

4.  Hydraulic and thermal analysis

• Multiphase flow meter • Water injection pump with limits per rock fracture gradient

Hydrodynamics of multiphase flow Multiphase flow pressure drop—Vertical vs horizontal Modern hydraulic analysis methods rely on software packages using mass and momentum conservation equations with equations closure relationships. The closure relationships constitute the commercial know-how of the vendors. Closure relationships are correlations based on experiments or field data, which complete the system of equations for conservation of mass and momentum required to calculate fluid motion. The relationships are being continuously updated based on field measurements and research data. Software is also regularly updated to improve the accuracy of predictions. A good summary of the basis relationships in multiphase flow is given by Hetsroni (1982). The book presents the equations for single phase flow, two-phase flow, flow with particles, interaction of interface with particles, liquid film condensation, drag reduction and measurement techniques. A good discussion of closure relationships is presented by Roullier et al. (2017). A more detailed description of the overall multiphase flow simulator design is provided by Jansen (2009). The summary for multiphase flow pressure drop correlations for vertical flow is provided in the monograph by Brill and Mukherjee (1999). Many of these correlations are still in use today. Variety of flow regimes have been identified by researchers over the past century. Few key ones are illustrated below in Fig. 4.1 for horizontal and vertical flow. Inclined flow researchers occasionally use terms froth or pseudo-slug which have more gas entrained in liquid slug and are similar to churn. Each flow regime represents a progressively increasing level of energy dissipation, as reflected by higher amounts of liquid droplets entrained into the gas phase. With higher pressure, droplet entrainment increases. Inclined flow tends to have a stratified flow pattern going downhill and slug flow uphill.

FIG. 4.1  Illustration of multiphase flow regimes.



Hydrodynamics of multiphase flow

75

The following images in Fig.  4.2 show the four slugs completely crossing the pipe cross-section, moving from right to left, in a 6-in. multiphase flow loop donated to the University of Tulsa with air and water. The images are frames from a video recorded for seven seconds. The incomplete slugs and waves are not shown. The areas of churn at slug fronts with high bubble entrainment and maximum energy dissipation are darker on these images, whereas liquid without entrained bubbles is light and translucent. The longer slug in the second image has two areas with bubble entrainment, which suggests this may be a slug merged from two smaller slugs. A video of slug flow in these frames is available on makogon.com/resources/6inchILOOP050101slugs.AVI and 6inchILOOP050101slugging.gif. Images from this video may be used to train slug pattern recognition in machine learning. Slug velocity may be determined from the video recorded in May of 2001. Slug length and frequency are common parameters predicted by the multiphase flow correlations. Slug length may be of a slightly greater interest from the system integrity standpoint because knowing it helps one calculate the momentum of the moving slug and the force with which the slug can impact on a pipe bend, a tee or an elbow in the flow path. A simplified calculation for an average slug length is proposed as L Slug [ ft ] = (D [ in ] ) 2

where pipe inside diameter is in inches and average slug length is in feet, so a 10 in. inside diameter pipe would produce 100 ft. or 30 m long slugs, on average. This may be used only as a very rough approximation of the true slug length, just to find the order of magnitude for the possible slugs in multiphase flow. The advantage is that this calculation is easy to remember and thus use in the field or as needed. This proposed correlation is useful up to pipe diameters of 14 in. which covers a large portion of installed multiphase pipes. A comparison of software predictions with field data for slugging observed in a 12-in. flowline is shown in Fig. 4.3 below (updated, from Fairhurst, 2002). The proposed slug length correlation has a reasonable agreement with the slug lengths observed in the field. Some examples of models for slug frequency are presented in Hill and Wood (1990) and Shea et al. (2004). The Hill-Wood model the slug frequency as function of mixture velocity and liquid height U mixture 2.68 h film /D 10 D The Shea model of the hydrodynamic slug frequency as a function of liquid superficial velocity and dimensionless slug length L expressed in pipe diameters was used in a commercial transient software simulator. f slug = 0.275

f =

0.68USL D1.2 L0.6

Application of correlations developed over the past decades for pressure drop and liquid holdup should be chosen based on pipe diameter and inclination and target flow conditions such as flow regime, viscosity.

76

4.  Hydraulic and thermal analysis

FIG. 4.2  Examples of slugs flowing in a 6-inch flow loop (from right to left).



77

Hydrodynamics of multiphase flow

Slug Length Distribution 250

200

Number of Slugs

Observed Software1 Software2

150

100

50

260

250

240

230

220

210

200

190

180

170

Slug Lengths ( m )

160

150

140

130

120

110

90

100

80

70

60

50

40

30

20

0

10

0

FIG.  4.3  Slug length distribution. (Updated from Fairhurst, P., 2002. Slugging prediction, Galveston flow assurance forum, 17–19th September, 2002).

It was calculated using OpenFOAM CFD that the largest portion of pressure drop is in the slug front as shown in Fig. 4.4 (Wenzel et al., 2016). Among the correlations easiest to apply in a hand calculation was one developed by Poettman and Carpenter (1952) for a pressure drop in vertical flow. The original work was performed with the goal to reduce the horsepower required to lift reservoir fluid by selecting appropriate well tubing size. Data gathered from 34 flowing oil wells and 15 gas lift wells with production tubing sizes of 2, 2.5 and 3 in. were correlated by at least 14 variables. Correlation is for gas-liquid ratios up to 5000 cubic feet of gas per barrel of total liquid, liquid rates from 60 to 1500 barrels of total liquid per day. The authors assumed that the energy losses for multiphase flow can be correlated by the well-known Fanning equation f =

2 gc Wf D

4u 2 ( h2 − h1 ) The correlation can be used for high flow-rate wells with dispersed bubble flow pattern and is shown below: 2 fQmix M2 dP =ρ+ ρ dh 7.4131010 ρ 2 D5

78

4.  Hydraulic and thermal analysis

PRESSURE p [Pa]

PRESSURE DROP IN SLUG BODY 101000 100800 100600 100400 100200

PRESSURE p [Pa]

0

0.05

0.1

101000

0.15

0.2

0.25

0.3

0.35

POSITION [m]

100800 100600 100400 100200

FIG. 4.4  Numerical Simulation of the pressure drop in a slug body. (Reproduced with permission Wenzel, S., Czapp, M., Sattelmayer, T., 2016. Numerical investigation of slug flow in a horizontal pipe using a multi-scale two phase approach to incorporate gas entertainment effects. https://www.td.mw.tum.de/en/research/research-areas/projektbeschreibungen/­numericalinvestigation-of-two-phase-flow-in-horizontal-pipes-in-slug-flow-regime-with-special-consideration-of-the-entrainment/ (Accessed 1 June 2018)).

ρ = ρ mix = ρliquid ∗ volumeFractionliquid + ρ gas ∗ ( 1 − volumeFractionliquid ) M is the total mass, in pounds, of flowing oil, gas, and water associated with one stock tank barrel flowing through the system. Change in pressure with distance in psi/ft. due to flow resistance is proportional to density in lb./ft3, friction factor, volumetric flow rate, mass, and pipe inside diameter in inches. The product QM is in pounds of mixture per day. Friction factor f is determined from a graph plotted as f vs ρ v D and developed based on data from 49 wells on normal depletion and with gas lift. The graph may be summarized by the following values in Table 4.2 read off the original chart: The authors designated Wf as energy losses due to irreversibilities of the fluid in flow such as slippage, liquid hangup or frictional effects, in lbf ft/lbf. Vm is the cubic feet of mixed gas, oil and water at pressure P per barrel of stock tank oil based on the ratio of fluids flowing into and out of the flow string. u is integrated velocity of homogeneous mixture in feet per second, average between P1 and P2. gc is a gravitational conversion constant 32.174 lbm ft/(lbf s2). The summary and comparison with field data for multiphase flow pressure drop correlations for horizontal flow is provided by Al-Ne'aim et al. (1995).

TABLE 4.2  Values read from the friction factor chart by Poettman and Carpenter Dρ v = f =

1.4737 10 −5 M Q D

2 gc Wf D

4u ( h2 − h1 ) 2

= 7.413

1010 W f D5

Q Vm2 ( h2 − h1 ) 2

155

28

8.25

2.5

1.65

0.8

0.001

0.01

0.1

1

10

100



79

Hydrodynamics of multiphase flow

Comparisons of multiphase flow correlations and related experimental work is provided by Shea et al. (1997), and Carrascal (1996). Slugging in itself is detrimental as it can reduce the production rate. Slugging also reduces production by increasing backpressure on the well. One reference to an example of a severe slugging flow reducing production by 20% was shown in Montgomery (2002). Slugging also causes periodic impacts at elbows which may affect mechanical integrity (Hill and Wood, 1994). Extremely long liquid slugs can be created when downward sloping pipelines lead to riser pipes in deepwater operations. These “severe slugs” can cause serious upsets in separation processes, high pipe vibration and stresses during the arrival stage, and paraffin deposition problems near the riser base.

Designing out severe slugging Production system may be designed to minimize severe slugging by routing the flow predominantly uphill. This is the common design technique used by offshore operators. However, in onshore production in shale wells it may be more beneficial to route the flowing the lateral portion of the well downhill, in a so-called toe-up configuration. Although this approach in shale causes more flow instability, it allows liquids to accumulate at the well heel location which then may be lifted to surface using artificial lift methods. A novel method to control slugging was recently proposed (Makogon et  al., 2011, US8393398). The system has no automation or moving parts and was shown in pilot-scale tests to help reduce slugging. It may be installed during initial construction or retrofitted to an existing system. After the concept model of severe slugging control method showed that slugging was eliminated in a multiphase flow simulator, the pilot tests quantified the range of the method performance in a 3-in. diameter 20 m pipeline—14 m riser or lateral-vertical flow geometry. The effect is shown in the charts below in Fig. 4.5 indicating flow regime maps without and with the method installed. Not all combinations of gas and liquid velocities were affected equally, but in multiple cases the method was effective. Flow stability was achieved at lower superficial gas velocities. Backpressure fluctuations were reduced or eliminated as data in Fig. 4.6 shows. An example of complete elimination shows backpressure fluctuation without and with the method implemented. 10

10 Severe Slugging Transition

Severe Slugging Transition Stable

VSL [m/s]

VSL [m/s]

Stable 1

0.1 0.1

1

10

1

0.1 0.1

VSG, 0 [m/s]

FIG. 4.5  Effect of flowline geometry on severe slug suppression.

1 VSG, 0 [m/s]

10

80

4.  Hydraulic and thermal analysis 40

VSL =0.9 m/s,

VSG =0.2 m/s

35

Pressure, [psia]

30 25 20 15

No Modification 10

Modification One Modification Two

5

Modification 3

0 0

50

100

150

200

250

300

350

Time, [s]

FIG. 4.6  Effect of flowline arrangement on backpressure fluctuations.

Besides severe slugging or liquid loading control, the method may be extended to optimize gas lift effectiveness as in riser-based gas lift systems. Method may help extend production of tiebacks with terrain slugs or declining and water-producing fields by recovering loaded up production stopped by severe slugging. Method may help reduce slug vibration by breaking large slugs into smaller ones, or to homogenize multiphase flow at subsea boosting pump intake. With no moving parts or electronics, the method is expected to have higher reliability.

Multiphase flow liquid holdup—Vertical vs horizontal In steady state operation the holdup averaged over large length does not change in vertical or horizontal flow, however local holdup can change in slug or churn flow. Multiple correlations have been developed to calculate the liquid holdup value in either vertical or horizontal configuration. Liquid holdup and entrainment in vertical flow are related to the liquid loading of wells. A correlation developed by Turner et al. (1969) based on Hinze (1955) flow equations by balancing gravity and drag forces acting on a droplet and updated by Coleman et al. (1991) allows one to estimate the minimum gas velocity in a well at which liquid entrainment will be sufficient to lift the liquids to surface. The Turner correlation was found to have a closer match to field data in Marcellus shale (Child and Brauer, 2017). It may be used with wellhead pressures over 1000 psi or 70 bar to find the minimum gas velocity u in feet per second to lift water or oil. 1

u = 1.912

1

σ 4 ( ρ L − ρG ) 4 1

ρG2 The density of gas is proportional to pressure, and densities of liquid may be assumed as 45 lbm/ft3 for oil and 67 lbm/ft3 for salt water. As the typical surface tension for gas-oil is



Thermal effects

81

25 mN/m and 60–65 mN/m for gas-water, in field units these are 0.17 lbf/ft and 0.44 lbf/ft. The authors suggested that heavier water is more likely to accumulate downhole, thus minimum gas velocity to lift water should be used. In an example calculation it equals about 7 ft/s or 2 m/s for a well with 1000 psi upstream of the tree choke. As pressure drops to 500 psi gas becomes less dense and can entrain less water so the minimum velocity increases to 10 ft/s or 3 m/s. A recent overview for multiphase flow correlations for inclined and horizontal flow in pipelines is provided in Jerez-Carrizales et al. (2015). The correlations implemented in commercial software have been extended to use 3-phase correlations with water, and sometimes with entrained solid particles. A solids transport model has been presented by Warner and Letizia (2001). Transient pressure hydraulic analysis is associated with surge calculations and HIPPS systems. HIPPS systems can provide economic alternative to installing a thick-wall pipeline rated to the maximum pressure which may be experienced in the production system. Instead, only a portion of the system which will definitely experience high pressure will have a pipe rated to higher pressure for example during a shut-in, whereas the portion of the production system which will experience lower pressure during production can be equipped with a pipe rated to a lower operating pressure. The two portions of the production system would be separated by a fast acting HIPPS valve which can close in a few seconds. A short portion of the production system downstream of the HIPPS valve would still be rated to the higher pressure to account for the pressure increase while the HIPPS valve is closing. Flow assurance uses transient analysis to determine the length of the reinforced pipe downstream of the HIPPS valve. Flow assurance hydraulic analysis for HIPPS for subsea and for onshore or topsides facilities may rely on API 17TR13, section 10.8, and API 17O standards. Flow energy dissipation in gas-dominated systems and in multiphase systems is influenced by conduit roughness. Values for commonly used materials are summarized in the chapter on reference information.

Thermal effects Heat transfer Typical average values for seawater flow velocity is 0.1 m/s and for air 1 m/s. Typical seawater temperature is 4 °C at depth greater than 1000 m worldwide. Actual values must be obtained from the recent meteorology and oceanography (metocean) report for the region of interest, with seasonal variation. As produced fluids flow from a warm reservoir through progressively colder environment, heat transfer occurs by conduction and convection. Changes in produced fluid temperature cause phase transitions which cause multiphase flow, solids precipitation and other engineering challenges. Insulation helps maintain heat in the produced fluid. Thermal properties of various materials commonly used in production systems are summarized below. These values in Table 4.3 are indicative only. Actual values should be verified for relevant conditions.

82

4.  Hydraulic and thermal analysis

TABLE 4.3  Material properties for thermal analysis Heat capacity J/kg K

Density kg/m3

Conductivity W/m K

Carbon steel

45.3

460

7865

CRA cladding SS316

14.5

500

7990

Duplex steel

18.2

460

7833

Flexible carcass

11.6

502

4835

Flexible pressure sheath

0.415

2023

945

Flexible armor

0.93

502

7076

Flexible fabric tape

0.6

1366

761.5

Flexible outer sheath

0.386

2153

940

Fiberglass (shale onshore pipe)

0.04

700

1520

Adhesive

0.22

2182

900

Asphalt enamel

0.692

1400

1324

Concrete weight coating

2

980

3040

Heat capacity J/kg K

Density kg/m3

Conductivity W/m K Fusion bonded epoxy

0.3

1500

1300

Novolastic

0.167

2500

993

Polypropylene foam

0.174

1744

720

Polypropylene solid

0.254

2153

900

Polypropylene weight coat

0.35

1300

2000

Spray polyurethane foam

0.16

1500

750

Thermotite deep foam

0.177

2017

760

Thermal sprayed aluminum

237

1005

2713

Neoprene

0.265

1340

1400

Aerogel

0.02

2100

20

Rockwool

0.045

840

128

Nylon

0.195

1700

1050

Glass

0.289

2000

1300

Foam

0.18

886

790

High density polyethylene

0.259

1776

936

PIPE LAYERS

INSULATION LAYERS



83

Thermal effects

TABLE 4.3  Material properties for thermal analysis—Cont’d Concrete

1.7

840

3040

Light cement

0.346

1256

800

Medium cement

0.692

1195

1400

Heavy cement

1.25

1256

1900

Conductivity W/m K

Heat capacity J/kg K

Density kg/m3

Ice

2.16

2108

910

Wax

0.25

2400

900

Methane hydrate

0.68

2080

910

Asphaltene

0.756

1340

1200

Scale calcite

2.12

2500

2710

Salt, scale halite

5.4

880

2160

Marine growth hard clams

2.88

2000

1120

Marine growth soft sponges

0.58

4200

1000

Onshore soil

1.3

938

2400

Undisturbed subsea soil

1

938

2400

Sand

2

830

1600

Reservoir rock

2

880

2100

OTHER MATERIALS

FLUIDS Conductivity W/m K

Heat capacity J/kg K

Density kg/m3

Expansion 1/C

Viscosity N s/m2

Reservoir fluid

0.295

1963

760

0.000744

0.0092

Liftgas

0.043

2747

107

0.0005

1.58E-05

Brine

1.73

2897

1400

0.0005

0.0005

Air

0.026

1005

1.22

Diesel

0.141

2093

840

Water

0.59

4184

1000

Oil

0.15

2100

860

Methanol

0.204

2430

791

MEG

0.25

2350

1145

Drilling mud

0.141

2093

1200

Drilling base oil

0.141

2093

780

84

4.  Hydraulic and thermal analysis

Joule-Thomson effect Minimum temperature in the production system is expected to occur in one of the two scenarios: - During restart due to JT cooling across the choke (so-called chilly choke conditions). - During system depressurization due to JT cooling across the flare system valve. In the first case a reservoir is below the bubble point pressure, reservoir fluid is saturated with gas, and the well is produced in multiphase natural depletion mode without artificial lift. Fluid settles downhole in such a well during a shut-in, and gas remains near the wellhead and cools down to the ambient temperature. During a restart, the gas is produced initially before the well unloads the liquids and multiphase production resumes. The initially produced gas is at a high wellhead shut-in pressure and at low ambient temperature. Flow of such gas across a partly opened wellhead tree choke causes it to expand and cool. When pressure drop across the valve is less than approximately 50%, gas expands and its temperature drops as described by a thermodynamic equation of state in proportion to the change in pressure and compressibility, which in turn depends on pressure and temperature. Reservoir may also be above the bubble point pressure. Then the JT effect will cause heating if pressure downstream of the choke is still above the bubble point pressure. JT effect will cause a combination of heating and then cooling if the pressure downstream of the choke is below the bubble point pressure. In the second case of flow to flare an operator may be requested to depressurize the system, for example to remedy or to prevent a hydrate blockage. Flare system is normally rated to pressures much lower than the production system, so a greater pressure differential may be expected. In case of depressurization there will always be JT cooling. When the pressure drop is greater than 50%, for example from 50 bar upstream of the valve to 10 bar downstream, critical flow or choked flow occurs as exiting gas velocity approaches the speed of sound in gas at the outlet pressure and temperature, which limits the cooling of the expanding gas. Typical coldest temperatures for hydrocarbon gas in critical flow downstream of a restriction is of the −50 °C order of magnitude, not much colder. Flow velocity across a critical flow choke can then only be increased if pressure upstream of the choke increases. The choked flow discharge velocity may limit the depressurization flow rate. In both cases flow from high to low pressure causes the fluid to change temperature which may affect the integrity of materials in the production or the depressurization systems. The materials are exposed to ambient temperature, which supplies heat and offsets the JT cooling. A smaller valve opening may be used to limit the flow of cold gas mass in order to maintain temperature of the system above the material minimum temperature limit.

Flow modeling Correlations A number of correlations have been developed over the years using various data sets to more accurately predict pressure drop and liquid content in a flowing fluid system. Most of



85

Flow modeling

TABLE 4.4  Application of correlations to flow in cylindrical pipes Correlation

Geometry

Development

Beggs-Brill (Beggs and Brill, 1973)

Inclined

Empirical

Duns-Ross (Duns Jr. and Ros, 1963)

Vertical

Empirical

Hagedorn-Brown (Hagedorn and Brown, 1965)

Vertical

Empirical

Mukherjee-Brill (Mukherjee and Brill, 1985)

Inclined

Empirical

Dukler (Dukler et al., 1964)

Vertical

Mechanistic

Aziz (Aziz et al., 1972)

Vertical

Mechanistic

Observation

Small diameter

Holdup model issues

the flow modeling today is performed using software. Discussion and review of various flow correlations is available in literature such as (Brill and Mukherjee, 1999). To name a few correlations as in Table 4.4 and their typical application to flow in cylindrical pipes, A more detailed information on flow correlation is in the chapter on reference information. Although each correlation had been fit to best accuracy to data available at the time, broader application of two-phase flow correlations may provide ±50% accuracy in system with different conditions. At present both engineering firms and academia aim to use computational power to validate three-phase correlations against ever larger data sets, including tens of thousands of flow cases (Roullier et al., 2017). This results in a more reliable predictive capability of software tools and more cost-effective production system design.

Dimensionless numbers The dimensionless numbers more commonly used in flow assurance as in multiphase flow, fluid interfaces or solids deposition modeling include: Reynolds Re = Prandtl Pr = Froude Fr =

Mach = Ma Euler Eu =

ρ vD inertial force = µ viscous force

momentum diffusion µ = k / CP thermal diffusion v

( g D)

0.5

=

inertial force gravitational force

compressible fluid velocity v = vSound speed of sound in compressible fluid

∆P pressure force = = energy dissipation in fluid flow ρ v2 inertial force

86

4.  Hydraulic and thermal analysis

Grashof Gr =

Nusselt Nu = Lewis = Le

L3 ρ 2 β g ∆T

µ2

=

buoyancy viscous force

h d convective heat transfer = k conductive heat transfer a Sc thermal diffusion = = DAB Pr mass diffusion

µ viscous mass transfer ρ Schmidt Sc = = DAB diffusive mass transfer Sherwood = Sh Weber We =

ρ v 2 Ddroplet σ interface

=

K c L convective mass transfer = D diffusive mass transfer

fluid inertia = interaction of two fluids at interface surface tension

Peclet Pe= Pr = Re HEAT Pe= Sc = Re MASS

advective heat transfer diffusive heat transfer

advective mass transfer diffusive mass transfer

Graetz GzHEAT = Gz MASS =

DHydraulic L

DHydraulic L

Re Pr

Re Sc

The use of dimensionless numbers may be useful in understanding flow characteristics. For example Beggs and Brill used Froude number in coordinates to present a flow regime map. Someday multiphase software tools will be able to plot each of these dimensionless values, which may lead to new understanding of multiphase flow phenomena and improved machine learning pattern recognition.

Software Software can be broadly classified as capable of solving steady state and transient flow motion. Both classes include both empirical and mechanistic models, with the possibility to use two phase flow as in vapor-liquid, three as in gas-liquid-water or four phases with addition of a drilling mud fluid. In some instances solids transport may be added so flow of up to five phases may be modeled.



Flow modeling

87

Specialists working on hydraulic modeling for both projects and operations offshore prefer to use transient multiphase simulators because the production system flow path geometry includes multiple significant changes in elevation such as wellbore and riser. Transient multiphase software allows to build the system model once and perform many different studies for both steady state and transient or time-dependent operations. Onshore systems specialists have a preference for steady state tools as onshore geometry is more uniformly flat, wells can be modeled as sources, and large networks of onshore gathering pipelines with hundreds or thousands of wells can be more reliably modeled and more accurately converged using steady state tools. With the advent of en-masse long-reach horizontal wells the flow geometry in onshore production systems becomes more reminiscent of subsea production, with a wellbore vertical section similar to an offshore riser. Transient multiphase simulator tools can accurately capture and predict flow instability such as slugging or liquid loading in horizontal wells. Both classes of software have been extensively verified against laboratory and field data and updated over the past decades. These tools provide sufficient accuracy in most cases. Accuracy of commercial tools makes flow assurance engineering more routine because the used preferred correlations limit the need for the specialty knowledge of how to set up a model for a given system.

Erosion modeling Erosion modeling has to be performed to ensure that the production system remains intact. Typical flow velocities (as an approximation) should be limited to 70 m/s for gas systems and 70 ft/s for multiphase systems where liquids are present. At higher velocities the liquid droplets may impinge on the pipe wall and affect the layer of corrosion inhibitor or corrosion product usually present inside a carbon steel pipe, which may accelerate the rate of corrosion. Several methods exist which allow to predict the erosional velocity limit for fluid motion. Some of these include: ° DNV-0501 guideline ° API 17E guideline ° NORSOK P-001 ° SPPS An overview and comparison of six models for single phase and multiphase flow is available in the literature (Parsi et al., 2016). However, each company should perform own selection and validation of an erosion modeling tool for their use.

Multiphase production problems The more common problems associated with multiphase flow include ° ° ° °

Slug movement and impacts on structures Increased pressure drop (depends on holdup and on flow regime) and lower production Liquids holdup (cause for corrosion, equipment weight, need for scraping) Solids deposition

88

4.  Hydraulic and thermal analysis

Increased pressure drop is the most omnipresent effect of multiphase flow. Many operators try to produce fluid in the same state it is in the reservoir, above the bubble point pressure in order to avoid the increased pressure loss and reduced production associated with multiphase flow. Water injection is one of the methods to maintain the reservoir pressure. Slug impacts at pipe elbows and tees occur much less often than the increased pressure drop but these impacts affect production system integrity and have a greater consequence. Thus this problem is listed at the top of the list. Deposition of solids such as soft unagglomerated hydrate slush may be accelerated by slug flow as hydrates are periodically compacted by slug impacts.

Operation online monitoring for pipeline Online production monitoring tools have been in field use for several decades. These tools allow the operator to be aware of the process parameters in every location of a production or an export pipeline without distributed instrumentation. The pressure and temperature transmitters installed at the inlet and outlet of the system along with a detailed model tuned to the historic flow data allows the monitoring tool to calculate pressure, temperature, flow rate and liquid holdup at every location along the pipe line. The production monitoring tools also can provide look-ahead modeling to forecast how the system will respond to changes in operating parameters. For example, if a pipeline carrying fluid flow is operating in a steady state it may develop certain liquid accumulation or a holdup. If the flow rate increases, some liquid will be swept downstream. The tool allows to forecast the time of the swept liquid arrival to the pipe line outlet so that operator can prepare capacity in the processing facility to accommodate the arriving liquid.

Correlations The correlations used in the production monitoring tool are the same as the ones used in multiphase flow analysis tools. Tuning of the correlations may be done individually for each flow system where the monitoring tool is deployed, to increase it accuracy.

Software Variety of online monitoring software tools exists based on multiphase flow simulators. A comparison of some of the commercial flow simulators presented by Dhoorjaty et al. (2018) shows relative agreement between the investigated commercial and academic models.

Operation online monitoring for well liquids loading and forming blockages/restrictions The production monitoring tools may be equipped with modules which detect deviations from normal parameters and interpret these as blockages, leaks and other upsets in normal production.



Design of oil/gas development project

89

Correlations The correlations used for detection of blockages rely on the phase transition conditions and blockage properties for the solids which are more likely to form in a given production or export pipeline. For example, for the detection of a wax blockage, the wax appearance temperature as a function of pressure would be used to tell the monitoring tool whether the wax solid phase is possible or not at a given location in the pipeline. The deviation of pressure drop may then be interpreted as wax or another type of restriction if wax is not thermodynamically stable at that location.

Software The same production monitoring tools can be used to detect the onset of liquids loading and the forming blockages.

Design of oil/gas development project The following flow assurance analysis is usually required for the design of a new project. ✓ Steady state line sizing and transient evaluation ° for gas fields ° for gas condensate fields & for volatile oil ° for black oil fields ° for heavy/viscous oil and tar sands production ✓ Steady state line sizing and transient analysis for gas or water reinjection case; ✓ Steady state line sizing for production chemical distribution system ✓ Optimization for the flow assurance mitigation strategy, with account for other issues and solids (wax, scale, asphaltene, slugs, sand, etc.) that might interfere in the normal production

Hydraulic management Hydraulic design should optimize both frictional and hydrostatic pressure loss, holdup accumulation, vibration, water hammer and surge exceeding normal operating parameters during steady and transient operations. Sensitivity to produced water cut should include assumption for planned and deferred water injection for pressure support, based on reservoir simulation production profiles. Operability design should ensure temperature, pressure and flow are within normal operating limits for the system at any stage in field development life. Flowlines from trees to manifolds and from manifolds to hubs should be routed predominantly uphill to minimize pressure losses due to terrain liquids holdup in low spots, in order to maximize overall recovery, and to avoid slugging to enable uniform subsea chemical distribution in produced fluid. Detailed field layout should ensure that both production and chemical injection systems can operate with acceptable pressure drop and chemical stability in subsurface, subsea, ­topsides and export systems conditions.

90

4.  Hydraulic and thermal analysis

Single line tieback concepts may be considered for early production systems. Technologies which could be considered in formulating a conceptual hydraulic design of a field development include the following: • • • • • • • • • • • •

Slug catcher or separator vessel(s) Periodic scraping Onshore or subsea compressors or booster pumps Onshore or subsea multiphase pumps Gas separator to minimize hydraulic loss or to reduce hydrate risk Water separator to minimize hydraulic loss or to reduce hydrate risk Downhole, wellhead and/or riser base gas lift Caisson gas separator if subsea reservoir is insufficiently strong Drag reducing agent chemical Multiphase flow meter or virtual flow meter Erosional limits for line sizing Water injection pump pressure limits per rock fracture gradient

Designs specific to subsea in the United States may refer to the following API technical reports: Avoidance of Blockages in Production Control Systems, API 17TR5; Attributes of Production Chemicals in Subsea Production Systems, API 17TR6; High-Pressure High-Temperature (HPHT) Design Guidelines, API 17TR8; HIPPS for subsea, API 17TR13, section 10.8, and API 17O.

Water injection management Multiphase flow assurance specialist may consult with topsides process, completion, and reservoir engineers to design an effective system for water injection. Produced water injection system should be separate from sea water injection system if produced water overboard discharge is not permitted. Injection water should be treated seawater and not produced water. Produced water injection wells are subject to faster degradation of injectivity than seawater injection wells. The injection water pump sizing and discharge pressure should take into account rock fracture gradient. Injection pump design should include flexibility for injection at or above the reservoir fracture pressure if injection above the reservoir fracture pressure is permitted. The water injection pipe line minimum flow velocity in turndown case should be over 5 ft/s. Project may consider placing water injection pump and filtration equipment on seabed to reduce the number of risers. Water hammer effects shall be accounted for in the design of all process control for valves and automation operation. Injection water quality relies on not mixing produced water and seawater in the injection system. Even with very high injection water quality, operations may need to clean the wells periodically. Injection wells should be isolated when not in service so that no cross-flow happens between injection wells on shut-in if several injection wells are fed from the same manifold.



Machine learning and artificial intelligence in flow network optimization

91

Provision for water injection line and header maintenance scraping to sweep any bacterial growth should be included, with ensuring that scraped solids do not enter the injection well or header. Proven technologies for anti-bacterial coating should be considered for water injection lines. Injection wells should have a provision for hydrate inhibitor injection as hydrocarbons may migrate up the wellbore and form a solid hydrate blockage near mudline when the injection well is not flowing.

Flow restriction and blockage monitoring Production control and automation system should be able to monitor for leading indicators of an imminent blockage and to mitigate it as early as is noticed by altering operating parameters upon approval by operations manager or by solvent / chemical injection. If flow restriction mitigation was unsuccessful or late, monitoring capability should assist in a safe and systematic remediation of blockage. Technologies which could be considered for monitoring of blockage in produced fluids include: • • • • • • • • • • • •

pressure differential deviation temperature deviation flow deviation vibration deviation valve operability change water composition and pH chemical residuals oil and water quality gas dew point and moisture content bacteria counts asphaltene instability solids TDS and TSS monitoring.

Emerging technologies which may be applicable on a case by case basis include ­gamma-ray densitometer, ultrasound solids detection, and guided wave deposit detection. The large number of monitored parameters make it conducive to implement flow and blockage monitoring with a machine learning method.

Machine learning and artificial intelligence in flow network optimization The early development in the use of computer for network flow optimization came in the form of spreadsheets with multiple runs indicating the hydraulic resistance of individual components of the network. One early example of such spreadsheet was presented by Lezeau and Leporcher nearly two decades ago (Lezeau and Leporcher, 2001). The methodology and logic presented in their work still is generally applicable to a further implementation of the network flow optimization process.

92

4.  Hydraulic and thermal analysis

Accuracy of the individual components of the hydraulic model such as reservoir flow resistance, wellbore flow resistance, tree choke flow resistance and gathering flowline and riser flow resistance all play into the overall reliability of the prediction for network flow optimization. Eventually the process was developed to integrate the network model within a single steady state multiphase simulator. There are numerous commercially available steady state simulators which can handle the task of flow network optimization. Present day simulation is seeing a growing adoption of methods based on machine learning algorithms. Multiple operator corporations and service companies are developing capability in this area and deploying their solutions as field application. In the machine learning approach, a number of simulations is performed for the individual segments and for the whole network to determine flow hydraulic loss for a given set of conditions. With the data set developed for the flow resistance versus operating conditions, machine learning database is then trained on a part of the data set, with the remaining part of the simulations comprising the data set kept for verification or validation of the accuracy of the trained database prediction. Modern tools such as Python 3.7 language and Pytorch library for parallelizing the database training in order to save time, with appropriate integrated development environment tool such as Jupyter, may be used to implement artificial intelligence for flow network optimization. Development tools keep evolving along with hardware and software, so newer ones may gain acceptance with time. Recent implementations of machine learning also deal with virtual flow metering (Andrianov, 2018), choke control, gas lift optimization, as well as the detection of flow assurance blockages building up in the production system. A comparison of various artificial intelligence methods for multiphase hydraulic calculations with field data is provided by Attia et al. (2015).

References Al-Ne’aim, S.A., Aggour, M.A., Al-Yousef, H.Y., 1995. SPE-29850, Horizontal multiphase flow correlations for large diameter pipes and high flow rates. In: Presented at Middle East Oil Show, 11–14 March Bahrain. Andrianov, N., 2018. A machine learning approach for virtual flow metering and forecasting. In: Proc. of 3rd IFAC Workshop on Automatic Control in Offshore Oil and Gas Production, Esbjerg, Denmark, May 30–June 01. Arabnejad, H., Mansouri, A., Shirazi, S.A., McLaury, B.S., 2015. SPE-174987, evaluation of solid particle erosion equations and models for oil and gas industry applications. In: Proceedings SPE ATCE Houston 28–30 September. Attia, M., Abdulraheem, A., Mahmoud, M.A., 2015. SPE-175724, Pressure drop due to multiphase flow using four artificial intelligence methods. In: SPE North Africa ATCE, 14–16 September, Cairo. Aziz, K., Govier, G.W., Fogarasi, M., 1972. Pressure drop in wells producing oil and gas. J. Can. Pet. Technol. 38–48. Beggs, H.D., Brill, J.P., 1973. A study of two-phase flow in inclined pipes. J. Pet. Technol. 25 (5), 607–617. Blasius, P.R.H., 1913. Das Aehnlichkeitsgesetz bei Reibungsvorgangen in Flüssigkeiten. Forschungsheft 131, 1–41. Brill, J.P., Mukherjee, H., 1999. Multiphase Flow in Wells. SPE Monograph series. vol. 17. Richardson, Texas, Society of Petroleum Engineers. Jorge Fernando Carrascal, 1996. Multiphase flow application to ESP pump design program. Texas Tech University. Master of Science Thesis. Child, H., Brauer, P., 2017. Comparing HZ Critical rate models against Marcellus field data. In: Gas well deliquification workshop, Feb 20-22, 2017, Denver. Coleman, S.B., Clay, H.B., McCurdy, D.G., Norris, L.H., 1991. A new look at predicting gas-well load up. J. Pet. Tech., 329–333.



Further reading

93

Dhoorjaty, P., Erickson, D., Kowta, R., 2018. A comparative study of the performance of multiphase flow pipeline simulators in a hilly terrain pipeline. In: BHRG Multiphase Conference, Banff. Dukler, A.E., Wicks, M., Cleveland, R.G., 1964. Frictional pressure drop in two-phase flow: an approach through similarity analysis. AlChE J. 10 (1), 44–51. Duns Jr., H., Ros, N.C.J., 1963. Vertical flow of gas and liquid mixtures in wells. In: Proceedings of 6th World Petroleum Congress, pp. 451–456. Fairhurst, P., 2002. Slugging prediction, Galveston flow assurance forum, 17-19th September. Hagedorn, A.R., Brown, K.E., 1965. Experimental study of pressure gradients occurring during continuous twophase flow in small-diameter vertical conduits. J. Pet. Technol, 475–484. Hetsroni, G., 1982. Handbook of Multiphase Systems. Hemisphere Publishing Corporation, McGraw Hill Book Company. Hill, T., Wood, D.G., 1990. A new approach to the prediction of slug frequency. In: SPE-20629, SPE ATCE, pp. 141–149. Hill, T.J., Wood, D.G., 1994. Slug flow: occurrence, consequences and prediction. In: SPE-27960, In University of Tulsa Centennial petroleum engineering Symposium. Hinze, J.O., 1955. Fundamentals of the hydrodynamic mechanism of splitting in dispersion processes. AICHE J. 3, 289. Jansen Jeppe, M., 2009. Evaluation of a flow simulator for multiphase pipelines. Master of Science Thesis, Norwegian University of Science and Technology. Jerez-Carrizales, M., Jaramillo, J.E., Fuentes, D., 2015. Prediction of multiphase flow in pipelines: Literature review, Ingeneria y Ciencia. Lezeau, P., Leporcher, E., 2001. A spreadsheet tool to ease the selection of a Deepwater production network. In: Proceedings 10th International Conference on Multiphase Flow, BHRg, Cannes France 13–15 June. Makogon, T.Y., Estanga, D., Sarica, C., 2011. A new passive technique for severe slugging attenuation. In: 15th Multiphase Production Technology Conference, Cannes, France: 15–17 June. Montgomery, J.A., 2002. Severe slugging and unstable flows in an S-shaped riser. PhD Thesis, Cranfield University. p. 22. Mukherjee, H., Brill, J.P., 1985. Pressure drop correlation for inclined two-phase flow. J. Energy Resour. Technol. 107, 549–554. Parsi, M., Kara, M., Sharma, P., McLaury, B.S., Shirazi, S.A., 2016. Comparative study of different erosion model predictions for single-phase and multiphase flow conditions. In: OTC-27233, Offshore Technology Conference, 2–5 May, Houston. Poettman, F.H., Carpenter, P.G., 1952. API-52, The multiphase flow of gas, oil and water through vertical flow strings with application to the design of gas-lift installations. In: Drilling and Production Practice. American Petroleum Institute, p. 257. Roullier, D., Shippen, M., Adames, P., Pereyra, E., Sarica, C., 2017. Identification of optimum closure relationships for a mechanistic model using a data set for low-liquid loading subsea pipeline. In: SPE-187327, SPE ATCE, 9-11 October, San Antonio. Shea, R.H., Rasmussen, J., Hedne, P., Malnes, D., 1997. Holdup predictions for wet-gas pipelines compared. Oil Gas J. 95 (20). Shea, R., Eidsmoen, H., Nordsveen, M., Rasmussen, J., Xu, Z., Nossen, J., 2004. Slug frequency prediction method comparison. In: BHRG Multiphase Production Technology Proceedings, Banff, Canada. Swamee, P.K., Jain, A.K., 1976. Explicit equations for pipe-flow problems. In: J or the Hydraulics Division, ASCE. Vol. 102, No. HY5, Proc. Paper 12146, May, pp. 657–664. Turner, R.G., Hubbard, M.G., Dukler, A.E., 1969. Analysis and prediction of minimum flow rate for the continuous removal of liquids from gas wells. J. Pet. Tech, 1475–1482. Warner, A., Letizia, L., 2001. Hyprotech, Gas-liquid Sand flows in horizontal pipelines—a novel model. In: Proceedings 10th International Conference on Multiphase Flow, BHRg, Cannes France 13-15 June. Wenzel, S., Czapp, M., Sattelmayer, T., 2016. Numerical investigation of slug flow in a horizontal pipe using a multiscale two phase approach to incorporate gas entrainment effects. https://www.td.mw.tum.de/en/research/ research-areas/projektbeschreibungen/numerical-investigation-of-two-phase-flow-in-horizontal-pipes-in-slugflow-regime-with-special-consideration-of-the-entrainment/. (Accessed June 1, 2018).

Further reading Makogon, T.Y., Brook, G.J., 2013. Device for controlling slugging. US Patent 8393398.

C H A P T E R

5 Flow restrictions and blockages in operations O U T L I N E Frequency of blockages

97

Frequency of blockage remediations Duration of hydrate and other flowline remediation

97

Hydrate versus other flowline remediation time

98 99

Blockage remediation

101

Hydrate of natural gas Introduction Gas hydrate formation Hydrate propensity, subcooling, supercooling and overpressurization Chemistry Thermodynamic features Stability Problems related to hydrate formation Hydrate plug formation mechanism Calculating location of hydrate blockage in a pipe Prevention of hydrate formation Hydrate dissociation Hydrate blockage remediation Comparative economics of hydrate prevention methods

101 101 102

Handbook of Multiphase Flow Assurance https://doi.org/10.1016/B978-0-12-813062-9.00005-1

Environmental impacts of hydrate remediation Health impacts Effect of hydrates on corrosion Gas hydrate in wells and in nature Hydrate management Emerging technologies of hydrate management Modeling of gas hydrates Case studies and process safety Commissioning/dewatering of pipelines to avoid hydrates

104 106 106 108 108 109 109 110 117 118 121

Asphaltenes Introduction Asphaltene chemistry Reservoir and wellbore plugging Prediction of asphaltene risk Light oil and EOR Gas condensate Heavy oil Role of asphaltenes in microbubble capture Asphaltene precipitation and deposition in wells and pipelines Monitoring and remote sensing of asphaltenes

95

122 123 123 125 127 128 129 131 139 140 140 141 141 142 143 143 144 144 144 145

© 2019 Elsevier Inc. All rights reserved.

96

5.  Flow restrictions and blockages in operations

Remediation of asphaltene plugging Environmental impact of various techniques Modeling of asphaltenes Prevention of asphaltenes

146

Effect of PVT conditions Role of composition Miscellaneous factors Tubular plugging Prevention techniques Remediation techniques Environmental impacts of remediation techniques Measurement techniques Conventional techniques Remote sensing and monitoring Emerging techniques Modeling Comprehensive modeling Waxy gels Case studies

146 146 147

Bacterial growth Topsides process equipment Water injection wells Bacterial growth management

148 148 148 148

Corrosion products Transport of solid corrosion products

149 149

Diamondoids

149

Ice

150

Liquid holdup Water in gas and oil lines Condensate in gas lines Steam (condensed water in oil sands steam injection lines) Liquid accumulation in horizontal and vertical wells

150 150 151

Multiphase flow Flow resistance of gas, oil and water Vacuum condition and pressure surge during stock oil flow

153 153

Sand transport Minimum transport velocity Erosional velocity limits Liquid with solids (hydrate, corrosion products, scale)

153 154 155

Paraffin wax Introduction Chemistry Composition Structure Wellbore and reservoir plugging

156 156 159 159 160 160

151 152

153

156

161 163 163 163 164 167 168 168 171 171 171 171 173 174 176

Reservoir souring Introduction Mitigation of reservoir souring Treatment of sour production Modeling of reservoir souring

176 176 177 177 178

Scale

178 178 178 178 179 179 180 181

Description Carbonate Sulfate Analysis Prediction Remedial actions Scale prevention

Interaction of flow assurance issues with and effects on produced fluids and flow

181

Seven suggestions from operations in deepwater and onshore

183

References

184

Further reading

188

There are many types of flow assurance restrictions. Some of the more frequently encountered ones include asphaltenes, waxes, hydrates, scale and sand. Flow assurance issues which may impede flow include the following: • Hydraulic liquids holdup • Emulsions, foam



Frequency of blockage remediations

97

• Water injectivity loss • Formation damage or compaction • Hydrate • Ice • Wax and gels • Scale • Sulfur deposition • Naphthenate • Asphaltene • Diamondoids • Heavy oil • Viscous oil • Bacterial growth • Corrosion products • Sand • Field layout with low spots Choice of technology(ies) for managing each of these possible threats should be based on reservoir rock type, reservoir fluids chemistry, regional environmental regulations, regional waste handling availability, and technology commercial availability in the region. Various combinations of available and permissible flow assurance technologies should be screened in preliminary concepts evaluation. Technologies may be changed or made complementary during the life of field, for example, operations may choose to switch from AA to KHI as water cuts increase, or from KHI to MEG as demand for system reliability increases. Details of addressing some of the flow assurance risks below may serve for development of project-specific flow assurance.

Frequency of blockages The sequence in Fig. 5.1 and in Table 5.1 below is based on the subjective survey from the SPE Flow Assurance Forum held in USA in June 2015. Although the forum was attended by flow assurance specialists from different continents, these values should be used as indicative only as this survey represents a fairly small sample size for a proper statistical analysis. Location and frequency of blockages were marked by the Forum participants based on their knowledge of the industry.

Frequency of blockage remediations Historically, the US Minerals Management Service had received and processed applications for flowline remediation in deepwater. Between 1991 and 1998, 52 subsea flowlines were reported blocked with wax and hydrates (Alvarado, 1999, 2003). Of these, all hydrate blockages were remediated, and approximately half of the pipelines plugged with wax were abandoned. Since then, several long-reach coiled tubing technologies have been commercialized to clear out blockages from pipelines by hydraulic jetting. Similarly, technologies for subsea hydrate and other blockage remediation by a subsea pump depressurization have matured and became a common practice. Some information about the global use of subsea blockage remediation with a commercially available subsea pump equipment during the past decade from 2008 through 2017 was

98

5.  Flow restrictions and blockages in operations

FIG.  5.1  Frequency of flow assurance issues as indicated by the participants at the 2015 SPE Flow assurance Forum, representing both onshore, subsea and shale production.

TABLE 5.1  Perceived locations and frequency of flow assurance blockages Location

Asphaltene

Wax

Hydrate

Scale & sand

Reservoir

1

0

1

4

Well

30

2

0

13

Flowline & riser

0

28

24

7

Injection line

0

2

4

0

Export line

0

2

6

0

Subsea process

0

0

0

0

Topsides process

3

0

0

7

Tree & manifold

0

0

2

0

shared by one of the technology providers (Oceaneering, 2018). This information may be useful in comparison of various flow assurance strategies. Blockages occur at all water depths. The information in the graphs below is a summary of subsea remediation for hydrate remediation and for other flowline remediation over the recent decade from 2008 through 2017.

Duration of hydrate and other flowline remediation On average, hydrate remediation took 21 days; the duration was nearly independent of water depth as shown in Fig.  5.2. Other flowline remediation average time was 25 days;



99

Frequency of blockage remediations

Days for subsea remediation 160

Hydrate remediation

140

Other flowline remediation

Time (days)

120

Linear (hydrate remediation)

100

Linear (other flowline remediation)

80 60 40 20

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10,000

Water depth (ft)

FIG. 5.2  Days for remediation of subsea flow assurance blockages.

this duration showed an increasing trend with water depth. Remediation project cost may include, besides renting specialized remediation equipment, hiring a support vessel to deliver the equipment to the flowline which may range from a service boat at approx. 50–100 thousand of US dollars per day to a workover rig or a drilling rig which may cost 300–600 thousand USD per day. Additional cost for staff, engineering support, chemicals and mobilization/demobilization should also be considered when a flow assurance strategy is selected. Typical cost limit for a subsea remediation project has been around 20 million USD, but valuable high productivity assets may increase this limit. Costs are approximate and shown in 2018 US dollars. While costs tended historically to approximately double every 20 years due to inflation, future costs in USD may vary.

Hydrate versus other flowline remediation time With time the flowline remediation methods become more effective and take less time. However, the time for hydrate remediation subsea keeps increasing from year to year as shown in Fig. 5.3. The actual frequency of blockages occurrence is an important input into risk models. Recent changes in the price of the produced hydrocarbon commodity made operators optimize cost of new projects to ensure these are still profitable. One of such optimizations is risk-based flow assurance, discussed further, when the production system is estimated to get plugged once per a time period. A common flow assurance strategy is to build a dual multiphase pipeline tieback to a new field which can be scraped, and live produced fluids can be displaced with stock tank crude to mitigate most flow assurance risks. An example of a risk-based flow assurance strategy approach is to build a single multiphase flowline subsea tieback to a new field if the probable cost savings of not installing the second line outweigh, by a pre-set margin, the probable operating cost losses from the unmitigated flow assurance risks. It would be useful for such risk-based approach to know the relative frequency for ­remediation of certain types of flow assurance blockages. A summary Table 5.2 for hydrate

100

5.  Flow restrictions and blockages in operations

Progress in subsea remediation time 160 140

Hydrate remediation Other flowline remediation

120

Linear (hydrate remediation)

Time (days)

Linear (other flowline remediation)

100 80 60 40 20

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Year of work start

FIG. 5.3  Progress in subsea remediation time. TABLE 5.2  Frequency of hydrate blockage remediations by one service provider Year

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

Number

6

3

14

7

7

12

14

10

5

11

remediation performed by one technology provider below may be indicative of the overall frequency of flow assurance blockages. While the average number of hydrate blockage remediation projects per year is 9 globally for one service provider as shown in Fig. 5.4, this is a lower estimate. Some blockages remain Hydrate remediations per year 16 14 12 10 8 6 4 2 0 2007

2008

2009

2010

2011

2012

2013

2014

FIG. 5.4  Trend of subsea hydrate remediations by one service provider.

2015

2016

2017

2018



Hydrate of natural gas

101

in a plugged pipeline until the regulatory requirements mandate the operator to remove the blockage or to decommission the pipeline. Some blockages get remediated by operator companies through operating process parameters manipulation, with proper engineering support. Some blockages get remediated by other service providers. In rare cases, blockages have been known to get remediated by a confluence of events triggered by a natural phenomenon like a hurricane as discussed earlier in Chapter 1. Historically, the number of hydrate blockages has been on an uptrend.

Blockage remediation Production system should be designed for blockage remediation to enable the removal of blockage(s) and to avoid secondary re-formation of solids. Access points and topsides deck space should be designated for regionally available remediation equipment. System equipment should include provisions for flow reversal for blockage remediation such as a stuck scraper. Technologies which could be considered for remediation of blockage in produced fluids include: • • • • • •

Solvent chemical progressive scraping depressurization from topsides depressurization through gas lift line subsea depressurization skid dry tree coiled tubing jetting.

Field-proven technologies which may be applicable on a case by case economic basis include pressure pulsation, long reach coiled tubing, and active electric heating.

Hydrate of natural gas Introduction Hydrates are solid crystals combining water molecules and guest molecules in a proportion of approximately 10 wt% gas and 90 wt% water. Flow assurance deals mainly with hydrates of light hydrocarbons such as methane, ethane, propane and isobutane present in natural gas. Hydrates were first observed and reported by Priestley (1778). The compound was named by Davy. After hydrates form, they get deposited on pipe wall or dispersed in hydrocarbon liquid or in water. Hydrate acts as a solid restriction or as viscous slush creating resistance to fluid flow. Both light and medium gas components can form hydrate crystals but hydrates of ­medium-sized molecules are less often encountered in production systems. Medium-small molecules like neohexane can still fit in hydrate cells (Makogon, 1996) but in general larger hydrocarbon molecules with 5 or more carbon atoms in a chain are too big to fit as guests in the hydrate cells.

102

5.  Flow restrictions and blockages in operations

Gas hydrate formation The formation of gas hydrate usually begins at the interface of water-gas-solid or water-­ hydrocarbon-solid. This is called heterogeneous nucleation. The presence of a solid reduces the time it takes to start the formation of the crystal, called an induction time. In reality this is related to the reduction of the energy barrier as described in a book by Makogon (1974, 1981) on pages 65 and 72 accordingly. Whether a small crystal nucleus continues to grow larger than the critical radius or dissolve depends on the latent heat of crystallization Q, supercooling at which crystallization occurs and nucleus' specific surface energy σ:

(

logP [ bar ] = β + 0.0497(T   C  + k T   C 

2

)

Crystals don't start to form as soon as the hydrate stability condition is reached. It takes extra cooling below the stability temperature to help organize the water molecules into a lattice of cells which can trap gas molecules. This extra cooling is known as subcooling or supercooling or propensity. These terms are used interchangeably. The greater the subcooling, or the difference between hydrate equilibrium temperature and local temperature in the system, the sooner the crystals will start to form. Similarly Sloan (1990) in p. 83 also provides an expression referenced from prior publications for the critical size of hydrate crystal nuclei above which the crystal continues to grow as a function of the surface tension σ and a change in Gibbs free energy. rcr = −

2σ ∆g

Neither manuscript provided a clear indication of what the typical size for the critical nucleus would be—whether it is of the order of magnitude of 10 Angstroms, 100, or 1000, rightly so because the nucleus size depends on the process. Nonetheless knowing the order of magnitude for this value is important for a general understanding of how hydrates form. Koh et al. (1996, 2000) suggests the gas hydrate nucleus size is of the order of 1 nm. A molecular modeling work by Walsh et al. (2009) with TIP4P-ICE confirms critical nucleus is of the nanometer scale. The importance of microbubbles and nanobubbles of gas for hydrate formation was described by Makogon (1996), ICGH-2. The radius of such microbubbles was related to pressure of gas in such bubbles and the surface tension through the Laplace's law and the van der Waals equation. An example detailed calculation presented in that work showed the gas microbubble size at 4.3 nm or 0.0043 μm. Pressure inside such gas microbubbles was estimated to be on the order of tens of MegaPascals or higher. An important observation is made by Sloan (1990) in p. 74 that works by Angell and Speedy and Angell (1976) indicated that concentration of hydrogen-bonded polyhedra is suggestive of pre-nucleation phenomena. Rahman and Stillinger (1973) showed that hydrogen-bonded water molecules is arranged as polygons. Makogon (1974, 1981) calculated from measurements the number of hydrogen bonds remaining in water after melting of ice and after dissociation of hydrate. Number of hydrogen bonds in water is shown in Table 5.3.



103

Hydrate of natural gas

TABLE 5.3  Number of hydrogen bonds in water at different temperatures Temperature (°C)

0

25

50

100

150

200

250

300

350

% broken H-bonds in water

9

11

13.8

20

26

34

45

61

86.5

Average number of water molecules in a cluster

860

455

288

70

37

16

8

4

1–2

After reference Makogon, Y.F., 1974. Gidraty Prirodnogo Gaza (Hydrates of Natural Gas, in Russian). Nedra, Moscow.

Vast majority of water molecules are hydrogen-bonded to their neighbors, with only a small portion of bonds broken due to conformational defects, for example if two neighboring water molecules point their hydrogen atoms in each other's direction. Broken bonds between neighboring water molecules are eventually restored due to molecules' reorientations and rearrangements. Some bonds are strained because of the differences in molecular positions. A conceptual schematic of water molecules interconnected into a network by hydrogen bonds is shown below, with few bonds broken. The network is dominated, according to Rahman and Stillinger, by hexagons and pentagons as shown in Fig. 5.5. The results shown in Chapter 10 confirm this distribution. The water molecules are predominantly bonded, but the network contains defects and some bonds are strained. When sufficient amount of gas such as methane is dissolved in

FIG. 5.5  Network of hydrogen-bonded water molecules is dominated by hexagonal and pentagonal ring groups.

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5.  Flow restrictions and blockages in operations

FIG. 5.6  Hydrate crystal formed by a lattice of hydrogen-bonded water molecules around a gas molecule.

­ ater, methophobicity or repulsion of water molecules from methane helps reorganize the w water network by making hollows or cavities to contain methane molecules into a crystal lattice as sown in Fig. 5.6 with a less strained arrangement of hydrogen bonds. The method for modeling water properties with a computer and calculating the number of polygons is discussed in Chapter 10. Rate of hydrate formation in production systems, process equipment and in nature may be limited by the availability of water molecules, gas molecules and by heat transfer away from the crystallization front. The rate of hydrate blockage formation in operating conditions may range from tens of minutes in liquid-dominated multiphase flowing systems to days in gas systems, depending on the limitations mentioned above. The changes in differential pressure or changes in the amount or composition of water arriving to the system outlet within this timescale may be indicative of hydrate formation. The rate of hydrate formation observed in laboratory as shown in Fig. 5.7 conditions can be as high as 1 mm/s (Makogon, 1999) when there are no limitations to heat or mass transfer. The typical growth rate of methane hydrate at an interface with seawater is on the order of 5 mm/min (Makogon et al., 2000). The growth rate decreases by 60% to approximately 2 mm/ min with a thermodynamic inhibitor such as 5% methanol.

Hydrate propensity, subcooling, supercooling and overpressurization In addition to subcooling, the overpressurization can measure how far in the hydrate stability region is the local condition. Overpressurization may be a useful measure in laboratory evaluation of gas hydrates (Talley, 2000). Overpressurization may help discern the performance of some LDHI chemicals



105

Hydrate of natural gas

FIG. 5.7  Fast hydrate growth at gas-water interface at 110, 150, and 190 s (Makogon, 1999).

such as KHI or kinetic hydrate inhibitors. While some KHIs may perform well at a high subcooling at lower pressures (e.g. below 50 bar), their performance may deteriorate at the same subcooling but at higher pressures. Although the terms may be seen in use interchangeably, there is a difference as shown in Fig. 5.8. Due to the non-linearity of hydrate equilibrium curves plotted in pressure-temperature coordinates, the hydrate propensity varies whether measured as subcooling or as overpressurization. It is possible to plot a hydrate curve as a straight line (Dendy Sloan, personal communication, 1993; Makogon, 1994) by presenting data either in ln(pressure) versus 1/ Temperature coordinates or as a semi-logarithmic plot. To illustrate, after plotting methane hydrate stability line in semi-log coordinates, the propensity differs for a fixed subcooling and a fixed overpressurization. Methane hydrate stability data (Deaton and Frost, 1946) are shown in the plot. Onset of hydrate formation is shown from a laboratory experiment (Makogon and Holditch, 2001b, Oil & Gas Journal, p. 45). The maximum propensity at which methane hydrate formation started in a clean laboratory system observed in Fig. 1A of this work is approximately 7 °C or

Pressure (MPa)

10

1 265

CH4 hydrate stability data constant subcooling 7 K constant overpressurization 4 MPa Makogon CH 4 subcooling

270

275

280

285

Temperature (K) FIG. 5.8  Comparison of subcooling and overpressurization for methane hydrate.

290

106

5.  Flow restrictions and blockages in operations

4 MPa. The graph illustrates that the constant overpressurization line corresponds to a lower subcooling at higher pressures, which fits empirical observations for KHI performance. At lower pressures, higher subcooling may be achieved for a set overpressurization before hydrates start to form. At higher pressures, hydrate starts to form at a lower subcooling for a set overpressurization. An observation was made in laboratory tests by Makogon and Sarkisyants (1966, p. 36) that a hydrate formation condition for a multi-component gas mixture differed from the hydrate dissociation condition. The start of hydrate formation was observed at temperatures lower than hydrate equilibrium (dissociation) condition by 1–10 °C approximately as read from the graph. Makogon (1974, 1981) also studied the effect of water preheating to reduce hydrogen bond structure in water on subcooling required to start hydrate formation. Table  12 and Fig.  37 in this work show that subcooling ranged from 0.6 to 8.3 °C at 127 atm and from 3.0 to 8.2 at 75 atm for methane hydrate. For ethane hydrate, Table 13 in this [1974, 1981] work shows that subcooling ranged from 1.5 to 8.6 °C depending on pressure. He found that preheating of water had effect on subcooling, but preheating beyond 30–35 °C gave no extra effect. This is relevant to flow assurance project design because some operator companies base the hydrate risk mitigation on a fixed subcooling value. Some companies use a positive subcooling and take a calculated risk by allowing the system to operate inside the hydrate stability region by a fixed number of degrees in temperature. Some companies take a conservative approach and use negative subcooling, designing the system operation to stay away from the hydrate region by a fixed safety margin of a number of degrees. Overpressurization margin could be a more appropriate measure for use in designing a production system for hydrate risk management. Also it is not advisable to rely on positive subcooling or overpressurization (i.e. to design a system to operate inside a hydrate region) as measured in clean laboratory conditions because in field operations produced fluids introduce impurities and solid particles which act as crystal nucleation sites and allow hydrates to start forming more easily, closer to the equilibrium than in a laboratory.

Chemistry Gas hydrates are chemically neutral as no chemical reactions occur during their formation or dissociation, only a fraction of hydrogen bonds between water molecules changes. As hydrate may consume sour gas components such as CO2 and H2S, the overall pH of the fluid may change as a result of hydrate formation. Crystal surface of hydrate may be both electronegative and electropositive as shown in Fig. 5.9, depending on which level the crystal surface is cleaved at. sII hydrate {1,1,1} dominant plane is commonly seen in real crystals. Chemical conformations, bonding energy and active sites can be viewed on crystals with molecular modeling as shown in Fig. 5.10. This helps compare the effectiveness of chemicals before lab synthesis and tests.

Thermodynamic features Thermodynamically the gas hydrates act as solids with low compressibility. A summary overview of phase diagrams for gas hydrates for various components, including several



Hydrate of natural gas

107

FIG. 5.9  sII hydrate {1,1,1} dominant crystal plane commonly seen in real crystals. Model shows open large 51264 cavities. Red and blue sites represent variation in electronegativity.

FIG. 5.10  Model of polyvinylpirrolidone KHI polymer adsorbed on sII {1,1,1} crystal surface of hydrate.

108

5.  Flow restrictions and blockages in operations

­ uadruple points where ice, water, hydrate and vapor can coexist, is presented by Sloan q (1990). More rare quintuple points for hydrates also exist such as the one discovered at the Colorado School of Mines for the coexistence of water, structure I hydrate, structure H hydrate, liquid hydrocarbon and vapor five phases at the same condition. Pure gas hydrate has a relatively low electrical conductivity or high electrical resistivity which is on the order of 20,000 Ωm (Dunbar, 2013). That property, combined with the speed of sound different from that of surrounding rock is used to find location and saturation of gas hydrate deposits in geophysical studies of natural deposits of gas hydrates. Typical electrical resistivity of a gas hydrate deposit is of the order of 100 Ωm, seabed is 1 Ωm and seawater 0.36 Ωm. The compression wave speed of sound is reported at 3650 m/s, and the shear wave speed measured simultaneously, is 1890 m/s (Waite et al., 1999).

Stability Stability of gas hydrates varies with pressure and temperature. In general, hydrates are more stable at low temperatures and high pressures. At lower temperatures water molecules have less movement relative to each other. At higher pressure more guest molecules such as methane are dissolved in water. Hydrogen bonds which hold together the water molecules in the gas hydrate crystal are stable at lower temperature and at higher pressure. As an example, a structure II hydrate commonly encountered in subsea production systems typically would form at approximately 10 atm and 4 °C with fresh water without chemicals. To make a formed gas hydrate unstable, one or more of the following is required: lower pressure, higher temperature, fewer hydrogen bonds. Chemicals such as methanol act by removing hydrogen bonds from the gas hydrate crystal. Methanol does that by making the hydrogen bonds in water which makes up the gas hydrate crystal switch from hydrate to the hydroxyl group OH in methanol where electronegative oxygen in methanol attracts electropositive hydrogens in water. As 4 °C or 40 °F is a temperature usually found in deep water environment, production systems may require a depressurization to below 10 bar in order to dissociate any formed hydrate. In some cases the depressurization needs to be to a lower pressure because some chemicals such as kinetic hydrate inhibitors (KHI) stabilize hydrates (Makogon and Holditch, 2001b).

Problems related to hydrate formation Gas hydrate formation creates mainly economic but also safety issues. In onshore production systems, both wells and gathering lines get plugged by gas hydrates. In subsea systems, mainly trees, flowlines and risers get plugged. A blocked well or a flowline can no longer generate revenue. However, hydrates also have plugged process equipment and flare relief lines which led to a loss of primary containment and release of hydrocarbons. Hydrates require four conditions to form: low temperature, high pressure, water and light hydrocarbons such as gas or live oil. These four conditions can be met in some process operations which leads to partial or sometimes complete hydrate blockages. A hydrate plug occupies nearly all cross-section of the pipe. A radiographic image in Fig. 5.11 shows a hydrate plug in a USA onshore field pipeline. Partly dissociated gas hydrate particles can also be transported to relief lines from elsewhere in the plugged line and restrict or block the vent relief line. In one instance (Makogon, 2017)



Hydrate of natural gas

109

FIG. 5.11  A radiographic image of a hydrate plug in a field line.

the cross sectional area of a relief line was reduced by half, which increased the time of depressurization. Water expands more when it turns into hydrate than when it freezes as ice. Hydrates possess a significant mechanical strength. Image of a collapsed production tubing in Chapter 1 shows the expansion effect of hydrate formed at 8 °C in a well annulus at 1100 m depth. Collapse pressure was estimated at >800 atm. Volumetric expansion of hydrate relative to water can be easily calculated from the crystallographic measurements. Hydrate occupies approximately 26% more volume than the water making up the hydrate.

Hydrate plug formation mechanism The viscosity of the hydrate slurry is one reason for the plug formation. Pressure of the reservoir fluids may be insufficient to move several hundred feet of a highly viscous non-­ Newtonian liquid through a flow line. The other reason is agglomeration of hydrate particles and their adhesion to the flowline walls. Numerous field studies were dedicated to the subject. A 3-in. service flowline in the Tommelitten field in Norway was purposely plugged with hydrates nearly 20 times to study the process of hydrate plug melting. The recent advancements in hydrate research at the CSM allowed us to select the reasonable average size of a hydrate particle at 40 μm [March 2005 meeting, Golden, Colorado]. The significance of the hydrate particle size is in the hypothesis that particles larger than 40 μm would, on average, be larger than the size of the momentum or velocity boundary sublayer near a pipe wall and will be transported by flow. The model assumes that the settled (2 mol% H2S or CO2), high salinity (>100,000 TDS) and high pressures (>10,000 psi) lab measurements should be used to verify hydrate stability conditions. Hydrate formation metastability and underinhibition should not be relied upon in normal operations. On start-up, system should be thermally or chemically treated until system temperature increases sufficiently to provide a safe-out time plus a no-touch time before re-entering hydrate conditions during an aborted start-up. For systems with on-demand active heating only temperature of components without heating (jumpers, trees, risers) should be considered. For flow assurance risk management strategies, minimum water cut threshold for chemical treatment such as 1% may be used if supported by appropriate multiphase laboratory verification (flow loop or flow wheel) and by multiphase modeling to ensure that all formed hydrate is fully dispersed and does not accumulate when water cut is less than 1%. Partial gas separation may be used to avoid hydrate if supported by appropriate laboratory verification. Several methods for hydrate prevention may be used: Thermal methods Thermal insulation or line burial is used in onshore and subsea production systems. When the produced fluids remain outside the hydrate stability envelope throughout the whole length of the production system, the use of hydrate inhibitor chemicals is unnecessary. In some cases the insulation is used to prevent wax deposition and thus hydrate also gets prevented as the temperature of hydrate stability is usually lower than the temperature of wax stability. Dehydration To prevent or to shift hydrate stability before it forms, the amount of water may be reduced in a flowing gas stream. Typical dehydration of gas is to 6–7 pounds of water per million standard cubic feet of gas. Modern equipment allows to achieve dehydration to 1–2 pounds per MMSCF. Similar to gas dehydration, a partial or complete water removal from oil systems may help achieve the hydrate blockage-free production to a level where remaining water can be transported with the reservoir fluid, with or without the use of chemicals. Alternative to partial water removal may be partial gas removal from low GOR systems. If the amount of hydrate which forms after a partial gas removal can be transported with the reservoir fluid, with or without the use of chemicals, this approach may also help achieve the hydrate blockage-free production. Chemical inhibition Chemical inhibition serves the same purpose as dehydration: to prevent hydrate blockages. A variety of chemicals exist, in two broad categories these are thermodynamic inhibitors and low dosage hydrate inhibitors (LDHI). Thermodynamic inhibitors act by altering water. Low dosage inhibitors work by altering hydrate crystals. • Thermodynamic inhibitors Thermodynamic inhibitors connect to water molecules either by hydrogen bonds like alcohols as shown in Fig. 5.12 and glycols or by ionic bonds like salt ions as shown in Fig. 5.13.

112

5.  Flow restrictions and blockages in operations

FIG. 5.12  Methanol hydrogen bonding to water thus preventing water from entering hydrate.

FIG. 5.13  Salt ions of sodium chloride forming solvation shells of water molecules thus preventing water from entering hydrate.

All thermodynamic inhibitors require high concentration in water to be effective in hydrate prevention. Their dosage usually ranges between 20 and 40 mass% in water. This means that for every 60–80 tons of water there needs to be added 40–20 tons of a thermodynamic inhibitor. This becomes prohibitively expensive in regular production unless the chemical can be recovered and reused. The most commonly used chemical in oil production is methanol. The most common chemical used in gas and gas condensate production is MEG or monoethylene glycol. MEG usually requires a higher dosage compared to methanol. Other thermodynamic inhibitors which may be used, if economics is favorable or if environmental or safety regulations require it are ethanol, triethylene glycol, and diethylene glycol. Salt is seldom used in oil and gas production but almost always used in well drilling and completion work for two reasons: salt can add weight to the wellwork fluid and also provides hydrate protection. Thermodynamic inhibitors have no limitation on the amount of water they can protect from hydrate. Water cut may be as high as 99% at which point the amount of gas dissolved in the remaining 1% of produced hydrocarbon fluid may be insufficient to form an appreciable amount of hydrate solids unless the water remains stagnant in the flowline as a holdup in multiphase flow. If multiphase flow cannot sweep the stagnant water, with time the hydrocarbon gas flowing past the water holdup area will form gas hydrate, provided the pressure and temperature are appropriate. If the flow velocity of the liquid layer is less than that required to fluidize the hydrate solids, hydrates may accumulate into a blockage. Recent transient multiphase flow simulators are capable of modeling this process of hydrate accumulation. As with any software, the accuracy remains to be verified by the user. Ions of salts attract several water molecules and form salvation shells. Glycols such as monoethylene glycol (MEG) or triethylene glycol (TEG) are often used to control hydrate in longer (>30 km) flow lines gathering gas from remote wells. Glycols are usually recovered by distillation and reused in the same field due to relatively high chemical cost. Historic MEG reclamation efficiency was typically in the 70–92 wt% range, with losses to salt removal which added a requirement of a logistical chain for delivery of fresh glycol to replenish the supply. Modern glycol recovery methods allow to reach MEG purity to 98 + wt%. Over 99% of MEG is recovered and reused. In many cases the economics of hydrate control with electrical heat and glycol are competitive. Ethylene glycol is often preferred as hydrate inhibitor because it has: ‐ lower dosage requirement than the other glycols. ‐ lower viscosity than the other glycols. ‐ lowest molecular weight of the glycols.



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‐ less soluble in liquid hydrocarbons than the other glycols. ‐ freezing temperature of its water solution is lower than for the other glycols. Thermodynamic inhibitor chemicals including methanol, glycols, salts inhibit hydrates above and below 0 °C for any length of time. However, these chemicals are required in large quantities, methanol is toxic, and glycols need to be recovered from produced fluids stream to be economic. Kinetic inhibitors are not toxic and can work at any water cut (up to 100%). However, these work only during production, for a limited time, with a limited subcooling or overpressurization, and accelerate hydrates growth when they eventually stop working. Properties of glycol mixtures with water are important for a preliminary conceptual design of hydrate inhibitor delivery systems. One set of such data set (Union Carbide, 1978), updated for brevity, for density and viscosity may be used to check software correlations' predicted values. However, the best, most cost-effective and most reliable validation of a chemical property such as density or viscosity is by a laboratory measurement. Laboratory measured values should be used for a detailed project design. • Low-dosage inhibitors Low dosage inhibitors typically require 0.5–3 vol% dosage in water which is much lower than that for thermodynamic inhibitor chemicals. Cost of treatment though remains the same due to higher cost of specialty components used to formulate the LDHI. Operator may save cost on logistics of chemical delivery as less chemical volume needs to be transported. While it is not uncommon to see a separate pipeline designed to deliver MEG from shore to the production platforms, LDHI is nearly always delivered in chemical tanks also called totes to the platform. Low dosage inhibitors fall in two sub-categories: kinetic and anti-agglomerant types. Kinetic inhibitors work by adsorbing on the critical size nuclei of hydrate as shown in Fig. 5.14 and preventing their further growth, as well as by blocking methane and other gas molecules which are like building blocks from reaching the growing hydrate surface. Altering surface energy of hydrate nucleus and steric blockage of diffusion of guest molecules are the mechanisms of KHI. Eventually the chemical dissolved in water runs out and the crystals proceed to form. Effectively KHI chemicals delay the growth of hydrate solids. Kinetic hydrate inhibitors or KHIs provide a delay on the order of hours to tens of hours, depending on pressure. The further into the hydrate stability region on a pressure-temperature hydrate stability diagram is the operating point, the shorter is the KHI protection time. There are two ways to measure how far is the operating point from the hydrate stability curve: overpressurization or the difference between the operating pressure and hydrate

FIG.  5.14  KHI polyvinylpyrrolidone (PVP) polymers adsorb on hydrate nuclei and disrupt crystal growth for some time.

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s­ tability pressure at an operating temperature, and supercooling or the difference between the operating temperature and hydrate stability temperature at an operating pressure. The higher the overpressurization, the sooner a KHI can fail. Similarly the higher the supercooling, the sooner a KHI can fail. Empirical evidence (Talley, 2000) suggests that overpressurization is more important to reducing KHI effectiveness time than supercooling. The first of the two sub-categories, the KHI have no limitation on the amount of water they can protect from hydrate. Operators use that property to deploy KHI in the areas of high water production such as late life deepwater oil wells, gas and gas condensate production with limited residence time of water in the pipeline. KHIs are also deployed in regions where environmental regulations preclude the use of more toxic thermodynamic inhibitors or ­anti-agglomerant chemicals because typically KHI chemicals are non-toxic. KHI chemicals are usually short polymers or oligomers with carbonyl groups present in the side chains. Some of the early KHI chemical active ingredients like PVP were same as used in shampoos and other non-toxic products. Some details and examples of chemicals are presented further. AA chemicals are similar in their chemical structure to corrosion inhibitors, which can be quite toxic and corrosive themselves, depending on concentration. An example of an AA chemical is a quaternary ammonium salt. AA chemicals work by allowing the hydrates to form, but control the solid surface to keep the solids finely dispersed in a carrier fluid. This makes AA chemicals have no limitation on the time of protection, similar to thermodynamic hydrate inhibitors like methanol but AA do have a limit on the amount of water they can protect from a hydrate blockage. As the formed hydrate solids need to be dispersed into a carrier fluid such as live liquid hydrocarbons produced from a well in order to be transported from the flowline where they form to the processing facility, there is a limitation for AA chemicals on the water cut which can be protected. Typical water cut limit for AA chemical use is between 40 and 50 vol%. Water expands when it transforms into gas hydrate similar to as when it freezes into ice. Actually water expands more when it forms a hydrate. Ice takes approximately 1.11 volumes when 1 volume of water freezes. Hydrate takes between 1.2 and 1.26 volumes, as calculated by the hydrate crystallographic unit cells size for different crystal structures when 1 volume of water forms a gas hydrate. The difference in expansion ratios between ice and hydrate is explained by the volume of gas trapped inside the hydrate crystal lattice. The expanded volume of solids can be dispersed in a liquid hydrocarbon and remain fluid up to 50–60% solids volume which dictates the AA chemical applicability limit of the water cut. There are specialty formulations which increase the limit to 60–70% water cut but these systems are rare. In one instance a formulation was developed by Yale University team led by Prof. Firoozabadi which allows an AA chemical to be effective up to 100% water cut by forming a water-in-oil-in-water dual reverse emulsion. The formed hydrate slurry remains fluid but is understandably very viscous as reported by oil majors who tested this method (Walsh, 2014). The water cut limit for normal operating conditions is verified in a laboratory for a specific oil which will be produced. This step saves operator cost as each crude may contain different amounts of naturally-occurring hydrate dispersant chemicals which may reduce the required AA chemical concentration. Some crudes known as self-inhibited possess a property to naturally disperse forming hydrate particles. This is usually associated with acidic crudes. Studies of the properties of naturally-inhibited crudes indicated that crudes with high TAN number reduced hydrate



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agglomeration. Examples of crudes with naturally occurring inhibiting properties have been reported in the Gulf of Mexico and in the Campos basin of the Atlantic Ocean. The amount of water becomes limiting for the deployment of an AA hydrate inhibitor as the chemical delivery system is typically rated to supply a certain flow rate of the chemical, based on the maximum pressure which a chemical pump can reach. Usually half-inch or 12mm diameter tubes are used to supply chemicals to subsea trees in deepwater application. Other sizes such as quarter inch or 5/8 in. may be used as dictated by project economics. Once the amount of the produced water exceeds the ability of the chemical system to deliver sufficient amount of chemical (between 0.5 and 3 vol% on water basis) the chemical applicability range is exceeded. Operator may respond either by choking back production from a well which produces too much water or by increasing chemical injection up to the pump limit, as dictated by economics of each response. Time does become a limitation for AA chemicals when the threshold water cut is exceeded. In such cases AA may provide a temporary protection from a solid blockage for several hours. It is imperative if a production system experiences a sudden increase in produced water cut, such as water breakthrough in a well either on water injection pressure maintenance or on natural reservoir depletion that such production system is treated upon an eventual shut-in with a secondary risk mitigation method such as methanol injection or bullheading of live produced fluids using stock oil from the gathering flowline into the well to a depth which is warmer than the hydrate stability temperature. If a secondary measure is not implemented after the primary measure fails, a flowline blockage is likely to form. Once the blockage fully forms, the pressure communication between the processing facility and the wellhead tree is lost, and the ability to respond by injecting methanol, stock oil or by depressurizing disappears. The temporary protection time for an AA chemical used outside its normal operating conditions verified in a laboratory depends on few aspects: how quickly water normally dispersed as droplets in hydrocarbons drains from high to low spots thus creating excess water available for hydrate formation, and how quickly hydrate solids grow and agglomerate in the production system undertreated with an AA chemical. Hydrate can grow as rapidly as 1 mm per second in laboratory conditions at gas-water interface with sufficient cooling. In production system the process is limited by both heat transfer (hydrate formation releases heat) and by mass transfer (gas molecules need to diffuse from live oil to water, through a growing layer of hydrate). Hydrate growth in stagnant conditions in cylindrical geometries was investigated in the laboratory (Makogon, 1997). It was shown that hydrate grows more intensively near the pipe wall, likely as a thin capillary channel between hydrate and pipe wall provides a path for water molecules to migrate up toward hydrocarbons thus accelerating the mass transfer, and proximity to the cold pipe wall surface also accelerated the heat transfer. The hypothesis for capillary water migration may be substantiated by the coloring of hydrate with corrosion products in the stainless steel cell where hydrate formed with degassed distilled water. Increased corrosion in stainless materials observed during hydrate formation as shown in Fig. 5.15 was mentioned earlier. • Effect of underinhibition In case of insufficient thermodynamic inhibitor such as glycol or methanol, hydrate will start forming and accumulating in the process stream. Methanol leads to more solid agglomeration, whereas glycol leads to more slushy hydrate which can get displaced from pipeline low spots downstream into pipeline slug catcher when flow rate increases (Dawson, 1999).

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FIG. 5.15  Increased corrosion in stainless steel observed during hydrate formation (Makogon, 1997).

Methanol in small amounts (below 2 wt%) acts as a hydrate growth rate promoter and may act as enhancer for methane and natural gas hydrate. The subcooling required to start hydrate formation is reduced when a small amount of methanol is added to water, at pressures between 50 and 100 bar (Makogon, 1974, 1981). In case of insufficient LDHI, hydrate plug forms more rapidly with too little kinetic inhibitor than without a kinetic inhibitor. With too little antiagglomerant inhibitor formed hydrates agglomerate into a plug. • Inhibitor evaporation to gas Volatile inhibitors (methanol) can evaporate into the gas phase, leaving the water underinhibited. The method to estimate the rate of methanol loss from water to gas is provided by Sloan (1990, 2000) as 1 pound of methanol per MMscf gas for every weight percent of methanol in water phase, at pressures >1000 psi. For more accurate estimates, the following three correlations were offered by Sloan (2000): (mol frac. methanol in gas/mol frac. methanol in water) = exp(8.412–7250/T[°R]) for 1000 psia. (mol frac. methanol in gas/mol frac. methanol in water) = exp(6.852–6432/T[°R]) for 2000 psia. (mol frac. methanol in gas/ mol frac. methanol in water) = exp(5.706–5738/T[°R]) for 3000 psia. For glycol, 0.02 pounds of MEG is lost to gas per MMscf gas, at pressures >1000 psi.



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Pressure management and wellwork safety Combination of salt and glycol or low dosage hydrate inhibitor may be used in wells where pressure management is important. An example is weakly consolidated formations in Western Atlantic deepwater. In cases of very high pressure reservoirs, wells during drilling and completion need to be protected from hydrate formation at the mudline hydrostatic pressure and mudline ambient temperature which is usually +4 °C, sometimes lower. Hydrates are a concern because hydrocarbon fluid may migrate into the openhole wellbore, gas or dense phase hydrocarbon may evolve from reservoir as hydrocarbon density is lower than that of a drilling mud or a wellwork fluid. Gas or dense phase hydrocarbon can rise by buoyancy to the mudline and form a hydrate accumulation at cold temperature leading to stuck equipment. The concentration of salt in wellwork fluid required to prevent hydrate at these conditions can make the brine too heavy, which may make the wellwork fluid overbalanced and cause uncontrolled fracturing of the reservoir. This may lead to uncontrolled release of hydrocarbons from the reservoir through the fractures to the environment. In order to avoid that, the formulation of the wellwork fluids for weakly consolidated formations may combine salts and glycols. Glycol adds less weight than salt to the wellwork fluid, but adds as much hydrate inhibition as salt. It is recommended that hydrate stability of a selected wellwork fluid is measured in the laboratory. This is a relatively simple and fast measurement which allows the driller to know the exact pressure at which hydrate would be stable at seabed temperature. The cost of a lab test to verify hydrate conditions with high salinity high pressure drilling mud or workover fluid system is immeasurably less than that of a deepwater well or of the undesirable consequences. In some cases low dosage hydrate inhibitors lose their effectiveness or get poisoned by other chemical additives present in wellwork fluids. Again the effectiveness of low dosage hydrate inhibitors in wellwork fluids should be verified in a lab. SCSSV safety valve has to be set deeper than the produced fluid hydrate stability depth, using temperature distribution from undisturbed well temperature log. Regional geothermal gradient analog may be used if accurate well log data are unavailable.

Hydrate dissociation Hydrate dissociates when the environment is not sufficient anymore to balance the force of guest molecules' repulsion from water and the attractive force of hydrogen bonds holding water molecules in a lattice around the guest molecules. This occurs when one or more of the three events take place: pressure is reduced, temperature is increased, or water molecules are dissolved into a solvent. The fourth method for a direct removal of guest molecules from the hydrate lattice has not been invented yet. The presence of additives such as kinetic hydrate inhibitors had been shown (Makogon et  al., 2000; Makogon and Holditch, 2001a) to cause a hysteresis in hydrate dissociation, when higher temperature was required to dissociate hydrate formed with KHI. Makogon and Holditch (2001b) reported up to 8.2 °C higher temperature of complete dissociation with 0.5% kinetic inhibitor. The temperature was increased very slowly at 1 °C/day or less. It was hypothesized that KHI molecules adsorbed to the hydrate surface stabilize it like steel bars would stabilize a concrete wall, and also decreased the water vapor pressure above the hydrate.

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Upon dissociation, gas evolves into the water layer present on the hydrate crystal surface as nano-bubbles and micro-bubbles which coalesce into larger gas phase. The importance and pressure of nano-bubbles of dissolved gas for hydrate formation was described by Makogon (1996). The significance of nanobubbles and microbubbles during hydrate dissociation was reported by Uchida et al. (2016a, b, c) who developed acronym MNB or micro- and nano-­ bubbles. They used a transmission electron microscope to confirm the existence of MNB after hydrate dissociation, with most frequently observed size in 200–400 nm range, and Raman spectrometer to estimate the pressure inside the MNB around 7 ± 5 MPa. The authors also described the importance of MNB for the memory effect of gas hydrate recrystallization (Uchida et al., 2016a, b, c). The industrial application of MNB for wastewater purification and physiological promotion was evaluated with respect to NaCl effect (Uchida et al., 2016a, b, c). The authors found that low concentrations of NaCl stabilize MNB for at least 1 week, but at salt concentrations >100 mM the MNB decay faster.

Hydrate blockage remediation The time to dissociate a hydrate blockage depends on the blockage location and on the insulation of the pipeline containing the blockage. As a preliminary estimate, a hydrate plug in an insulated deepwater flowline will take as many days to fully dissociate by depressurization as is the pipe diameter in inches. timedissociation ( days ) ≈ Inside Diameter ( in.) This estimate is based on heat transfer, mass of hydrate and the time it takes for the energy for dissociation to transfer through the flowline insulation as the majority of deepwater flowlines are thermally insulated. An operator should plan for at least this many days for a hydrate removal, plus time for mobilization and demobilization of depressurization equipment. A more accurate analysis for the anticipated time to dissociate a hydrate plug by depressurization can be done with detailed heat transfer analysis. Hydrate may be dissociated in many ways, but the common practice is to depressurize the plugged flowline to a pressure below hydrate stability. Usually the dissociation pressure at the plug location will be below 10 bar in deepwater conditions because structure II hydrate forms most commonly in oil and gas production, and its stability pressure is near 10 bar at the typical deepwater temperature of 4 °C. Initial pressure communication through the plug may start at as early as one tenth of the time of complete dissociation, provided that pressure at the hydrate remains below its stability pressure. Pressure of the hydrostatic head of the liquid column in a deepwater riser must be taken into account when planning a hydrate remediation project. Thermodynamics of hydrate dissociation are described to explain this. Water molecules in a hydrate crystal lattice are held together by hydrogen bonds, just like bricks in a building a held together by mortar. It takes 5 kcal per mol of water to break the hydrogen bonds. Thus the process of hydrate dissociation is endothermic or consuming energy. Energy is required to agitate the bonded water molecules in a hydrate lattice to a point where the hydrogen bonds begin to break. The energy in a deepwater environment comes from the cold seawater. Deepwater flowlines are usually insulated with approximately 3 in. of insulation layer, designed to keep fluids warm during normal produciton. However, during



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hydrate dissociation this insulation limits the heat which can enter the pipeline and dissociate the hydrate. This insulation explains why it takes so long to dissociate hydrate in a subsea flowline. Energy flows from a cold 4 °C seawater into the pipeline because hydrate gets even colder when it dissociates and reaches the equilibrium temperature at the flowline pressure. The dissociation temperature may be lower than the freezing temperature of water. Fresh water is released from a melting gas hydrate. If the dissociation occurs in conditions where ambient temperature is below the freezing temperature of water, the water released from hydrate will freeze as ice and will remain as ice until the ambient conditions warm up above the freezing temperature of water. This should be taken into account in arctic operations and in permafrost regions. A consideration that a hydrate blockage cannot be dissociated in a gas pipeline operated at below freezing conditions was first specified by Makogon in 1961; a partial hydrate blockage may be removed either by heat or by addition of methanol to the gas stream (Makogon, 1961). When hydrate forms, it releases heat and thus limits the rate of hydrate growth. When hydrate melts, it consumes heat and limits the rate of hydrate dissociation. Hydrate dissociation or formation is a phase transition process. It is similar to boiling of water phase transition: temperature will remain fixed until the whole phase transition from liquid to vapor completes. The hydrate melting temperature typically is close to the water freezing temperature. Hydrate takes up energy from the water present in the flowline until water freezes, which depending on salinity occurs between 0 and approx. −6 °C. Chemicals may be used to help dissociate hydrate. Their effectiveness by weight decreases as the molecule size increases. For example, to prevent hydrate at 4 °C and 100 atm it takes around 30 wt% methanol, 45 wt% MEG and 60 wt% TEG (Wood Virtuoso GUTS 6.2 software). However, toxicity and hazardousness decrease as the molecule size increases. Methanol is flammable and poisonous, while TEG is toxic if ingested and may be combustible at high temperature. In each of these inhibitors the active components are the oxygen and hydroxyl groups O and OH. Methanol formula is CH3-OH. MEG or mono-ethyleneglycol formula is HO-CH2CH2-OH and easy to remember as two methanols CH3-OH. TEG or tri-ethyleneglycol formula is HO-CH2CH2-O-CH2CH2-O-CH2CH2-OH and easy to remember as three MEG. Furthermore, the chemicals get diluted and become ineffective as hydrate dissociates and water is released from melting hydrate. In one instance, a hydrate blockage formed in a deepwater dry tree riser remained stable for weeks despite MEG being placed on top of the hydrate plug. After few months of waiting, coiled tubing was deployed to safely jet out the hydrate blockage with a lukewarm KCl brine. Combinations of pressure, chemical and thermal methods as well as points of access to deliver the solutions allow for a multitude of implementation options. Table 5.4 below summarizes over 50 ways to melt a hydrate plug, many of which have been attempted in the past. Some methods are more effective than others and some are more novel than others. Technical feasibility, safety, duration and economics of each option should be considered when ­planning a removal operation. Two-sided depressurization is considered to be safer than other options.

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TABLE 5.4  Methods to dissociate a hydrate plug Depressurize

From upstream of line

With hydrate skid Through service line Through access wye

From downstream

Through topsides With hydrate skid Through service line

Coiled tubing jet

From middle of line

Manifold

From upstream

With hydrate skid

From downstream

Through topsides Through PLET

From middle

Cut, set plug and lift line Riser base PLEM Manifold

Flow chemical

Methanol

From upstream

Through flowline Through service line Through chemical line

From downstream

Through flowline Through service line Through chemical line

Glycol

From upstream

Through flowline Through service line Through chemical line

From downstream

Through flowline Through service line Through chemical line

Brine

From upstream

Through flowline Through service line Through chemical line

From downstream

Through flowline Through service line Through chemical line



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TABLE 5.4  Methods to dissociate a hydrate plug—cont’d Nitrogen

From upstream

Through flowline Through service line Through chemical line

From downstream

Through flowline Through service line Through chemical line

Helium

From upstream

Through flowline Through service line Through chemical line

From downstream

Through flowline Through service line Through chemical line

Heat

Active

Exothermic reaction

Mix reactive fluids Sodium stick in well tubing

Hot medium

Annulus for PIP line Hot water tubing Hot oil

Electric

EH for wet insulation DEH for PIP Heat traced pipe in pipe Welding apparatus Heating lamp

novel

Pressure pulsation

From topsides

Microwave

Deployed via coiled tubing

Comparative economics of hydrate prevention methods There are several industry-accepted methods for design of production systems which prevent hydrate formation. • insulation • active heating • chemical • periodic remediation (onshore vs. offshore) The relative cost of each method varies with time as new technologies become available. Insulation method should be valued for either wet insulation or dry insulation.

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Wet insulation is exposed to ambient elements. Wet insulation has to be more rigid and thus is more thermally conductive and less efficient compared to dry insulation. Wet insulation may be used for multiphase pipeline tiebacks up to 20–30 miles. Wet insulation also is limited by water depth to which it can be deployed depending on type of the material. Wet insulation absorbs moisture from ambient elements with time, and its efficiency may be expected to decrease by 3–5%. Dry insulation is contained in the annulus between two concentric pipes for a pipe-in-pipe configuration. Having two pipes nearly doubles the cost but provides more effective insulation which can be deployed to greater seawater depths. Dry insulation may be effective to tieback lengths of 30–40 miles. For tieback lengths >40 miles actively heated insulated pipes are used. Cost of active heating adds the power generation equipment and platform, cables, subsea transformers, installation costs. Actively heated pipes are used seldom. To-date 36,000. The work by Bbosa et  al. (2017) extends the transport velocity prediction method to non-Newtonian slurry. Multiphase transport models were presented by. King et al., 2001. Al-lababidi et al., 2012. Ibarra et al., 2014. Yan (2010) presents results of sand transport study in multiphase 2, 3 and 4 in. pipes inclined from 0 to 20°. Sand transport in vertical flow has multiple technology areas to rest on such as catalyst fluidized bed models, drill cuttings transport. One of the easier methods to estimate sand transport velocity is to find sand falling velocity in a fluid. Vertical velocity in gas is a free fall velocity with gas resistance and depends on particle drag coefficient and cross-sectional area, and on gas density. V _ particle = ( 2 × mass _ particle × g / ( density _ gas × C _ drag × Area _ particle ) )

0.5

As sand particles are rough and irregularly shaped, C_drag is usually 1.15 or higher at high Re > 100. At low flow velocities the Stokes' solution gives C_drag = 24/Re.



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Sand transport

Stokes equation (1851) for particle settling velocity in a fluid shows dependence on particle diameter D: Ws = D2 × ( density _ particle − density _ fluid ) × g / ( 18 × viscosity ) which is valid where density_fluid × Ws × D/viscosity  1 but it takes time for ions to find each other and combine which is represented as kinetics of the process. For calcium carbonate scale the SR > 1.2 causes scale deposition when water temperature Twater > 100 °C. Under pressure water boils at >100 °C but loses some of its ability to dissolve carbonate ions and ions diffuse in hot water more rapidly. At lower temperature the saturation ratio SR must reach 2–3 for calcite scale to appear. For barium sulphate scale to become an operational issue, both the saturation ratio must be >3 and the scale precipitation amount must be >50 mg/L (Graham et al., 2005; Simpson et al., 2005). Brine instability is also reported as Saturation Index (SI). SI = log 10 ( acation aanion / K solubility product ) When SI > 0 or SR > 1 then aqueous brine is saturated with ions. Various scales precipitate at different SI. For example, calcite precipitation is expected when SI > 1, barite when SI > 0.5. Location of scale deposition usually coincides with the location of precipitation. Rate of scale deposition is usually measured in a laboratory. An approximate correlation may be made between the rate of calcite scale deposition and the saturation index based on results presented by Setta et al. (2012). Calcite Scaledeposition rate ( inches / yr ) = 3.3 × ( Saturation Index − 0.9 ) This correlation is only applicable to calcite because barite uses a different threshold for its saturation index.

Remedial actions Scale remediation methods depend on its composition. Halite scale is water-soluble. Halite scale blockage formed in a North Sea pipeline downstream of a methanol injection port was cleared by water circulation. Carbonate scales are soluble in acids. Mild acids such as citric or acetic as well as strong acids as hydrochloric can be used to dissolve carbonate scale. Calcium sulfate (gypsum) is also soluble in acids such as hydrochloric or sulfuric.



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Solubility of scales in acids usually increases with temperature. Laboratory verification of scale type and selection of the best solvent is required for efficient remediation of formed scale deposits. Barium sulfate scale is insoluble in water or acid and has to be removed by chelant chemical treatment, or by mechanical milling. Scale may be controlled by optimization of operating pressure or temperature to reduce or prevent scale precipitation, or by injection of chemical inhibitors. Scale inhibitors are usually deployed downhole in the deepest chemical injection location. Inhibitors may be deployed as periodic batch treatments via annulus, as continuous treatment via chemical injection tubing, as periodic treatment by squeeze into reservoir rock, and as periodic treatment with solid soluble material placed in well sump.

Scale prevention Scale management aims to mitigate the risk of scale restriction by physical or chemical means. Physical means include avoiding comingling of incompatible fluids from multiple zones. Scale potential should be evaluated based on laboratory measurements of water samples collected under pressure and properly preserved upon depressurization. In absence of water samples from exploration/appraisal wells, one may utilize high pressure water chemistry from analog fields. Technologies which could be considered for management of scale in produced fluids include: • • • •

Scale inhibitor chemical on topsides, at tree, or downhole pressure maintenance to reduce carbonate evolution desulphation of injection water preventing comingling of incompatible fluids.

Note that scale inhibitor chemical deployment downhole may be accomplished continuously by injection via capillary tube, periodically by squeeze into the formation, periodically by soluble pellets in sump, or initially by proppant pellets impregnated with chemical. Some examples of scale inhibitor chemicals include phosphonate, polyacrylic acid, polyvinylsulphonic acid or phosphinopolycarboxylic acid. Following remediation technologies could also be considered as a back-up. • acid or water solvent wash, depending on scale type • coiled tubing to mill out the deposit, especially for a wellbore or a riser for insoluble scales

Interaction of flow assurance issues with and effects on produced fluids and flow The issue of interaction of flow assurance issues is an interesting one, and was brought into a separate section rather than listing the likely interactions individually for each issue.

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The complexity of interactions is potentially as intricate as a game of chess. In chess, there are 32 pieces which may interact at certain conditions. The objective of a game of chess is to foresee these interactions. In flow assurance, the phases and processes are as numerous: Water phase/ice. Gas phase. Hydrocarbon phases and batch flow. Hydraulic performance. Thermal performance. Emulsions. Foam. Subsea or topsides separation. Water treatment. Water or gas injection performance. Hydrate. Wax and gels. Scale. Sand. Sulfur deposition. Naphthenate. Asphaltene. Heavy oil. Viscous oil. Bacterial growth in process systems/reservoir souring. Corrosion. H2S CO2 sour gases. Mercury & organomercury, arsenic selenium/heavy metals. Blockage monitoring/flow monitoring & optimization. Blockage remediation. Subsea and riser considerations. Field layout/wellbore trajectory optimization. Commingled production from various producing zones. Cross-flow between wellbores through manifold. Fracture gradient of injection wells and rock consolidation. Materials erosion properties. It does not mean that an engineer skilled in flow assurance will be good at playing chess. Nonetheless, the complexity of possible interactions and their consequences is not too dissimilar. Fortunately, most fields in development do not possess all of the above issues at the same time. However, some assets like in Paleogene possess many. We will try to outline some of the possible interactions. Hydrate Gas hydrates interaction may come from one or more of the following effects: ‐ Hydrates create a flow restriction; it may alter pressure and temperature distribution in a flowing system leading to changes in stability of other flow assurance phases.



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‐ Mechanical movement; hydrate plugs have been known to move and scrape wax deposit from a pipe wall into a solid wax blockage, which could not be removed by depressurization. ‐ Mechanical expansion; hydrate expands more than ice relative to liquid water upon freezing; hydrate formed downhole has been known to crush well tubing. Mechanical expansion also affects rock consolidation in natural environments as hydrate formation and dissociation over geologic times affected sediment strength. ‐ Hydrate formation introduces solid particles, which may lead to increased erosion-corrosion. ‐ Hydrates are water-based compounds and remove water from produced stream; removal of water may cause other water-dissolved materials to precipitate; It was confirmed experimentally (Hu et al., 2018) that solid halite scale does precipitate out of water solution after hydrate formation consumes some water. It is also hypothesized that chemical inhibitors formulated in water may precipitate out of solution as water molecules are removed into hydrate. ‐ Hydrates consume light hydrocarbons and sour gases. Change in the amount of dissolved methane may affect asphaltene stability; change in CO2 content may affect carbonate scale stability; change in H2S content may affect corrosion. ‐ If dissociated in Arctic or other sub-zero environments by depressurization, hydrate will convert to an ice plug and remain as ice until the warm season; in Arctic subsea with −2 °C seawater temperature time to a warm season may take a while.

Seven suggestions from operations in deepwater and onshore FA is prediction and management of physical and chemical behavior of produced fluids to ensure uninterrupted operation. The following are suggested as seven rules of a successful flow assurance engineer (both multiphase and production chemistry). 1. Keep track of your fluids. Double check what's being injected and whether it's compatible with the fluids and materials in place. Chemical tanks may get re-badged or de-badged en-route or at the blending plant. 2. No inhibitor gives 100%. Even after passing lab tests for one set of fluids, inhibitors may underperform in changed fluids. 3. Displace while you still can. Use a proven method to safe-out systems from hydrate even if another issue (scale etc.) is suspect. 4. All models approximate. A recent comparison across commercial and in-house software packages brought up dissimilarities and gaps in inhibition prediction for brines+MEG. 5. Unplug from downstream. In a short system (a jumper) a solid month-old hydrate blockage was unplugged after methanol was injected in reverse to the original flow.

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5.  Flow restrictions and blockages in operations

6. Establish and update safe limits in labs. Use available labs to periodically verify performance for adequate treatment because fluids change. A pre-deployment lab test of acidic scale dissolver gave optimal contact time. 7. When in doubt read the procedure and err on the side of safety. Cost of lost production and involving additional resources trying to remediate a previouslyformed blockage can outweigh the benefit from operating beyond established safe limits.

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Further reading API Recommended Practice 14E, 1991. Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, fifth ed. American Petroleum Institute.



Further reading

189

Barton, N.A., 2003. Erosion in Elbows in Hydrocarbon Production Systems: Review Document Prepared by TÜV NEL Limited for the Health and Safety Executive, Research Report 115. http://www.hse.gov.uk/research/rrpdf/ rr115.pdf. (Accessed January 19, 2016). Bello, K.O., Idigbe, K.I., 2015. Development of a new drag coefficient model for oil and gas multiphase fluid systems. Nigerian J. Technol. 34 (2), 280–285. Debenedetti, P.G., Sarupria, S., 2009. Hydrate molecular ballet. Science 326 (5956), 1070–1071. DNV, 2015. RP-O501, Managing Sand Production and Erosion. http://rules.dnvgl.com/docs/pdf/dnvgl/RP/201508/DNVGL-RP-O501.pdf. (Accessed January 19, 2016). Firoozabadi, A, 2014 Yale hydrate inhibitor up to 100% water cut. Guner, M., Pereyra, E., Sarica, C., Torres, C., 2015. An experimental study of low liquid loading in inclined pipes from 90° to 45°, SPE-173631-MS. In: SPE Production and Operations Symposium held in Oklahoma City, Oklahoma, USA, 1–5 March. Hatton, G.J., Kruka, V.R., 2002. Hydrate Blockage Formation—Analysis of Werner Bolley Field Test Data, in DeepStar V Project CTR 5209-1. Makogon, T.Y., Johnson, T.L., Angel, K.F., 2003. Successful pigging frequency optimization with field Wax composition data. In: IInd International Applied Statistical Physics Molecular Engineering Conference, 25–29 August, 2003, Puerto Vallarta, Mexico. Makogon, T.Y., Mehta, A.P., Sloan, E.D., 1996. Structure H and structure I hydrate equilibrium data for 2,2-­dimethylbutane with methane and xenon. J. Chem. Eng. Data 41, 315. Makogon Y.F., Trebin F.A., Trofimuk A.A., Cherskiy N.V., Vasiliev V.G., 25 July 1961 priority date, The property of natural gas to form solid gas hydrate deposits in earth crust at certain thermodynamic conditions (temperature up to 295 K, pressure up to 250 bar), USSR National registry of science discoveries No. 75, 1971. NORSOK, 2014. P-002 Process System Design, first ed. NORSOK Standard, 1997. Process Design, P-001, Rev. 3. http://www.standard.no/pagefiles/1130/p-001r3.pdf. (Accessed January 19, 2016). Sloan, E.D., 1998. Clathrate Hydrates of Natural Gases. Marcel Dekker, New York. Thomas, D.G., 1962. Transport characteristics of suspensions. Part VI. Minimum transport velocity for large particle size suspensions in round horizontal pipes. AIChE J. 8 (3), 373–378. Wang, Q., Sarica, C., Chen, T., 2005. An experimental study on mechanics of wax removal in pipeline. J. Energy Resour. Technol. 127 (4). Annual Statistical Review of World Energy, BP, 2018. API PUBL 7103. Management and disposal alternatives for naturally occurring radioactive material (NORM) wastes in oil production and gas plant equipment.

C H A P T E R

6 Production chemistry and fluid quality O U T L I N E Sampling fluids Quality: 4Cs of production chemicals Laboratory verification of chemical performance Pass/fail criteria for hydrate, wax, asphaltene, scale, corrosion chemicals Lab equipment requirements Test procedures Chemical injection systems

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Emulsions, foam, topsides separation, water treatment management

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Naphthenate management Properties of naphthenates

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Heavy oil management

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Viscous oil management

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Mercury management

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Sulfur deposition

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DRA

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Chemical characteristics

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Comparative economics of production chemicals

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Chemical tubing blockage

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Product fluid quality Hydrocarbon oil Hydrocarbon gas Produced water

194 195 195 195

Dosage selection and optimization

200

Chemical data

200

References

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Sampling fluids All containers should be clean from contamination. Containers for live hydrocarbons should be sufficient in size to allow to perform the required flow assurance and production chemistry tests. The sampling program should be coordinated with the flow assurance and production chemistry specialists to determine the required amount of samples.

Handbook of Multiphase Flow Assurance https://doi.org/10.1016/B978-0-12-813062-9.00006-3

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6.  Production chemistry and fluid quality

Water should be sampled without leaving un-filled space for air on top of the sampling bottle. Water should be filled to overflow the bottle and the cap placed on it quickly to limit exposure to air. The water sample should be buffered as early as possible to preserve the dissolved ions. H2S or mercury can adsorb to steel container walls. This adsorption would reduce the quantity of either component in the sample and may give an erroneous measurement indicating that there is no presence of these compounds in the sample. Sampling containers where H2S or mercury are expected to be present due to regional or geologic analogs should have special inside liner coating which would prevent adsorption of either H2S or Hg to the container steel wall. Sampling method recommendations for petroleum fluids are summarized in the API recommended practice 44 (API, 2003).

Quality: 4Cs of production chemicals The production chemicals quality may be described with the following characteristics: • Compatibility Chemicals should be compatible with each other without a significant loss of effectiveness, and with the production system materials such as valve elastomeric seals without degrading or dissolving them. • Consistency (stability) Chemical should remain of the same consistency and fluidity over the range of temperatures and pressures in the production system. Chemicals should retain their consistency for at least 6 months because chemical injection may not occur for and extended time while chemical may remain in the injection tubing at elevated pressure and temperature such as downhole before being injected into the produced fluid. Consistency should also remain at reduced pressure such as vacuum. Chemicals are usually formulated in solvents such as toluene, glycol or methanol. Carrier solvents may be heavier than the live produced fluid. Hydrostatic pressure of the chemical may be higher than of the produced fluid at the injection point. In some cases in deepwater the heavier chemical may fall down the riser portion of the injection tubing and create vacuum condition. In vacuum, the solvent would flash off or evaporate and leave the heavier active components which may lead to plugging the chemical tubing. • Cleanliness Chemical should be clean and filtered because the presence of even minute quantities of solids could plug off the chemical injection valve or port. • Concentration Chemicals should be effective in fairly low concentrations to remain economic and not affect the separation process significantly. Typical dosages of chemicals were shown in Chapter 1. Chemicals are usually injected in 50–500 ppm concentration (0.005–0.05 wt%). Hydrate control chemicals are used in much higher concentrations ranging from 10,000 to 400,000 ppm (1 to 40 wt%). Chemical



Laboratory verification of chemical performance

193

injection at higher dosage may become uneconomic. The operating expenditure for the use of production chemistry may add between $0.1 and $2/bbl lifting cost, depending on the scope and severity of flow assurance and production chemistry issues.

Laboratory verification of chemical performance Pass/fail criteria for hydrate, wax, asphaltene, scale, corrosion chemicals Laboratories are used to ensure the chemical performance alone and in a blend with other chemicals which are planned for injection in a given well or flowline. The criteria for chemical performance are subjective for each company and laboratory and there is no standard metric for these. Joint industry projects developed such criteria but their adoption remains gradual. Some of the chemical performance criteria are suggested below. Hydrate thermodynamic inhibitor has to completely prevent formation of hydrate solids. Hydrate kinetic inhibitor has to completely prevent formation of hydrate for at least the time of residence of fluids in production system at the highest pressure in the system. Hydrate antiagglomerant chemical has to prevent agglomeration of hydrate and its adhesion to an optical window in a pressurized rocking cell, stirred vessel, flow loop or in a rotated wheel. Wax inhibitor has to reduce the mass of wax deposition by at least 50% at the temperature differential between wax appearance temperature and ambient temperature in the planned production system at atmospheric pressure in a cold finger, shear cell or flow loop test or at high pressure (rare shear cell apparatus). Asphaltene inhibitor has to prevent or reduce the amount of precipitated solids. Asphaltene dispersant has to prevent adhesion of flocculated asphaltenes on the test cell walls. Scale inhibitor has to prevent precipitation of solids by retaining the scale-forming cations in test solution in a static bottle test as indicated by their residual concentration. Scale inhibitor has to prevent or reduce deposition of solids in test tubing in a dynamic loop test as indicated by pressure drop across the loop. Corrosion inhibitor has to reduce the rate of metal loss so that penetration rate is below 1 mil (0.001 in.) per year. In some cases rates as high as 4 mpy are considered acceptable, depending on the design life of the system.

Lab equipment requirements Lab equipment should be able to reproduce as closely as possible the pressure and temperature in the production system, and not allow any leaks of test fluids or ambient fluids across the test apparatus boundary. In some cases it is impractical to use pressurized equipment, then atmospheric pressure is used as in emulsion or some scale or wax tests.

Test procedures Test procedures for corrosion are documented by NACE.

194

6.  Production chemistry and fluid quality

Test procedures for some of the scale tests are also available from NACE, but in many cases are developed or updated by companies or laboratories individually. Test procedures for the majority of other flow assurance issues are developed by companies or laboratories individually. Some test standards as ASTM D97 for waxy oil pour point are adopted or modified. Both laboratories and test equipment vendors may recommend the test procedures. Every test procedure should be reviewed by operator company specialists to ensure that it adequately reflects the operating conditions expected in the planned production system.

Chemical injection systems Chemicals are usually deployed through chemical trunkline with branch lines equipped with metering valve systems. Chemicals may also be deployed with point-to-point chemical lines for systems which require high reliability of chemical delivery. Chemicals may be delivered into the lower wellbore with downhole chemical injection, into the upper wellbore with injection above SCSSV or from tree, into the tree, into the jumper with injection from tree or a dedicated line, into the flowline or riser with a dedicated line, and topsides. Chemicals may also be deployed into the reservoir with injection water through a water injection pipeline, into the reservoir with squeeze treatment through a service flowline. Processing equipment may be located on surface (onshore or topsides offshore), subsea (separation, boosting, pumping) or subsurface (downhole separation or homogenizing, or subsea caisson separation). Chemicals may need to be injected into processing equipment by the point-to-point method.

Comparative economics of production chemicals Typical dosages of chemicals in the 50–500 ppm range were shown in Chapter 1. In most cases the initial production starts at elevated chemical dosage to ensure the reliable startup of production. Subsequent periodic reviews of chemical effectiveness and economics may be done to check whether the injected dosage for each chemical is sufficient, too high or too low. This should be done in concert for all chemicals injected at a facility because many chemicals may affect each other's performance. So, an increase of corrosion inhibitor dosage may lead to reduced performance of demulsifier, low dosage hydrate inhibitor and some other chemicals. This may lead to loss in separated water quality and incidents of noncompliance.

Product fluid quality The product of petroleum production includes hydrocarbon oil, hydrocarbon gas and produced water.



Emulsions, foam, topsides separation, water treatment management

195

Hydrocarbon oil Water content specification applies to sales oil. In the USA the crude oil should have a water content under 5000 ppm or 0.5 wt%. Some contracts vary and the water content may be lower at 2000 ppm or higher at 10,000 ppm or 1 wt%. Methanol is soluble up to 1% in crude oil. Methanol content in USA oil is regulated by contract with the receiving refinery. Some refineries cannot process oil with high methanol content. In Russia separation processes may vary, and oil may contain up to 1% water. The maximum salt content of product oil is set to 300 mg/L and is rated into three categories by a state standard. Methanol content in oil is not regulated.

Hydrocarbon gas Gas is expected to have water content below 6–7 pounds per MMScf.

Produced water Water discharge requirements include hydrocarbon content and toxicity. In the US Gulf of Mexico the allowed oil and grease hydrocarbon content limit in produced water averaged over 30 consecutive days is 29 mg/L. The temporary excursion limit is 42 mg/L which allows for slightly-off-spec water discharge. This temporary excursion is allowed only during any 24-h period. Once the limit is exceeded and the regulatory agency notices that, usually in a form of a sheen, usually silvery in color and well seen from aerial vehicle such as a helicopter. The difficulty in obtaining the discharge water specification is that it includes both ­water-insoluble and water-soluble organics. While the former may be separated by regular means as free water knockout, flotation cell and electrostatic treater, the latter may not because organics are dissolved in water. This requires the injection of water clarifier chemicals. The water may also contain hydrocarbons in form of a reverse emulsions. In a reverse emulsion a droplet of water is covered by a shell of hydrocarbon material, which is suspended in bulk water. Reverse demulsifier chemicals (also called water polishers) also help remove hydrocarbons from water. Reverse emulsions and water soluble organics usually manifest themselves in form of a greyish color sheen on water near the discharge point. Toxicity test is performed with shrimp in the water sample and survival rate is monitored over several hours.

Emulsions, foam, topsides separation, water treatment management Emulsions and foams both increase resistance to flow and should be avoided in wells and flowlines. Separation management is complementary to the topsides process design in controlling emulsion or foam formation by physical or chemical means. Physical means include avoiding flow shear or incompatible fluids comingling.

196

6.  Production chemistry and fluid quality

Produced water should be discharged overboard, if regional regulations permit. No commingling of produced water with seawater should be allowed on a regular basis because of compatibility issues and potential for scale deposition. Topsides process design should include: • Chemical injection points to deliver required chemicals • Sampling points to monitor chemical performance and fluid characteristics. Technologies which could be considered in formulating fluid handling concept of flow assurance include the following: • • • • • • • • • •

Emulsion breaker chemical Defoamer chemical Oxygen scavenger chemical Reverse demulsifier water clarifier chemical Hydrocyclone equipment to separate water Vacuum de-aeration equipment Filtration equipment for produced water reinjection Desulphation membranes equipment for pressure maintenance water injection Separator equipment Flotation cell equipment

Note that topsides process technologies should be verified by trials as mutually compatible, for example triazine injected for scavenging H2S from gas may result in scale deposition, corrosion inhibitor can adversely affect emulsion separation, etc. Emulsion breaker and reverse demulsifier chemicals are perhaps the most important chemical category after the corrosion inhibitor because they ensure quality of the product stream. When separation is inefficient, it may leave hydrocarbons, both regular organics and water-soluble organics in water. Disposal of produced water stream with off-specification residual components in it may lead to either plugging of the produced water reinjection wells or to sheen on seawater if water is discharged overboard. In USA, the BOEM regularly monitors the performance of production facilities separation and issues warnings of non-compliance if they observe it or shut-in the facility. The data on the incidents of non-compliance (INC) are publicly available and may serve as the lagging indicator of which operator needs help with their production chemistry operation. Periodic reviews of chemical effectiveness discussed above may serve as the leading indicator of production chemistry performance. The up to date reports of INC for USA operators (BOEM, 2019) are in www.data.boem.gov/Company/INCs/Default.aspx. The number of both warnings and shut-ins shown in Figs. 6.1 and 6.2 have both been on a decreasing trend in the past. It may be a coincidence that there is a peak in non-­compliance with water quality specification, which is 29 ppm hydrocarbons in discharged water or 42 ppm momentary excursions, for a 30 day average and daily maximum, respectively, in the year when petroleum commodity price was low. The method required to monitor hydrocarbon compounds in produced water is the Federal EPA Method 1664 (2010). This regulatory compliance method is a weight-based method which relies on solvent extraction of oil and grease hydrocarbons with hexane followed by solvent evaporation and weight analysis of the residue.



197

Naphthenate management

BOEM INC warnings per facility 5.00 4.50 4.00 3.50 3.00 2.50 2.00 1.50 1.00 0.50 0.00 2011

2012

2013

2014

2015

2016

2017

2016

2017

FIG. 6.1  BOEM warnings per facility between 2012 and 2016.

BOEM INC component shut-in per facility 2.00 1.80 1.60 1.40 1.20 1.00 0.80 0.60 0.40 0.20 0.00 2011

2012

2013

2014

2015

FIG. 6.2  BOEM component shut-ins per facility between 2012 and 2016.

Naphthenate management Calcium naphthenate is one of the concerns in production chemistry which may plug production systems and process equipment. Naphthenate precipitates when naphthenic acid reacts with metal ions such as calcium or sodium.

Properties of naphthenates Naphthenate density ranges between water and oil densities. Naphthenates may collect at oil-water interface and behave as surfactants by stabilizing emulsions.

198

6.  Production chemistry and fluid quality

Calcium naphthenate is a calcium soap of naphthenic acids in crude oil, and appears as a light brown gel. Sodium naphthenate looks like white gel or clear dark brown liquid. Sodium naphthenate behaves as an emulsifier and as a mild detergent. Naphthenic acids molecular weight ranges from 120 to over 700 g/mol. Naphthenic acids may be present in immature heavy oils. Paraffinic crudes usually have low acid content. Naphthenate potential can be evaluated with laboratory measurements of oil and water samples collected under pressure and properly preserved as needed upon depressurization. ARN-acid is the naphthenate of concern for the calcium naphthenate issue. The naphthenate potential is analyzed based on the total acid number (TAN), the CO2 content in the reservoir oil and bicarbonate ion HCO3− in reservoir brine. Total acid number can be determined by thermometric titration. Naphthenate restriction may be controlled by chemical or physical means. Physical means include avoiding incompatible fluids commingling, if it is practical to have segregation with a sliding sleeve completion or having separate wells and flowlines for different incompatible reservoirs. Technologies which could be considered for management of naphthenates in produced fluids include: • • • •

Naphthenate inhibitor chemical Preventing exposure of oil to calcium-rich water Acetic acid chemical Selection of a different emulsion breaker chemical to remedy separation threats

Heavy oil management Heavy oil increases the backpressure on reservoir which reduces production by high density. Technologies which could be considered for management of heavy oil in produced fluids include: • Artificial lift • Preliminary water knock-out or subsea water separation • Multiphase pumping.

Viscous oil management Viscous oils increase the backpressure on reservoir which reduces production by high viscosity. In some countries the oil is considered to be viscous when its viscosity at reservoir conditions exceeds 200 cP. Technologies which could be considered for management of viscous oil in produced fluids include: • Multiphase pumping • Drag reducing agent chemical

DRA

199

• Active heating • Emulsion breaker chemical to reduce emulsion viscosity • Emulsifier chemical to form water-external emulsion.

Mercury management Mercury content in produced fluids affects the environment and personal health through discharge streams such as de-oiled filtered produced water. Mercury also can accelerate corrosion of metals such as aluminum and cause integrity issues in process equipment components made of aluminum. Mercury in produced fluids is usually associated with production in North Sea and regions near continental rim such as Northern Australia or Indonesia. Mercury management aims to reduce the mercury impact on health, safety and environment and material integrity. Technologies which could be considered for management of mercury in produced fluids include: • Mercury removal from gas unit including recommended location and technology • Mercury monitoring system including sample locations and appropriate equipment Materials in production systems containing mercury should avoid aluminum, brass, nickel alloys as suitable for the expected mercury level.

Sulfur deposition Sulfur may be carried from reservoir in gas phase. As pressure and temperature in wellbore change, sulfur may deposit in well tubing. Sulfur deposition depends on both temperature and pressure. Elemental sulfur solubility in gas decreases very roughly tenfold for every 25 °C or for every 100 bar.

DRA Drag reducing agents are long polymeric chains which help reduce turbulence at the pipe wall by affecting turbulent eddy size and reducing fluid drag on pipe wall. Being long chains, the DRA chemicals suffer from shear degradation when long molecules get sheared and broken by the flow. The location of DRA chemical injection should be downstream of any equipment which causes high shear such as valves, chokes, etc. to avoid chemical degradation. Typical dosage of DRA chemicals is described in Chapter 1.

200

6.  Production chemistry and fluid quality

Chemical characteristics Chemicals may be formulated in carrier solvents such as methanol, toluene, glycol or water. Concentration of active components usually varies from 10% to 40%. Bulk properties of chemicals such as density, viscosity, vapor pressure and resistance to flashing off of solvent mainly depend on the properties of the carrier solvent. Some characteristics of chemicals are available in literature, which may be used for a preliminary hydraulic design of the chemical injection system. A more robust process is to get the chemical characteristics including density, viscosity and vapor pressure as function of both temperature and pressure from the potential chemical suppliers at an early stage of project design, after the scope of potential flow assurance issues is understood based on appraisal well samples or regional analogs.

Chemical tubing blockage Vapor pressure of a chemical is an important characteristic because vacuum can occur at top of chemical injection lines causing flashing off of solvent and deposition of active ingredient in the chemical tubing, leading to its plugging. Plugged chemical tubing may be remediated with solvent circulation if there is flow communication through the blockage, or using a pressure pulsation blockage removal method. Chemical tubing may also be blocked with flow assurance solids such as hydrates when pressure in the chemical tubing is less than in the production system. Such difference in pressures may occur when production is shut in, and chemical is less dense than the produced fluids. Untreated or undertreated produced fluid may migrate across the check valve(s) as all valves have some leakage, and form a blockage in the chemical tubing. An example of a hydrate blockage inside methanol tubing was discussed earlier in Chapter 1.

Dosage selection and optimization Dosage selection is performed with account to potential loss of chemical effectiveness when other chemicals are injected, and to project economics. Chemicals performance is tested at several concentrations both without and with other chemicals, and the lowest concentration which is sufficiently effective is selected.

Chemical data • Density of MEG is shown in Fig. 6.3 • Viscosity of MEG is shown in Fig. 6.4 Table  6.1 shows estimated properties of production chemicals at atmospheric pressure and room temperature. Note that viscosity and density will increase at higher pressure and lower temperature; data should be obtained from chemical vendors.



Chemical data

FIG. 6.3  MEG specific gravity (relative to water density at 60 °F) (updated from Union Carbide, 1978)

201

202

6.  Production chemistry and fluid quality

FIG. 6.4  MEG viscosity (updated from Union Carbide, 1978).

References 203

TABLE 6.1  Chemical properties Chemical

Viscosity, cP

Density, kg/m3

Asphaltene inhibitor or dispersant

35

910

Corrosion inhibitor

100

960

Defoamer

10

950

Emulsion breaker

100

930

Glycol (MEG)

35

1110

H2S scavenger (triazine)

20

1120

LDHI chemical (AA)

15

800

Methanol

1

790

Naphthenate dispersant/acetic acid

200

1050

Scale inhibitor

30

1020

Wax inhibitor or pour point depressant

100

880

References API, 2003. Sampling petroleum reservoir fluids. In: American Petroleum Institute Recommended Practice 44, second ed. April. BOEM, 2019. www.data.boem.gov/Company/INCs/Default.aspx. (Accessed January 1, 2019). EPA, 2010. Method 1664, Revision B: n-Hexane Extractable Material (HEM; Oil and Grease) and Silica Gel Treated n-Hexane Extractable Material (SGT-HEM; Non-polar Material) by Extraction and Gravimetry, February. United States Office of Water Environmental Protection Agency (4303). Union Carbide, 1978. Glycols.

C H A P T E R

7 Flow assurance deliverability issues O U T L I N E Flowline design process

205

Optimization of flowline sizes

206

Artificial lifting

206

Topsides equipment and arrival pressures

207

Cold flow and emulsion Heavy oil viscosity Emulsion rheology

207 208 208

References

209

Further reading

209

Flowline design process Flowline design is in the realm of pipeline engineers, but is done in collaboration with flow assurance specialists. The flow assurance analysis helps indicate whether the pipe is sufficiently large or too large for the life of the project and whether flow is likely to be stable or intermittent. Flow assurance also helps forecast the amount of liquids arriving into the process equipment at various stages of the project life. Pipeline sizing considerations are usually based on two boundary conditions: pressure and velocity. Pressure in a pipeline should not to exceed the pipe design pressure. Usually the MAOP is set with a safety margin of between few bar and up to 10% lower than the design pressure, to allow for pressure surges during transient flow events such as production startup or shutdown. Velocity in a pipeline should not exceed the erosional velocity. Maximum velocity is determined based on operator internal design considerations for erosion, fluid corrosivity, or on recommended guidelines provided by API, DNV or NORSOK. Regional regulatory requirements may prescribe which method to use for the flow velocity considerations. In some cases, velocity should not drop below a certain minimum threshold to ensure produced solids such as sand are transported by the flow. Typical minimum liquid v ­ elocity

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© 2019 Elsevier Inc. All rights reserved.

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7.  Flow assurance deliverability issues

expected to transport sand in a near-horizontal pipe is 1 m/s. This value may differ at ­various operator companies. In some production systems operating in stratified multiphase flow regime, the chemical inhibitors are injected and are carried in the liquid phase. Sufficient gas flow velocity is required to entrain liquid droplets and wet the perimeter of the flowline so that all parts of the production system are treated with the injected chemicals. The minimum gas flow velocity consideration is important when top of the line corrosion (TOLC) is expected to be an issue. In multiphase flow with stratified flow regime, as flowing produced fluid cools down, water may condense from the gas stream and accumulate as droplets on top of the flow line. Freshly condensed water has no inhibitor chemicals in it. This brings the concerns of corrosion and hydrate formation. Corrosion risk may be mitigated by maintaining gas velocity above the minimum value. Hydrate risk may be mitigated by injection of a volatile hydrate inhibitor such as methanol. It should be noted that methanol may absorb oxygen from air if kept in a storage tank without a gas blanketing system. Oxygen thus brought into the system with methanol may increase the rate of corrosion. Routing of flowlines should avoid significant elevation changes. It may be more profitable to increase the line length in order to keep the line mostly flat rather than build it straight over a mountain or through a canyon. Analysis of the relative cost of extending the flowline length should be performed together with the flowline size and flow rate optimization to find the relative impact of a hill or canyon crossing on the backpressure and delivery of wells over the life of field.

Optimization of flowline sizes Flowline sizes may be optimized to provide target flow rates over the life of field. Larger diameter pipelines result in lower pressure drop, but also cost more. In multiphase flow the liquids accumulation as holdup in low and uphill sections of oversized lines also acts as a hydraulic restriction and increases pressure drop. Flow assurance can develop a flow performance analysis, correlating both pressure drop and liquid holdup with the flow rate and flowline size. There is expected to be a flowline size when pressure drop and holdup are low. This size is optimal for the operation as it would reduce the back pressure and increase production from wells over the life of field, and reduce liquid surge into process equipment.

Artificial lifting Artificial lift design is in the realm of production engineers, but should be done in collaboration with flow assurance specialists (Table 7.1). When reservoir pressure is or becomes low, there are several methods which allow to add or to periodically accumulate the energy in order to lift heavier liquids from reservoir to surface. Some of the artificial lift methods are listed in the table below. Absence of moving parts should improve equipment reliability.



207

Cold flow and emulsion

TABLE 7.1  Artificial lift methods categorized by energy introduction, application location and presence of moving parts Artificial lift method

Add or accumulate energy to flow Application

Moving parts

Gas lift

Add

Well

No

Plunger lift

Accumulate

Well

Yes

Velocity string

Accumulate

Well

No

ESP

Add

Well

Yes

Progressive Cavity Pump

Add

Well

Yes

Jet pump

Add

Well or flowline

No

Swabbing

Add

Well

Yes

Multiphase pump

Add

Flowline

Yes

Topsides equipment and arrival pressures Topside equipment should be rated to the pressures expected at the wellhead. In cases of high pressure high temperature (HPHT) reservoirs, the shut-in wellhead pressure may be significantly higher than the flowing wellhead pressure and the process equipment pressure rating. In such field development designs the high integrity pressure protection system (HIPPS) with fast-acting valves (can go from fully open to fully closed in approximately 3 s) may be installed to protect the equipment from pressure. A certain length of reinforced pipe rated to the maximum wellhead pressure, usually less than 1000 m long is installed downstream of HIPPS valves. The remainder of the pipe and process equipment may be rated to a lower pressure to reduce capital cost. Flow assurance can develop a fast transient flow performance analysis to estimate the maximum pressure observed downstream of the HIPPS valve while it closes. The fast transient HIPPS analysis can help ensure that the length of a reinforced pipe is sufficient to contain the produced fluid pressure during the time while the well stops and the HIPPS system actuates.

Cold flow and emulsion Cold flow is a technology concept which has been evaluated between 10 and 20 years ago. The premise of cold flow is to eliminate the use of the highest dosage and costly hydrate control chemicals by routing of the production fluids so as to induce precipitation of solids in a controlled way that said solids would not plug the production system. This may be accomplished by recycling some of the production fluids cooled to ambient temperature back to the vicinity of the wellhead. The cooled produced fluid would already contain small crystals of gas hydrate and paraffin wax. Injection of the recycle stream at the wellhead would serve to provide crystal seeds on which wax and hydrate would grow from the well stream fluid, instead of on the pipe wall. The method had been validated and demonstrated to work in a pilot scale equipment in Tiller, Norway (Argo et al., 2004).

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7.  Flow assurance deliverability issues

Another cold flow design is static mixer. The static mixer design has been validated in the field (Turner and Talley, 2008) to control the hydrate formation and to keep hydrates dispersed and flowing. None of the cold flow methods have been implemented for continuous field use due to novelty and lack of historic performance. Operators are not yet certain whether either cold flow technique can deliver 100% reliability over the life of field. Cold flow technology may be useful where the use of chemicals is restricted by local regulation.

Heavy oil viscosity Heavy oils provide increased resistance to flow not only by being heavy but also by having higher viscosity. Over 20 methods are available in literature for estimating oil viscosity. These methods have been summarized by Bergman and Sutton (2007) who correlated dead oil viscosity with temperature and density based on 9837 viscosity measurements from 3047 fluids which ranged in API gravity from 0.45° to 135.9°. The Bergman and Sutton correlation was discussed earlier in Chapter 3. A recent correlation for estimating the viscosity of heavy oil in mixtures with water has been presented by Wen et al. (2016). The method proposed by Wen may be used together with the correlation provided by Bergman and Sutton (2007).

Emulsion rheology Oil and water emulsion may be more viscous than just oil by a factor of 10 or more. Several correlations for emulsion viscosity had been developed including Smith & Arnold, Woelflin Loose, Woelflin Medium and Woelflin Tight. Emulsions may exhibit peak viscosity around 50–85% water cut. The inversion point from oil-external to water-external emulsion depends on the character of the crude, the character of the brine, and the degree of emulsification. The inversion points corresponds to maximum viscosity (Fig. 7.1). Emulsion Viscosity

Effective Emulsion Viscosity, cP

100,000

10,000

1000 Smith & Arnold Woelflin Loose Woelflin Medium Woelflin Tight

100 0.0

0.1

0.2

0.3

0.4 Water Cut

FIG. 7.1  Effective emulsion viscosity correlations comparison.

0.5

0.6

0.7

0.8



Further reading

209

References Argo, C.B., Bolavaram, P., Hjarbo, K.W., Makogon, T.Y., Oza, N., Wolden, M., Lund, A., Larsen, R., 2004. Method and System for Transporting Flows of Fluid Hydrocarbons Containing Wax, Asphaltenes, and/or Other Precipitating Solids. (WO2004059178). Bergman, D.F., Sutton, R.P., 2007. A consistent and accurate dead-oil-viscosity method, SPE110194. In: SPE Annual Technical Conference and Exhibition (Anaheim, 11–14 November). Turner, D.J., Talley, L.D., 2008. Hydrate inhibition via cold flow—no chemicals or insulation. In: 6th International Conference on Gas Hydrates, Vancouver, July 6–10. Wen, J., Zhang, J., Wei, M., 2016. Effective viscosity prediction of crude oil-water mixtures with high water fraction. J. Pet. Sci. Eng. 147, 760–770.

Further reading Bradley, H.B., 1987. Petroleum Engineering Handbook. Society of Petroleum Engineers, Richardson, TX (Chapter 19). Woelflin, W., 1942. The viscosity of crude-oil emulsions. In: Drill. and Prod. Prac., API, pp. 148–153.

C H A P T E R

8 Flow assurance stability issues O U T L I N E Severe slugging Phenomena description Prediction methods Suppression techniques

211 211 212 213

Transient operation Shut-in and start-up Rate ramp-up and ramp-down

213 213 214

Slugging in gathering lines

214

Calculation of slug impact force on Tees and Elbows

214

Calculation of pressure surge on sudden flow shut-in 215 Vacuum condition in flow

216

References

216

Further reading

216

Severe slugging Phenomena description The issue of severe slugging has several impacts on production system. Periodic slugging causes mechanical integrity issues as slugs of liquid impact on bends of the flow lines. Slug of a large volume may cause a production facility shutdown if it overfills the separator capacity. Slug flow also causes periodic increase of backpressure on wells which reduces the overall production rate and may lead to lower ultimate recovery of hydrocarbons from the reservoir. A detailed description of severe slugging issues is provided by Hill and Wood (1994). The authors provide the correlations for slug frequency, average and maximum possible slug length and discuss the design of slugging systems. The authors report the “best fit” average slug frequency correlation as:

( Fs D / Vm ) ∗ (1 − 0.05 VSG ) D0.3 = −24.729 + 0.00766 exp ( 9.91209∗ Hle∗ (1 − 0.068 / VSL ) ) + 24.721 exp ( 0.20524∗ Hle∗ (1 − 0.068 / VSL ) ) ∗

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© 2019 Elsevier Inc. All rights reserved.

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8.  Flow assurance stability issues

Fs = slug frequency per hour; D = pipe diameter, m; Vm = mixture velocity, m/s; VSG = superficial gas velocity, m/s; Hle = equilibrium stratified liquid holdup; VSL = superficial liquid velocity, m/s.

Prediction methods Flow regime map Flow regime map is plotted in coordinates of superficial liquid velocity vs. superficial gas velocity, on a log-log scale. A flow regime map would be expected to have the following form (Fig. 8.1). Stability limits Multiple additional works on severe slugging are available in the literature such as Montgomery (2002). The author indicates that severe slugging causes a 20% drop in production, and results in separator trips/shutdowns. The stability criterion proposed by the author: U GL S ≤ U GB S∗ ( 1 − g εLP L P sin θ ( ρL − ρG ) / ( PS + ρL g h R ) ) UGLS = inlet gas velocity. UGBS = gas velocity entering the riser base, m/s. g = gravity acceleration, m/s2. εLP = pipeline liquid holdup, calculated using Taitel (1986) method. LP = downhill pipe length upstream of the lowest point. θ = inclination from horizontal at riser base downstream of the riser lowest point. PS = separator pressure. ρL = liquid density. ρG = gas density. hR = riser height.

FIG. 8.1.  Typical multiphase flow regime map.



Transient operation

213

The author indicates the stability criterion is that in order to prevent a bubble penetrating the riser base, the inlet gas velocity must be lower than some critical gas velocity, which depends on the ratio of the hydrostatic head in the pipeline and riser. The Boe criterion for the occurrence of severe slugging is commonly used in the industry. The Boe criterion provides an estimate of the minimum liquid velocity at which pressure increase due to liquid accumulation in vertical part of the multiphase flow system is higher than pressure increase due to gas compression in horizontal part of the system. U L S ≥ PP U G S / ( ρL g ( 1 − εL ) L sin α ) ULS = liquid superficial velocity. PP = pipe pressure. UGS = gas superficial velocity. ρL = liquid density. g = gravity acceleration. εL = pipeline or tubing liquid holdup. L = length of downhill pipe upstream of the lowest point. α = inclination of pipe upstream of the lowest point.

Boe estimated the holdup based on no-slip condition: ε L = U L S / ( U L S + U G S ) The Boe criterion is a straight line in ULS vs. UGS coordinates. Unstable flow is at values above the line. Additional work which provides stability criterion on horizontal-vertical flow systems includes Zakarian (2000). Author developed a stability criterion and validated it with laboratory analysis.

Suppression techniques Slug mitigation options (Montgomery, 2002) include: gas lift, choke control and separation. Choke control, separator pressure and gas lift are named as slug mitigation options in (Sancho, 2015). The author also provides a severe slug classification into four categories. A novel method for slug suppression by dividing large liquid slugs into smaller parts which would be more easily accommodated by the separator was proposed (Makogon et al., 2011) which was discussed in Chapter 4.

Transient operation Shut-in and start-up On production shut-in, liquids redistribute according to gravity in the production system. This affects the cooldown of the produced fluids. Water tends to retain more heat. As water drains to and accumulates in the low spots, this may provide additional time before hydrates begin to form. However, system insulation is usually designed to provide sufficient cooldown time in the gas-filled sections of the flowline. Gas has the least heat capacity of the produced fluids. Sections of flowline filled with gas cool down the fastest. Typical insulation

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thickness in subsea flowlines is 3 in., which provides sufficient time for the operator to take preventive action to manage the risk of flow assurance blockages in the system. Startup of production is a transient operation which can cause a surge of liquids settled in the low spots of the production system to arrive in the separator and stop the production if separator is not sufficiently large to hold the arrived liquids. Transient multiphase simulation tools are available to estimate the volume of liquid surge at different well ramp-up rates during a start-up.

Rate ramp-up and ramp-down Production operator may increase or decrease wells' production rate according to the field development plan. During a flow rate ramp-up an event similar to a liquid surge during start-up may be expected. Higher flow rate sweeps liquid holdup accumulated in the flow line; the liquid travels to the separator and temporarily increases the liquid rate. During a flow ramp-down, less liquid is expected to be produced to the process facilities. At lower flow rate more liquid will accumulate in the flow line.

Slugging in gathering lines Gathering lines carrying multiphase fluids may also experience slugging when slugs originate in a wellbore as the well starts to be loaded with liquids. Choke opening or artificial lift methods may be used to reduce the liquid loading in wells and slugging in the gathering lines. Lowering production tubing into the Boycott range may also help stabilize wells production and extend well life. If no method works to mitigate the slugging, then flowline restraints or bracing for the flowlines should be used as recommended by Hill and Wood (1994) to help with the loads on the pipework.

Calculation of slug impact force on Tees and Elbows Slugs traveling at high velocity through a production flow line carry a substantial momentum M and impact the pipe locations with change in direction with a significant force. Slugs are known to have knocked flow lines off their support stands and caused significant (greater than 1 pipe diameter) movement. Slugging has led to loss of integrity as in-field pipelines made of fiber epoxy got disconnected from the Tee at the location of slug impacts. Liquid slug is pushed through a flow line by gas. Liquid slug travels at nearly the velocity of gas which pushes the slug like a piston. A simplified correlation for slug length based on pipe diameter was proposed in Chapter 4. L [ ft ] = (D [ inch ])2



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The force of slug impact may be calculated if one knows slug density, gas velocity, pipe size and angle of the pipe bend. Force of slug impact on a bend may be estimated as: F = ∆Μ / ∆t = ρ V 2 A ( 2 − 2 cos θ )

0.5

ρ = liquid slug density, kg/m3. V = gas or slug velocity, m/s. A = pipe cross section area, m2. θ = bend angle. M = momentum, kg m/s. t = time, s. Time may be estimated based on slug velocity and slug length. The calculated force value should be multiplied with a suitable dynamic load factor (DLF). A DLF of 2.0 is commonly used. Experimental data on slug forces at pipe bends from several researchers was presented and summarized in the works of Hou et al. (2014) and Tay and Thorpe (2015).

Calculation of pressure surge on sudden flow shut-in Flowing mass of liquid carries a substantial momentum. When flow path becomes suddenly blocked, a pressure is expected to increase. Transient single phase flow simulators are commonly used to estimate the pressure change during such event. A simple albeit somewhat conservative method to calculate pressure surge is based on Joukowski. ∆P = ρ C ∆V ΔP = change in pressure, Pa. ρ = density of flowing fluid, kg/m3. c = speed of sound in fluid at operating pressure and temperature, m/s. ΔV = change in flow velocity, m/s. c = (K*/ρ)0.5. K* = K/(1 + D K/(e E)). D = pipe diameter, m. e = wall thickness, m. E = wall elasticity modulus, Pa = kg/(ms2). K = fluid bulk modulus, Pa = kg/(ms2). Some values for materials commonly used in production systems are shown below. ESTEEL = 200 * 109 Pa. EFIBERGLASS = 17 * 109 Pa. EHDPE = 0.8 * 109 Pa. KWATER = 2.15 * 109 Pa. KOIL = 1.7 * 109 Pa. KGLYCOL + WATER = 3.4 * 109 Pa.

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Vacuum condition in flow Vacuum condition and pressure surge may occur during stock oil flow. In oil export pipelines going through mountainous terrain, or in deepwater during displacement of the flowline live oil with stock oil there may be a vacuum condition at the highest point of the flow system. If pressure at a pipeline pumping station downstream of a mountain or at the bottom of the flowline riser is lower than hydrostatic head pressure for stock oil, vacuum may occur at the crest of the mountain or at the riser top. Vacuum condition has to be taken into account for design of flexible lines and flexible parts and materials on topsides system. Vacuum can also occur at top of chemical injection lines causing flashing off of solvent and deposition of active ingredient in the chemical tubing. Higher than normal flowing pressure or deadheading may occur during start-up of stock oil flow to move the stationary fluids in the pipeline or in the flowline such as during dead oil displacement.

References Hill, T.J., Wood, D.G., 1994. Slug flow: occurrence, consequences and prediction. In: SPE 27960, University of Tulsa Centennial Petroleum Engineering Symposium, Tulsa, 29–31 August. Hou, D.Q., Tijsseling, A.S., Bozkus, Z., 2014. Dynamic force on an elbow caused by a traveling liquid slug. J. Press. Vessel. Technol. 136. Makogon, T.Y., Estanga, D., Sarica, C., 2011. A new passive technique for severe slugging attenuation. In: 15th Multiphase Production Technology Conference, Cannes, France, 15–17 June. Montgomery, J.A., 2002. Severe Slugging and Unstable Flows in an S-Shaped Riser. PhD. Thesis, Cranfield University. Sancho, A.M., 2015. Severe Slugging in Pipelines. Master Sc. Thesis, Instituto Superior Tecnico, Lisboa. Taitel, Y., 1986. Stability of severe slugging. Int. J. Multiphase Flow 12 (2), 203–217. Tay, B.L., Thorpe, R.B., 2015. Statistical analysis of the hydrodynamic forces acting on pipe bends in gas–liquid slug flow and their relation to fatigue. Chem. Eng. Res. Des. 104, 457–471. Zakarian, E., 2000. Analysis of two-phase flow instabilities in pipe-riser system. In: Proceedings PVP2000, ASME Pressure Vessels and Piping Conference, July 23–27, Seattle.

Further reading Boe, A., 1981. Severe Slugging Characteristics, Part I, Flow Regime for Severe Slugging, Presented at Special Topics in Two-Phase Flow, Trondheim, Norway. Joukowsky, N., 1898. “Über den hydraulischen Stoss in Wasserleitungsröhren.” (“On the hydraulic hammer in water supply pipes.”). Mémoires de l'Académie Impériale des Sciences de St.-Pétersbourg (1900), Series 8 9 (5), 1–71. (in German); Sections presented to the Division of Physical Sciences of O.L.E., 26 September 1897, to the PhysicalMathematical Commission of the Society, 30 January 1898, to the Polytechnic Society of the Moscow Imperial Institute, 21 February 1898; complete paper to the Russian Technical Society, 24 April 1898, to the PhysicalMathematical Division of the Academy of Sciences, 13 May 1898. Also: Жуковский, Н.Е. (1899). “О гидравлическом ударе в водопроводных трубах.” (“On hydraulic hammer in water mains.”), Proc., 4th Russian Water Pipes Congress, pp. 78–173, printed in Moscow (1901), April 1899, Odessa, Russia.

C H A P T E R

9 Flow assurance integrity issues O U T L I N E Corrosion Introduction Types of corrosion Corrosion monitoring methods Currently used corrosion control techniques

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Erosion

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Corrosion Introduction Besides mechanical impacts on pipe walls and process equipment by liquid slugs and moving flow assurance plug projectiles, the production system also experiences chemical degradation by corrosion. Corrosion management is the domain of corrosion engineers. Corrosion system design should be done in collaboration with flow assurance specialists. Numerous flow parameters which are used to estimate the rate of corrosion can be derived from flow assurance analysis, including: multiphase flow regime, liquid and gas flow velocities and densities, liquid and gas pressure and temperature, rate of liquid droplets entrainment by gas flow, location and rate of water condensation from gas, location and composition of water holdup, shear stress exerted by gas or liquid flow on the pipe wall, flow velocities at the chemical injection quill locations, locations of solid deposits.

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Types of corrosion A large amount of NACE literature on corrosion exists. General details on corrosion are available (Fontana 1975; Dillon 1982). Two key categories of corrosion are: physico-chemical corrosion. microbially influenced corrosion. Some of the common types of physico-chemical corrosion include: Uniform—caused by electrochemical reaction leading to dissolution of metal; Galvanic—may occur due dissimilar weld material and pipe material; Pitting—localized corrosion enhanced by localized difference in ion concentration; Crevice—when a gap between pipe wall and another material such as flow assurance deposit creates a localized difference in ion concentration; Intergranular—when metallurgy has dissimilar grains of metal present; Stress corrosion cracking—due presence of chloride ions released from fluid. May occur in stainless steels such as chemical injection systems or sour service systems (Fischer et al., 2016). Hydrogen embrittlement—may occur due hydrogen evolution in the system and ingress into metals due to its small molecule size. Microbially influenced corrosion (MIC) affects the rate of corrosion processes due to a biofilm formation on a surface of pipe. MIC may occur in crude pipelines near the locations of water holdup in low spots, which relates the MIC to flow assurance hydraulic analysis. A recent overview of MIC in petroleum systems is provided by Al-Saleh et al. (2011).

Corrosion monitoring methods There are several methods in the operations to monitor corrosion rate listed: Weight loss coupons. Electrical resistance probes. Linear polarization resistance (LPR). Field signature method (FSM). Electrochemical noise. Flexible UT Mats. Ultrasonic pipe thickness measurement. ILI in-line inspection with magnetic flux leakage intelligent scraper tool. Radioactive methods. Indirect monitoring may also be done by Ultrasonic sand detection. Process stream analysis. Corrosion monitoring can provide data for tuning of the integrated multiphase flow and corrosion models. An overview summary of corrosion monitoring methods is available in Hedges and Bodington (2004).

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Currently used corrosion control techniques Corrosion prevention is accomplished by several methods simultaneously: use of corrosion inhibitor chemicals, use of maintenance scraping to remove water holdup from the pipelines, use of corrosion-resistant materials. Corrosion inhibitor chemicals are among the most widely used methods of corrosion methods. Chemicals performance is evaluated in laboratory by tests and in field by in-line inspection. Lab methods aim to measure: Inhibitor efficiency; Inhibitor partitioning behavior between hydrocarbon and water; Compatibility with other production chemicals; Film stability and persistence; Optimum concentration. Inhibitor efficiency may be measured with: Bubble test apparatus; Rotating electrode, including rotating disk (laminar flow) and rotating cylinder (turbulent flow, high shear); Jet impingement test; Recirculating flow loop, which allows to make tests at a controlled shear stress; In-line inspection (ILI) uses magnetic flux leakage probes installed circumferentially on a ILI tool which records wall thickness along the whole perimeter and length of the tested pipe.

Integrated models Multiphase flow models can be combined with corrosion rate models to provide an integrated assessment of the expected corrosion rates for a given flow scenario. There are commercial tools available which allow to estimate corrosion rate. Alternatively it is possible to find multiphase flow parameters and then use these in the corrosion rate prediction model. Commercial multiphase flow simulators have modules of published corrosion models such as NORSOK M-506, deWaard-95 and Top-Of-the-LineCorrosion (Wang and Nesic, 2003). The first two are for CO2 based corrosion, and the TOLC is for condensed fresh water corrosion. The use of these built-in modules for corrosion rate assessment may be limited if corrosion engineers at operator companies develop and maintain in-house corrosion rate prediction models. The limitation for the use of multiphase tools’ corrosion modules for corrosion rate prediction is the limited ability to tune the model input parameters. It may be useful as an initial check of the corrosion rate. Nonetheless, multiphase flow modeling tools are very useful and indispensable in analyzing the two parameters which are required by the corrosion specialists: thermal conditions of flowing fluids and shear rates exerted by fluids on pipe wall. Both of these are parameters used in the in-house models. Temperature determines both the corrosive species’ diffusion and corrosion reaction rate and the condensation rate of fresh water. Shear affects the corrosion inhibitor layer and the protective corrosion product layer. Some operators, to derive the desired shear and temperature distribution, as well as flow regime, attempt to couple the in-house corrosion rate

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correlations with multiphase flow models such as point or drift flux slip, with varying success. The uncertainty in corrosion rate prediction keeps the ILI inspection service companies in demand. In some instances, best available in-house models for US-based and UK-based integrated operators underpredicted the corrosion rate in deepwater dense fluid production and in onshore sour service production. Other companies deploy artificial intelligence to fit measured rates to corrosion models. Comparison of which flow parameters (calculated with a commercial multiphase flow simulator) have the most impact showed that holdup and inside heat transfer were top (Liao et al., 2012).

Erosion Besides mechanical degradation of pipe wall surface, erosion by impingement of liquid droplets or solids such as sand or hydrates affects the integrity of the protective corrosion inhibitor film or of a corrosion product layer formed on a passivated pipe wall. This may lead to localized pitting corrosion.

References Al-Saleh, M.A., Sanders, P.F., Ibrahim, T.M., Sorensen, K.B., Lundgaard, T., Juhler, S., 2011. Microbially influenced corrosion assessment in crude oil pipelines. In: NACE-11227, Corrosion-2011, 13–17 March, Houston. Dillon, C.P. (Ed.), 1982. Forms of Corrosion, Recognition and Prevention. Vol. 7. NACE. Fischer, D., Li, C., Huang, W., Sun, W., 2016. Investigation of the sulfide stress cracking and stress corrosion cracking behaviors of duplex and lean duplex stainless steel parent and welded materials in sour service. In: NACE-20167325, Corrosion 2016, 6–10 March, Vancouver. Fontana, M.G., 1975. The Eight Forms of Corrosion, Process Industries Corrosion. NACE, pp. 1–39. Hedges, W., Bodington, A., 2004. A comparison of monitoring techniques for improved erosion control: a field study. In: NACE-04355, Corrosion 2004, 28 March-1 April, New Orleans. Liao, K., Yao, Q., Wu, X., Jia, W., 2012. A numerical corrosion rate prediction method for direct assessment of wet gas gathering pipelines internal corrosion. Energies 5, 3892–3907. Wang, S., Nesic, S., 2003. On coupling CO2 corrosion and multiphase flow models. In: Paper 03631, Corrosion 2003, NACE International.

C H A P T E R

10 Research methods in flow assurance O U T L I N E Hydrate stability and crystal growth Importance of studying gas hydrates Gas hydrates as an industrial hazard Hydrates as an environmental buffer for holding Ch4, Co2 Industrial applications for gas hydrates Hydrates as a source of hydrocarbon fuel Properties and structures of gas hydrates Thermodynamics of hydrate formation Kinetics of hydrate formation Phase transitions in gas hydrates Methane hydrate experiments Xenon sI and xenon + neohexane sH hydrate experiments Evaluation of experimental results Evaluation of the biomolecular computer studies

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Molecular modeling Comparison of chemical performance on a solid surface Computer study of hydrate inhibition mechanism

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Docking of macromolecules on hydrate and ice Studying of kinetic inhibitor interaction with water: solvation of the polymer in the bulk water Summary of computer modeling Summary of the experimental and computer model work

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Experimental and computer study of the effect of kinetic inhibitors on clathrate hydrates Crystallographic information about hydrates Hydrate crystal growth Inhibition of hydrate formation Computer modeling of hydrates: solid solution models Potential models Structures of liquid water and hydrate Thermodynamic properties Translational and vibrational spectra Stability of gas hydrates Early modeling of hydrate growth Inhibition of hydrate growth Research objectives

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Experimental study of hydrate crystal growth Morphology of hydrate crystals Effect of adding kinetic hydrate inhibitors on the morphology of growing hydrate Effect of NaCL salt on THF hydrates THF + water + inhibitors solution with NaCL salt Growth rate measurements Computer modeling of interaction between a hydrate surface and an inhibitor Organization of this section Early modeling of clathrate hydrates at CSM Studies of monomers adsorption on hydrate with cerius2 Using the hand-written software for studying interaction of water and monomers Adsorption of inhibitor polymers on hydrate Using the computer to design inhibitors

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Summary of simulations Summary from the adsorption simulation results Conclusions about kinetic inhibition mechanism Recommendations

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Flow loop tests

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Bench scale tests Paraffin cold fingers Paraffin cross-polarized microscope CPM Rheology DSC Raman spectroscopy

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Computer code Program for generating radial distribution function in water Program for h bonded rings count in water Monte carlo program for polymer adsorption on hydrate

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References

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Further reading

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Hydrate stability and crystal growth This section describes measurement of thermodynamic equilibria for methane sI hydrate formation, which were measured in a temperature interval of 190–262 K. No structural hydrate phase transition occurred in the studied region. Methane hydrate remained as structure I. Thermodynamic equilibria of xenon sI hydrate and xenon + neohexane sH hydrate formation were studied. The temperature interval was from 228 to 288 K for sI hydrate and from 233 to 288 K for sH hydrate. A quintuple point sH-sI-Lw-Lh-V was determined to be at 281.5 K.

Importance of studying gas hydrates Gas hydrates are inclusion crystalline compounds. Hydrates may form when a mixture of water and gas molecules is subjected to specific temperature and pressure. Usually, the pressure of gas hydrate formation is high (above 10 psi) and temperature is low (below 50 °F). Temperature and pressure of hydrate formation may be dependent or independent variables, depending on the number of components and phases in system. Gas hydrates have an increasingly important place in the oil and gas industry. They may serve in the future as the principal source of hydrocarbon fuel. One of the estimates suggests that gas hydrate deposits worldwide are about 2 × 1016 m3 or 7 × 105 Tcf. This is roughly two times the amount of carbon in all other known fossil fuel deposits.



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Currently, gas hydrates are considered to be an industrial nuisance. Hydrate plugs forming in the pipelines prevent the normal operation of gas and oil production facilities. To date the worldwide expenditures on hydrate prevention through methanol injection into the pipeline are over $150,000,000 (Long et al., 1994).

Gas hydrates as an industrial hazard The normal operating conditions during oil and gas production establish the thermodynamic conditions favorable for hydrate formation. Gas is transported from the well at high pressure. Water coming from the production well is also present in the pipeline. When the temperature of the pressurized gas-water mixture falls below the equilibrium value, thermodynamic conditions are established for gas hydrate to form. Formation of hydrate consumes gas and water present in the pipeline. Bulk of the forming hydrate eventually adheres to the pipeline walls and narrows the flow channel. This results in the further pressure increase in the pipeline in front of the hydrate and accelerates growth of hydrate on the wall of pipeline. With time hydrate plugs the pipeline and stops its normal operation. Usually, after the hydrate formation pressure in the pipeline is lowered below equilibrium pressure and hydrate is allowed to dissociate into gas and water. Sometimes, however, the hydrate plugging of the pipeline may result in serious damage to the producing facilities and cause a disaster. Such was the case at the Piper Alpha oil rig in the North Sea (Cullen, 1990). The explosion at that platform had happened on 6 July 1988. It caused the death of 167 persons, injury and trauma to many of the survivors, and destruction of the platform. The economic estimate (Lovegrove, 1990) was that the British Government will have lost $2.8 billion in revenues. Cost of the platform for Occidental Petroleum (Caledonia) LTD which operated the platform was $0.5 billion. The investigation on the accident had shown that one possible cause of the explosion was plugging of the condensate pump with gas hydrates and the following gas leak. Finally, gas hydrates within the foundation sediments of deep water offshore structures may present a hazard to the foundation of pipelines and other production facilities (Makogon, 1988).

Hydrates as an environmental buffer for holding CH4, CO2 Interest on environmental aspects of gas hydrates is mostly related to the greenhouse effect of methane and carbon dioxide. These gases may form hydrates at conditions existing on earth. Greenhouse gases are transparent to the infrared solar radiation on its way to earth. They absorb the energy of this radiation after it reflected from the earth surface. This causes the temperature increase in the atmosphere. Atmospheric temperature affects the stability of methane and natural gas hydrates located widely on earth. More methane is released into the atmosphere as hydrate decomposes. Hypothetically, this may result in a runaway global warming (Fig. 10.1). Methane has a greenhouse effect which is 21 time stronger than that of carbon dioxide (Englezos, 1993a). Several scenarios of global warming were proposed. The annual atmospheric temperature increase ranged from 0.006 °C/year to 0.08 °C/year for the catastrophic scenario (Englezos, 1993b). Industrial development has been accompanied by a release of greenhouse gases into the atmosphere. Atmospheric temperature increase during the past century is attributed to artificial activity. Electric power plants are among the most active sites releasing CO2, another important greenhouse gas.

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Runaway. Methane hydrate decomposition Temperature increases

Release of a greenhouse gas.

More hydrate decomposition.

Enhancement of global warming.

FIG. 10.1  Scenario of a runaway global warming.

It was noticed, however, that similar fluctuations of atmospheric temperature are not uncommon in past years. Large amounts of greenhouse gases were and are released into the atmosphere during volcanic eruptions. It should also be noticed that, to date nature had the ability to equilibrate the conditions on earth. Another approach is to treat gas hydrates as an environmental buffer for storing excess greenhouse gases. When the gas concentration in atmosphere reaches a certain value, formation of gas hydrate becomes more favorable than its further decomposition. Such mechanism allows the atmosphere to store the excess of greenhouse gas in form of hydrate (Fig. 10.2).

Industrial applications for gas hydrates Many applications for gas hydrates were described earlier (Makogon, 1981, 1985; John, 1993). These applications are based on the change of properties of hydrate formers in hydrate state. The specific volume of water increases by 26–32% during formation of gas hydrate and only by 9% during freezing (Makogon, 1985), while the specific volume of gas changes by several orders of magnitude. This permits the storage of large amounts of natural gas in the hydrate state. Gas molecules are packed much closer together in hydrate than in gaseous state. Pressure of gas can be increased by passing it through a hydrate state and decomposing the gas hydrate in a limited volume. Only molecules of a particular size may form gas hydrate. Also various compounds require different thermodynamic conditions in order to form hydrate. Separation techniques may be based on these properties of gas hydrate. Water enrichment with D2O may utilize the fact that heavier isotopes of water form hydrate easier than the lighter ones (Makogon, 1985).



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Methane hydrate decomposition Tempertature increases

Release of a greenhouse gas.

No runaway.

Increase of methane concentration in atmosphere.

Formation of methane hydrate to remove excess gas from atmosphere.

FIG. 10.2  Schematic of greenhouse effect damping with hydrate.

Hydrate may be used as a heat accumulator. The hydrate formation is accompanied with release of energy on the order of 400 kJ/kg (Makogon, 1985). In the reverse direction, to dissociate a hydrate one has to introduce the same amount of heat. Electric conductivity of hydrate is lower than that of the initial solution. The sound velocity in hydrate is higher by 60–100% than that in gas saturated rock (Makogon, 1985). These properties of hydrate provide the effective means for surveying gas hydrate deposits. Gas hydrates may be applied in biotechnology. Modification of activity of enzymes encapsulated in reverse micelles may be done through pressure manipulations (John, 1993). Formation of gas hydrates in the water-in-oil microemulsions or reversed micelles leads to removal of intramicellar water and a consequent decrease in micelle size. Gas hydrate can be used as a means of disposal of carbon dioxide. Power plants generate CO2 and excessive amounts of this gas may increase the greenhouse effect. It is estimated that the contribution of carbon dioxide has reached 71% of all greenhouse gases (Tomisaka et al., 1990). A hypothesis is being developed (Aya et al., 1991) that carbon dioxide expelled into deep water (below 2750 m) will form a hydrate under high hydrostatic pressure. CO2 hydrate is denser that the sea water and it will settle on the bottom of the ocean (Fig. 10.3). Assumption of stability of sea conditions has been made (Fig. 10.4).

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CO2 tanker

more than 3000 m.

CO2 discharge pipe

FIG. 10.3  Conceptual view of CO2 disposal at ocean bottom.

Hydrates as a source of hydrocarbon fuel Hydrates of natural gas are widely spread around the globe. The techniques of gas extraction from hydrate already exist (Makogon, 1981) and are being improved. Locations of hydrates are found in all continents in the world. It can be seen that hydrates are often encountered in offshore regions as well as onshore. Gas hydrates store a tremendous amount of gas. Over 170 volumes of gas at standard temperature and pressure may be enclathrated by water. Fig. 10.4 demonstrates that the amount of gas in gas hydrate is sufficient to support its own combustion while melting the hydrate crystal. Natural gas hydrates are a potential source of fuel for the future. One of the most recent illustrations of the influence of natural hydrates on the environment may be viewed in the several unexplained vertical near-cylindrical caverns or craters of approx. 100 ft in size which have suddenly appeared in area of northern Russia called Yamal (Fig.  10.5). Makogon and Makogon (in Riazi 2016, p.429) hypothesize that this may have been brought about by warming of the upper lithological permafrost cover thus destabilizing gas hydrate deposit trapped under the icy permafrost cover, which is impermeable to gas. As permafrost temperature remained below ice freezing but above hydrate stability, gas released from a hydrate lens deposit accumulated under the permafrost cover. Pressure of the gas released from hydrate built up until it equaled the geostatic overburden pressure of the permafrost cap still frozen and impermeable and led to a pneumatic explosion. Gas would escape to the atmosphere and the soil and still stable ice from permafrost would form edges of crater or fall to the bottom of the crater. The lower estimate of the amount of gas released from hydrate may be easily calculated from measuring the depth and diameter of the vertical near-­ cylindrical crater by equating the pressure exerted by overburden permafrost soil column



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FIG. 10.4  Burning methane hydrate (U.S. Geological Survey, 2016).

of typical density to the pressure exerted from below the overburden by gas released from a hydrate lens deposit of similar diameter by warming in a confined volume. Gas would be released as temperature exceeds equilibrium. Geothermal profile of temperature for permafrost areas may be found in the literature. The upper estimate of the amount of gas released may be higher as the hydrate deposit could be thicker and the remainder of hydrate could dissociate without overburden pressure stabilizing it. Hydrate content in lenses is usually high, up to 100% hydrate so using the volume of gas released from hydrate of 164 m3 methane /m3 hydrate is not unreasonable. Satellite measurements at time of the craters’ appearance have

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c­ onfirmed spikes of methane content in atmosphere over the area coinciding with approximate time of the event, substantiating this hypothesis. Unexplained ice also has been found by explorers at the bottom of the several noticed craters, further substantiating this hypothesis because hydrate dissociation is endothermic, and upon dissociation at atmospheric pressure water released from hydrate would convert to ice. Warming of the atmosphere may gradually bring more dissociation of some portion of the natural gas hydrate deposits existing onshore which are estimated at 3% of the global hydrate amount releasing methane and setting off a chain reaction. Eventual warming of the oceans may similarly destabilize, with time, some of the oceanic sediment natural gas hydrate, estimated at 97% of the global hydrate amount. However, if other natural phenomena such as methane solubility in seawater plays a role, the process would eventually over geologic times balance out. Makogon et al. (1972) showed that at T and P corresponding to the hydrate equilibrium, the solubility of methane in water decreases abruptly, by a factor of 3 to 5. Makogon et al. (2004) confirmed these data and showed that at a pressure of 75 bar the solubility of methane in water changes from 4 cm3/g without hydrate to 0.22 cm3/g above hydrate. This difference in concentrations of methane in water creates the driving force for methane diffusion from the atmosphere into the hydrate. Based on gas solubility without hydrate, seawater can dissolve 4 cm3 methane / gram water. Estimating global ocean at 1.34 × 109 km3 = 1.34 × 1024 g, and global reserve of gas in natural hydrate deposits at 1.5 × 1016 m3 = 1.5 × 1022 cm3, then 0.28% of the ocean can dissolve all gas released from all the natural hydrate. Nonetheless, dynamics of gas dissolution may be slow and depend on pressure and temperature. While the above estimate is encouraging that the ocean can dissolve the methane from hydrate, more detailed research is needed to confirm the rate of methane dissolution in the ocean because global ocean temperatures vary laterally and with depth.

Properties and structures of gas hydrates A gas hydrate is a crystalline compound in which water molecules enclathrate one or more types of guest molecules. Such inclusion compounds are formed when the appropriate thermobaric conditions were applied to the gas-water system. An extensive review of common types of hydrate crystals and their properties is available (Sloan, 1990). Also a list of the more rare hydrate structures was presented by Dyadin et al. (1991). Hydrate crystalline structures are composed of guest and water molecules. Water molecules arrange themselves in polyhedra encapsulating the guest molecules. Oxygen atoms of water molecules are positioned in the vertices of such polyhedra (Fig. 10.6). Such polyhedra or cavities share faces to form the crystalline lattice. Different combinations of cavities produce different hydrate structures (Fig. 10.7). Geometric properties of hydrate crystals are presented in Table 10.1. Most often in nature hydrates of cubic structure I (sI), (Fig. 10.8) and cubic structure II (sII), (Fig. 10.9) are formed. These two hydrate structures are formed with three types of cavities: 512, 51262, and 51264. These numbers represent the types of faces and numbers of these faces forming a cavity. Thus, 512 represents twelve pentagonal faces forming a dodecahedron. Cubic structure (sI) hydrate is formed when 512 and 51262 cavities come together. sI hydrate may be formed with molecules ranging in size from methane (0.436 nm diameter) to triethylene oxide (0.61 nm diameter).



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FIG. 10.5  Yamal crater (Yamal, 2015). Photo by Prof. Bogoyavlenski; reproduced with permission.

FIG. 10.6  Water molecules enclathrating the methane guest molecule and forming a 512 cavity. Dashed lines represent hydrogen bonds.

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10.  Research methods in flow assurance

FIG. 10.7  Schematic of sI and sII hydrates formation.

Cubic structure (sII) hydrate is formed when 512 and 51264 cavities arrange themselves in a lattice. sII hydrate may be formed with molecules ranging in size from argon (0.38 nm diameter) to isobutane (0.65 nm diameter). Hexagonal structure hydrate (sH) was discovered recently (Ripmeester et al., 1987). This hydrate is composed of the three types of cavities: 512, 435663, and 51268, forming a lattice shown in Fig. 10.10. Sizes of molecules which may participate in sH hydrate range from that of argon (0.38 nm diameter) to hydrogen sulfide (0.46 nm) and from the size of cyclohexane (0.75 nm) to that of methylcyclohexane (0.86 nm diameter). Any molecule that is of the abovementioned size or smaller may be a simple or binary hydrate former. The exception to this statement are the molecules with a size smaller than argon. These very small molecules can't form hydrate because they cannot stay in the cavity formed



231

Hydrate stability and crystal growth

TABLE 10.1  Geometry of hydrate structures. Hydrate crystal structure

I

II 5

5 6

5

435663

51268

2

6

16

8

3

2

1

0.391

0.433

0.3902

0.4683

0.391

0.406

0.571

Effective free diameter, nm

0.51–0.52

0.57

0.48–0.50

0.69

–

–

–

Number of water molecules per unit cell

46

136

34

Space group

Pm3n

Fd3m

P6/mmm

Crystal system

cubic

cubic

Hexagonal

Lattice parameter, nm

1.2

1.71

a = 1.22; c = 1.02

5

Number of cavities per unit cell Average cavity radius, nm a

12 2

12

H

5 6

Cavity type

12

12 4

a

From Istomin et al. (1988), assuming the van der Waals radius of water being equal 0.14 nm.

FIG. 10.8  Stereoscopic view of sI. Obtained with Hyperchem® software.

FIG. 10.9  Stereoscopic view of sII. Obtained with Hyperchem® software.

12

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10.  Research methods in flow assurance

y x

framework viewed along [001] FIG. 10.10  Stereoscopic view of sH. Source: Meier, W. M., Olson, D. H. 1987. Atlas of Zeolite Structure Types. 2nd revised ed. London: Butterworth.

by water. Small size allows these molecules to escape from the cavity. And in case the small guest molecule prefers to stay inside, it will not provide sufficient support to the surrounding water molecules and the cavity will collapse. Hydrates may form from pure components as well as from the mixtures of hydrate formers. Structure I and II hydrates may form with pure gases. Examples may be methane forming structure I hydrate and nitrogen forming structure II hydrate. However, structures I and II may be formed with mixtures of gases as well. Structure H hydrate must be formed with a mixture of components. The variation in size of sH hydrate is so large that the hydrate cavities cannot be stabilized by guest molecules of one size. Not every cavity is occupied in hydrate by a guest molecules. In order for the hydrate to be stable the occupancy of the hydrate lattice must be high. For this requirement to be met it is necessary to have sufficient availability of the guest molecules of appropriate size. In case of structure II hydrate there should be enough methane molecules to fit into the small 512 cavities and propane molecules to stabilize the large 51264 cavities. Gas hydrates may change their structure depending on thermodynamic conditions and composition of hydrate former. The van der Waals and Platteeuw (1959) statistical thermodynamics model is most frequently used in fitting and in predicting the equilibrium conditions of hydrates formation. A recent use of the model by Lundgaard and Mollerup (1992) suggested an unusual prediction of the phase diagrams of methane hydrates, obtained via minimization of the Gibbs free energy of the system. One of the predictions of Lundgaard and Mollerup was that a slight mismeasurement of the unit crystal cubic side (by as little as 0.002 nm in 1.2 nm) could cause a structural transition (I to II) on the three phase (I-H-V) hydrate equilibrium line at a temperature of 170 K. Such a transition would not be unique because cyclopropane and trimethylene oxide have the ability to form either structure I or II hydrates, depending on thermodynamic conditions. The simple hydrates of cyclopropane were shown to undergo structural transition in the temperature range of 257.1–274.6 K based on data by Hafemann and Miller (1969) and Majid et al. (1969). Hydrates of trimethylene oxide undergo phase transition between 252.4 and 260.1 K as determined by Hawkins and Davidson (1966). Several other works (e.g., Holder and Hand (1982), Adisasmito and Sloan Jr. (1992), etc.) provided experimental evidence for structure I - structure II transition for hydrates of natural gas mixtures at temperatures above the ice point. However, for gas mixtures, the phase transition occurs as a principal function of gas composition.



Hydrate stability and crystal growth

233

Thermodynamics of hydrate formation Hydrate formation without inhibitors The phase equilibria of gas hydrates are of the most industrial and academic interest. Thermodynamic conditions at which hydrates form from pure water are usually described by a pressure-temperature diagram. An univariant curve describes the equilibrium for hydrate formation from binary mixture water-hydrate former. The univariant curve is prescribed by the Gibbs's phase rule: 2+C = F+P

(10.1)

where C = number of components, F = number of degrees of freedom, P = number of phases. The three phase line (V, Lw, H) for Structure I hydrate of methane will serve as an example: 2 + 2 ( methane + water ) = 1 + 3 ( vapor + hydrate + liquid )

(10.2)

This gives only one degree of freedom for hydrate formation equilibrium. A large amount of hydrate equilibrium data for natural gases was compiled by Sloan (1990). He analyzed the sI and sII hydrate equilibria for pure hydrate formers and their multicomponent guest mixtures. Data for sH hydrate of methane and adamantane was reported by Lederhos et al. (1992). Data for other hydrate structures have not been reported in the recent literature. Usually, as temperature of the system goes down, a lower pressure is required to form gas hydrate. This can be shown from the Clausius-Clapeyron equation. d ( ln P ) / d ( 1 / T ) = −∆ d H / ( ZR ) . where ΔdH is the enthalpy of hydrate dissociation. Hydrate consumes heat on dissociation and ΔdH is greater than zero. Thus the slope of ln P against 1/T is negative. This also can be explained from an entropic viewpoint. At lower temperature water molecules vibrate less and become more ordered. The entropy of the system decreases. According to the equation: G = U + PV − T S,

(10.3)

if the volume stays constant and temperature decreases, then the pressure must also decrease in the closed system (U = const) at equilibrium (G = const). Hydrate formation with inhibitors There are four basic methods of prevention of hydrate formation. These include removal of water from the system, raising the system temperature above equilibrium, decreasing the system pressure below equilibrium, and introduction of an inhibitor. Thermodynamic inhibitors such as alcohols or glycols are widely used in gas and oil industry to prevent hydrate formation. When an inhibitor is added to the gas-water system, lower pressure is required to form hydrate compared to a system without an inhibitor, at the fixed temperature. Makogon (1981, p. 133) reported that, “With an increase in concentration of alcohols in water, a breakdown is observed in the structural organization of water and in the clathrate-­ forming aggregates. As a result, the probability of hydrate formation is reduced”. This observation suggests that the thermodynamic inhibitors change the structure of water away from that favoring hydrate formation as a part of their effect. A result from a neutron diffraction study (Soper and Finney, 1993) of a 1:9 M ratio methanol-water mixture concludes that the

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HH pair correlation function doesn't change much from that for the pure water. This work also showed the experimental evidence that water molecules form a disordered hydrogen bonded cage around the methanol molecule. The water structure can be described not only by the pair correlation function but also by the structure of hydrogen bonded network in water. No difference can be seen for the pair correlation function of pure water and water + hydrate inhibitor solution. The changes in hydrogen bonded network of aqueous inhibitor solution were significant compared to pure water. Formation of the hydrogen bonded cage around the inhibitor monomers was also noticed in computer simulation. Phase equilibria data for hydrate formation with inhibitors is available in the literature. Sloan (1990) reviewed the data for pure hydrate forming natural gases and their mixtures. There has been some contradiction in the literature on the effect of hydrate equilibrium with low concentrations of alcohol. Makogon (1981, p. 134) and Berecz and Balla-Achs (1983, p. 102) reported that at concentrations below approximately 5 wt% of methanol in water the onset of hydrate formation can occur at a higher temperature, thus reducing the subcooling required to start hydrate formation. A hypothesis was suggested by Makogon (1981) that this may happen due to inclusion of the methyl CH3 radical in voids in the structure of water. It was also reported later (Svartas and Fadnes, 1992) that methanol inhibited the hydrate formation over the whole range of concentrations. Only a few data points in this work, which indicated the opposite effect, were related to an experimental error. Another interesting concept discussed in the literature is whether methanol molecules can or cannot participate in the hydrate structure. NMR and dielectric study of ethylene oxide and tetrahydrofuran hydrates was performed (Davidson et  al., 1981). The results show no sign of enclathration of methanol. The opposite was suggested by computer studies performed on water-methane-methanol mixtures (Wallqvist, 1992) at 270 K. He made a simulation of a single unit cell of sI methane hydrate with a varying number of methane molecules substituted by methanol molecules. He reported that small amounts of methanol can be incorporated into the hydrate structure. A 4 wt% methanol solution hydrate was reported to be stable, whereas a 7 wt% solution hydrate melted. Experimental evidence for the formation of a solvation shell of water molecules around methanol molecules is drawn from a neutron diffraction study (Soper and Finney, 1993) of a 1:9 M ratio methanol-water mixture.

Kinetics of hydrate formation Studying the kinetics of hydrate formation allows one to determine two attributes of hydrate formation. One is how soon hydrate will start forming (induction time) since the system was placed in appropriate thermodynamic conditions. The other attribute is the growth rate at which liquid water or ice will be converted into a solid hydrate. Interest in this area of hydrate research has previously been purely academic. Today industry is seeking the new chemicals which allow operation of a gas-water system at conditions where hydrate would normally form, so that it stays in a metastable state without aggregating to a large hydrate mass. Experimental data for kinetics of hydrate formation are available in the literature for temperatures above and below the ice point. Falabella (1975) studied the formation of hydrates of different gases and mixtures of gases at low sub-zero temperatures. The work on kinetics of hydrate formation have been reviewed (Sloan, 1990).



Hydrate stability and crystal growth

235

Rates of linear hydrate growth may reach up to 103 nm/s as reported by Makogon (1974, p. 74). This allows one to estimate the time required to orient one layer of water molecules into hydrate lattice. Taking the size of water molecule as its van der Waals diameter of 0.29 nm, it takes 290 μs for water molecules to position themselves from bulk water into the crystalline structure. This scale of time is about 10 times larger than time scale of usual computer simulations in regular computers using distributed processing or GPUs with CUDA or similar parallel coding and achievable in supercomputers. This indicates that, most likely, kinetics of hydrate formation will be studied experimentally and using computer molecular modeling in the near future. In experimental work kinetics of gas hydrate formation may be affected by many different factors. Among these are: (a) Subcooling, or lowering the system temperature below the equilibrium value for a given pressure. Different shapes of hydrate crystals were obtained by Makogon (1981, pp. 88–100) depending on the amount of subcooling. (b) Overpressurizaton, or increase of the system pressure above its equilibrium value for a set temperature. This is another measure of subcooling. (c) Rate of cooling, or gradient of temperature decrease of the system in time. (d) Stirring rate. Effect of turbulence in the hydrate system on kinetics of crystallization, the crystal size distribution and the duration of the induction period was described by Englezos et al. (1987). (e) Previous temperature of water available for hydrate formation. This effect was studied by Makogon (1981, pp. 63–72). (f) Presence of the sites for hydrate nucleation like steel walls of the reactor or pipeline, or particles of silica or bentonite. (g) Preliminary saturation of water with hydrate forming gas. Dissolution of gas in water is a diffusion process if no mixing were applied to the system. Rate of gas dissolution may be monitored and subtracted from total gas consumption during the experiment. Kinetics of hydrate formation is strongly affected by so- called kinetic inhibitors. The mechanism of kinetic inhibition is by adsorption to hydrate nuclei and by sterically blocking guest molecules from reaching the hydrate surface. Kinetic inhibitors are usually polymeric molecules of high molecular weight having the ability to hydrogen bond with water. • Comparison of chemical performance on a crystal solid surface and laboratory methods

Phase transitions in gas hydrates For a single guest component hydrate, a solid phase transition can be indicated by a sharp change of slope in the three-phase, univariant pressure-temperature equilibrium line shown as a discontinuity in a plot of d(ln P) against d(1/T). This slope change is due to the change in the enthalpy of hydrate formation, ΔdH, determined by the Clausius-Clapeyron equation applied to a univariant system. d ( ln P ) / d ( 1 / T ) = ∆ d H / ( ZR )

(10.4)

The univariant Clausius-Clapeyron equation is given in the above equation where P and T are absolute pressure and temperature of hydrate equilibrium with vapor and ice, ΔdH is the enthalpy of dissociation of hydrates to ice and vapor, Z is the compressibility of the gas, and

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R is the universal gas constant. If ΔdH/Z were constant over the temperature range, a plot of ln P against 1/T would be linear within a single structure. On the other hand, a non-linear plot might indicate either a hydrate crystal structure change, or a variable ΔdH/Z.

Methane hydrate experiments Data in the literature for methane hydrate Experimental equilibrium data for methane hydrate formation below the ice point were available from multiple sources: Deaton and Frost Jr. (1946) at 273 to 262.4 K, Roberts et al. (1940) at 259.1 K, and Falabella (1975) at 148.8 to 193.2 K. However these data sets did not cover the temperature range 193–259 K. Linear fits for the available semilogarithmic data sets at temperature above and below 210 K are shown in Fig.  10.11. Fitted lines intersect at an angle which suggested a transition between structures I and II. Such phase transition was suggested in the work by Lundgaard and Mollerup (1992). The paucity of measurements in the temperature range of 193–259 K suggested an experiment to determine whether this transition might occur.

FIG.  10.11  Methane hydrates equilibrium data. □—data by Falabella (1975). △—data by Deaton and Frost Jr. (1946).



Hydrate stability and crystal growth

237

FIG. 10.12  Schematic of the apparatus.

Experimental equipment and procedure for methane hydrate A schematic of the experimental equipment is given in Fig. 10.12. The apparatus was built around a stainless steel spherical cell of 5.08 cm internal diameter rated for 10.1 MPa. The cell was filled with 150 stainless steel balls of 0.31 cm diameter, needed for surface renewal. A Thermolyne orbital shaker with 0.4 cm amplitude was used to agitate the stainless steel balls inside the cell at 16.7 rps. A cylinder of 99.9% pure methane from Matheson Inc. was used as a gas supply without further purification. The volumetric unit and the vent chamber shown on the diagram were not used in this set of experiments. Pressure was monitored via Heise gauges rated at 13.43 and 2.01 MPa. A Barocel differential electronic manometer (0.267 MPa full scale, 0.133 Pa resolution) was used at low pressures. A grease-sealed glass flask attached to the water and hydrocarbon inlet was used to vacuum distill water into the steel cell. The cell was immersed in an 8 l Neslab ethanol stirred bath. The bath was cooled using the Neslab cryocool CC-100 II 2-stage immersion cooler. The minimal attainable temperature was 180 K. The operating temperature was maintained with the Neslab temperature controller with ±0.3 K stability at temperatures below 260 K and ±0.1 K at higher temperatures and a 600 W immersion heater. Temperatures were measured with an Omega platinum resistance thermometer with ±0.1 K accuracy. The shaker frequency was selected to provide maximum cell agitation without excessive vibration. The lines and cell were evacuated to 4 Pa. Water (degassed, deionized) was vacuum distilled into the cell which was partially immersed in liquid N2. After the vacuum distillation process was complete, lines were re-evacuated. The bath was set to a constant experimental temperature. Fig. 10.13 presents a schematic of the experimental procedure. The gas was admitted into the system, and 8–10 min were allowed for pressure and thermal equilibrium without agitating the cell. After the system had stabilized, the shaker was started and the pressure drop was monitored as hydrates formed.

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10.  Research methods in flow assurance

Pressure

hydrates form

hydrates form Peq

error in data

hydrates decompose

hydrates decompose

0 0

Time

FIG. 10.13  Schematic of experimental procedure.

When the pressure approached a near-equilibrium value (in several hours), some gas was vented from the system to decrease the system pressure below the expected equilibrium value. The hydrates which had previously formed, dissociated causing the pressure to increase and to approach the equilibrium value. After pressure stabilization at some new level, the system pressure was increased again. This process was repeated in successive approximations until the differential between the formation and dissociation pressure reached 1–2% of the absolute pressure, as shown on the right in Fig. 10.13. The arithmetic average of the upper and lower pressure approximations was taken as the equilibrium value. Results and discussion for methane hydrate data The new equilibrium measurements are presented in Table 10.2 and in Fig. 10.14 along with those of previous researchers. The two extremes of our measurements (at 262.4 and 190.15 K) fit smoothly with previous results of Falabella (1975), and Deaton and Frost Jr. (1946), respectively. This agreement suggested the validity of the apparatus and experimental procedure. The other values fit smoothly into the temperature gap, as complements to existing data. Reproducibility of the measurements was also determined by duplicate runs at 243, 208, 198, and 190 K, with the largest variation of 2.5% at 198 K.



239

Hydrate stability and crystal growth

TABLE 10.2  Methane hydrate equilibrium. Data by

T equil, K

P equil, MPa

Error, MPa

190.15

8.471E-02

±0.001

8.572E-02

±0.001

1.349E-01

±0.001

1.365E-01

±0.001

2.336E-01

±0.002

2.278E-01

±0.002

218.15

3.666E-01

±0.005

243.15

9.825E-01

±0.01

9.991E-01

±0.01

9.823E-01

±0.01

9.805E-01

±0.01

262.4

1.847E+00

±0.06

148.8

5.30E-03

159.9

1.21E-02

168.8

2.11E-02

178.2

4.20E-02

191.3

9.01E-02

193.2

1.01E-01

262.4

1.79E+00

264.2

1.90E+00

266.5

2.08E+00

268.6

2.22E+00

270.9

2.39E+00

273.7

2.77E+00

274.4

2.90E+00

275.4

3.24E+00

275.9

3.42E+00

277.1

3.81E+00

279.3

4.77E+00

Present work

198.15

208.15

Falabella (1975)

Deaton and Frost Jr. (1946) set 1

set 2

Continued

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10.  Research methods in flow assurance

TABLE 10.2  Methane hydrate equilibrium.—cont’d Data by

T equil, K

P equil, MPa

280.4

5.35E+00

280.9

5.71E+00

281.5

6.06E+00

282.6

6.77E+00

284.3

8.12E+00

285.9

9.78E+00

259.1

1.65E+00

Error, MPa

Roberts et al. (1940)

FIG. 10.14  Methane hydrates equilibrium data. □—data by Falabella (1975). △—data by Deaton and Frost Jr. (1946), ◊—data by Roberts et al. (1940), ⊙—present work data (1992).



Hydrate stability and crystal growth

241

We used the Clausius-Clapeyron equation and the hydrate heat capacity by Handa (1986) in order to show that a smooth equilibrium line is expected with the absence of a phase transition in the region. Justification for use of this equation for univariant systems over a narrow temperature range comes from the fact that ΔdH and z do not change rapidly with temperature. Total change in ΔdH over the studied temperature interval was 22% of the initial value. Eq. (10.4) can be used to determine the enthalpy of dissociation of the hydrate systems, as validated by Handa (1986). This equation shows that the slope of the logarithm of the hydrate equilibrium pressure versus inverse equilibrium temperature is proportional to ΔdH. When a plot of ΔdH against T is monotonic and continuous, then a plot of ln[P] against 1/T will have no slope discontinuity. It is also known that. ΔH depends on T as follows: T0

∆d H ( T ) = ∆d H ( T0 ) + ∫ ∆CP dT

(10.5)

T

From this dependence it is seen that if a plot of ΔCp against T is smooth, then, so is ΔdH against T in the absence of a phase transition. ΔCp was evaluated using the stoichiometric formula:

∆CP = CP ( Hydrate ) − 6CP ( Ice ) − CP ( Gas )

(10.6)

assuming that the unit cell of sI hydrate crystal is formed by six ice molecules and one gas molecule at the most probable 96% occupation of cavities by guest molecules. Cp(Hyd) values were taken from Handa (1986), and Cp(Ice) and Cp(Gas) were extrapolated from literature values (Handbook of Chemistry and Physics, 1988; Friend et al., 1989) available for the region (23–271 K). Since both heat capacities of ice and methane do not deviate substantially from straight lines over the temperature region of interest, the conclusion may be drawn that ΔdH and consequently the slope of ln(P) against 1/T should be continuous. This fact may be supported by the experimental evidence from the work of Majid et al. (1969) for cyclopropane hydrates, where the sharp changes of slope of the hydrate equilibrium line were observed in the hydrate structural transition region. The absence of slope discontinuities in the entire subzero methane hydrates equilibrium line suggested that there was no structural transition of the structure I hydrates to structure II in the region of interest.

Xenon sI and xenon + neohexane sH hydrate experiments Data in the literature for Xe hydrates The second part of research on the low temperature apparatus was performed with a mixture of hydrate formers. Pure xenon and xenon + neohexane were chosen as the structure I and structure H hydrate formers, respectively. Pure xenon is only capable of forming sI hydrate. Data for sI hydrate of xenon were published by Aaldijk (1971). One unpublished data point by Dyadin et al. is at a much higher pressure. No previous phase equilibrium data was available for sH hydrate of this two guest mixture. An investigation of a temperature - pressure phase diagram of sH hydrate was the main purpose of this work.

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Apparatus used for xenon hydrate formation A xenon gas hydrate may form from ice as well as from liquid water. In order to study thermodynamic properties of gas hydrate below ice point the low temperature apparatus has been used. A schematic diagram of the apparatus was previously shown in Fig. 10.12. A spherical stainless steel reactor of spherical shape rated to 1500 psia was used to form hydrate. One hundred and fifty stainless steel balls of 1/8 in. diameter were placed inside the reactor. A reactor with stainless steel balls was shaken by the Thermolyne orbital shaker in order to mix the contents and renew the hydrate formation surface. Reactor maintenance consisted of regular cleaning with acetone, alcohol, and, sometimes, nitric acid to remove the fouling from the walls of the reactor and steel balls. The reactor was immersed in the constant temperature methanol bath. The temperature of the bath was maintained within ±0.3 K at temperatures below 260 K, and within ±0.1 K at higher temperatures by the Neslab on/off temperature controller. Cooling was provided by a Neslab CC-100 II low temperature cooler. The pressure of the reactor was sensed by two Heise gauges and by a Barocel manometer. The Heise gauges were Bourdon tubes with ranges 0–2.07 MPa ±1.38 kPa and 0–13.79 MPa ±13.79 kPa. The Barocel manometer was a differential electronic manometer with the range 0–2000 Torr ± 0.001 Torr (0–0.267 MPa ± 0.133 Pa). Water and liquid hydrocarbon were supplied to the reactor by vacuum distillation. Evacuation of the apparatus was provided by the Trivac vacuum pump generating a vacuum to 4 Pa. The cold trap was placed between the apparatus and the vacuum pump in order to prevent pollution of the apparatus tubing with vacuum oil and to collect some of the waste liquid after the experiment. The cold trap was cooled by the Flexi-cool cooler to 263 K. Experimental procedure A typical experiment started with evacuation of all tubing and the reactor. Stabilization of the pressure with the vacuum pump valved off indicated complete removal of water and hydrocarbon liquid. A weighed sample of degassed water was vacuum distilled into the reactor immersed into the cold bath by evaporation from the inlet flask and condensation on the cold walls of ­reactor. Vacuum distillation transported 98–99% of liquid into the reactor which was determined by weighing the reactor before and after distillation. Non-condensed vapor was evacuated. Liquid hydrocarbon was then, if required, distilled into the reactor, which was immersed into liquid nitrogen. All lines were evacuated after the distillation was complete. Xenon of 99.999% purity purchased from Matheson Gas Products, Inc. was used in this set of experiments. The gas pressure was set and gas was allowed to cool in the stationary reactor for 10 min. The pressure was then adjusted to the starting value and the shaker was started. Pressure was monitored with intervals of 10–30 min and recorded into the notebook for further analysis. A typical curve of pressure versus time is shown in Fig. 10.15, similar to that of Fig. 10.13. Gas was partially vented after hydrate formation rate approached zero and hydrate decomposed. Pressure was then increased to the lowest point in the previous formation cycle and hydrates formed. This process was repeated until the differential between the lower formation and upper decomposition pressures narrowed to 7–14 kPa. The arithmetic average of the two values of



243

Hydrate stability and crystal growth

Pressure, torr 800 run 39 10 / 9 / 92 xenon–neohexane Structure I equilibrium pressure

700

T=–10°C, Tamb=75°F s.s.balls=150, D=1/8in. shaking rate=970rpm stirring rate=1000rpm 99.999 xenon 7:1 water–neohexane m water = 1g

600

500 0

500

1000

1500

2000

Time, min. FIG. 10.15  Typical hydrate equilibrium run.

decomposition and formation pressures in the end of experimental curve (see Fig. 10.13) was taken as the equilibrium pressure of hydrate formation at the given conditions. This procedure provides a more rapid approach to equilibrium. Upon completion of the experiment gas was vented into the atmosphere. Water, and the hydrocarbon liquid, if any, were evacuated from the reactor and lines. Results A set of data for pure Xe sI hydrate formation conditions was generated. Experiments were run with 1 g of water in the reactor at constant temperatures of 228, 273, 283, and 288 K. Data are presented in Table 10.3 along with the data by Aaldijk (1971). Fig. 10.16 shows the equilibrium data for xenon sI hydrate formation. The change of equilibrium line slope in Fig. 10.16 at sub-zero temperatures is attributable to the change of heat capacity as discussed in Eq. (10.6). A set of data for Xe + neohexane liquid sH hydrate formation conditions was generated. Xenon (effective diameter 0.458 nm) fits only into small (512) and medium (4351263) cavities of sH hydrate (see Table 10.1). Neohexane (effective diameter 0.773 nm) can fit only into the large (435663) cavity of sH hydrate. At complete occupancy of cavities, the unit cell of sH

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10.  Research methods in flow assurance

TABLE 10.3  Pure xenon sI hydrate equilibrium. Data by

T equil, K

P equil, MPa

Error, KPa

228.15

0.01620

±0.1135

273.15

0.1551

±1.216

283.15

0.4263

±1.723

288.15

0.6984

±0.1723

289.07

0.784

283.62

0.4465

278.66

0.269

273.15

0.153

262.16

0.0932

252.49

0.0594

232.88

0.0212

227.29

0.01512

CSM

Aaldijk (1971)

Miller (Amer, 1981)

Dyadin (1994), Dyadin et al. (unpublished) 337

250,000

hydrate, composed of 34 water molecules, may enclathrate at most 1 neohexane molecule and 5–6 xenon molecules. Experiments were run with 1–2 g of water and a higher than stoichiometric amount of neohexane, (0.15–1 g) in order to avoid disappearance of liquid hydrocarbon phase. Experimental data are presented in Table 10.4. In order to ensure repeatability, runs at four out of ten temperatures were repeated. Results and discussion for xenon hydrate data Fig. 10.17 shows the superimposed data sets for pure xenon and xenon+neohexane mixture hydrates. A crossover of equilibrium curves can be seen in the temperature interval around 281.5 K. This indicates a presence of a quintuple point for a vapor-liquid1-­liquid2-sI hydrate-sH hydrate system. This is the first quintuple point observed for sH hydrate. ­ Fig. 10.18 shows the enlarged crossover area. At temperatures above the crossover, the xenon + neohexane hydrate formation line has a slightly higher pressure, but is parallel to the pure xenon hydrate formation line. Crossover and a change in slope of equilibrium pressure line for xenon + neohexane hydrate clearly indicates the phase transition of sH hydrate into sI hydrate in this temperature interval. Fig. 10.18 shows this phenomenon more clearly. A program utilizing the SRK EOS was written in Turbo Pascal, allowed the calculation of vapor and liquid composition of xenon + neohexane mixture. It indicated that liquid



Hydrate stability and crystal growth

245

FIG. 10.16  Equilibrium data for pure xenon sI hydrate. □—CSM data (1992). △—data by Aaldijk (1971).

­ ydrocarbon phase was present in the system at the studied conditions. Results of this calcuh lation are presented in Table 10.5. Justification for elevation of sI hydrate equilibrium line for the three-component mixture above the sI line for the two component mixture was done using a two-step process. The first step used PHAS_88 program by DB Robinson Research LTD. to calculate the vapor phase compositions of two- (water + xenon) and three-component (water + xenon + neohexane) systems with known total compositions. The second step used HYDR_88 program by DB Robinson Research LTD. to estimate sI hydrate equilibrium pressure for the two- and three-component systems with known total compositions. Hydrate equilibrium requires the fulfillment of the three conditions: equal temperature, pressure, and chemical potential in hydrate and in other phases. In case of two component system a certain pressure of xenon is required in the vapor to form hydrate. If a third v ­ olatile component is added (like neohexane) which cannot participate in sI hydrate, the partial ­pressure of xenon will decrease due to the presence of neohexane in the vapor. Hydrate will form only if the partial pressure of xenon in the vapor mixture is equivalent to the pressure of

TABLE 10.4  Xenon + neohexane hydrate equilibrium. Temperature (K)

Pressure (MPa)

233.15

0.0145

±0.0011

253.15

0.0464

±0.0001

263.15

0.0785

±0.0017

273.15

0.1333

±0.0010

0.1315

±0.0001

0.1819

±0.0010

0.1813

±0.0005

278.15

0.2412

±0.0003

280.65

0.3447

±0.0010

0.3427

±0.0057

283.15

0.4525

±0.0010

285.65

0.5742

±0.0019

288.15

0.7242

±0.0032

0.7238

±0.0052

0.7296

±0.0016

275.65

FIG.  10.17  Data for pure xenon and for xenon + neohexane mixture. □—Present work data for pure xenon, △—data by Aaldijk for xenon (1971), ⊙—present work data for xenon + neohexane.



Hydrate stability and crystal growth

247

FIG. 10.18  Data for pure xenon and for xenon + neohexane mixture above 273 K. □—Present work data for pure xenon, △—data by Aaldijk for xenon (1971), ⊙—present work data for xenon + neohexane.

TABLE 10.5  Calculated phase composition for the xenon + neohexane system. T, K

x Xe

y Xe

278.15

0.06957

0.92354,

280.65

0.09655

0.93963

283.15

0.12222

0.94818

285.65

0.14837

0.95379

288.15

0.18293

0.95943

Liquid and vapor phase composition at equilibrium conditions based on program calculation for Xe + neohexane system.

pure xenon above sI hydrate. Thus a higher total pressure was required in the 3 component mixture to offset the neohexane concentration in the vapor. Table 10.6 presents how the xenon vapor concentration is reduced by the addition of neohexane to the system. The bottom section of the table shows the normalized reduction of concentration to vary between 4% and 9%.

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10.  Research methods in flow assurance

TABLE 10.6  Calculated vapor phase composition. 3 component vapor phase composition at equilibrium conditions based on EquiPhase program calculation for Xe + neohexane + water system T, K

y H2O

y neoC6

y Xe

278.15

0.003516

0.0795

0.917

280.65

0.002924

0.0627

0.9344

283.15

0.002639

0.05375

0.9436

285.65

0.002469

0.04788

0.9496

288.15

0.002262

0.04202

0.9557

2 component vapor phase composition at equilibrium conditions based on EquiPhase program calculation for Xe + water system T, K

y H2O

y Xe

278.15

0.003575

0.9964

280.65

0.00299

0.997

283.15

0.002713

0.9973

285.65

0.002551

0.9974

288.15

0.002354

0.9976

Change in vapor xenon concentration as a result of adding neohexane in the system T, K

△y/(y3 component)

278.15

0.086587

280.65

0.066995

283.15

0.05691

285.65

0.050337

288.15

0.043842

In the second part, higher sI hydrate equilibrium pressures in a three-component system were predicted, compared to the two-component system. Although the predicted pressures were underestimated by 7–8%, the predicted pressure differences for the two- and three-­ component systems were comparable to the differences measured experimentally as indicated in Fig. 10.19. This figure presents the experimental and calculated univariant sI hydrate lines. Table 10.7 presents the calculations and experimental data. The reader may notice that the normalized pressure and compositional differences have similar values in the last five lines of Tables 10.6 and 10.7. This similarity reflects the change in partial pressure as a function of composition (pA = yA*P). If yA decreases the total pressure must increase proportionally in order to maintain the same partial pressure (uncorrected fugacity).



Hydrate stability and crystal growth

249

FIG. 10.19  Calculated and experimental data for pure xenon and for xenon + neohexane mixture above 273 K.

□—CSM data for pure xenon (1992), △—data by Aaldijk for xenon (1971), ⊙—CSM data for xenon+neohexane (1992), - -, HYDR_88 program predicted data.

Evaluation of experimental results Study of the phase transition possibility for methane hydrate at subzero temperatures was investigated. Results of this study are summarized earlier in this chapter. It was shown that in the temperature interval of 154–273 K no sI to sII structural transition of the hydrate happened. It is possible, however, that the structural transition may occur at temperatures below 154 K where no experimental data exist. Experiments on xenon sI and xenon + neohexane sH hydrate equilibria resulted in a generation of two phase diagrams in the temperature region of 228–288 K. It was found from the generated equilibrium curves that a quintuple point sH-sI-Lw-Lh-V point should be present in the temperature interval of 278–283 K. This phase diagram does not violate the Gibbs's phase rule.

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10.  Research methods in flow assurance

TABLE 10.7  Hydrate equilibrium calculation. Hydrate equilibrium for Xe + neohexane + water system T, K

P, kPa

Pcalc

278.15

241.25

264.22

280.65

344.74

333.38

283.15

452.52

421.12

285.65

571.21

532.8

288.15

733.593

673.68

sI hydrate equilibrium for Xe + water system T, K

P, kPa

278.15

N/A

280.65

N/A

283.15

426.2743

285.65

N/A

288.15

698.4332

Pcalc

396.2

640.66

Normalized changes in xenon pressure required as a result of having neohexane in the system. T, K

△P/P(3 component)

278.15

N/A

280.65

N/A

283.15

0.057999

285.65

N/A

288.15

0.047928

Evaluation of the biomolecular computer studies Simulation of the macromolecules docking on the surface of water crystals showed the preferential orientations and interaction energies between macromolecules and the surface. It was concluded from the resulting low energies of interaction that Winter Flounder polypeptide biomolecule, PVP and PVCap molecules are able to adsorb on ice, sI and sII hydrate surfaces. Very high interaction energy was shown for the VC-713 polymer which suggests that it cannot dock on water crystals. The reason for inability of VC-713 to dock on water crystal is considered to be the DMAEMA (dimethylaminoethylmethacrylate) monomers presence in the polymer chain. This monomer acts as a buffer between polymer and crystal. Verification of the water models was performed. The simple point charge (SPC) water model was shown to adequately represent the structural and thermodynamic properties of real water. SPC water model is recommended as a choice among all water models available in SYBYL.



Molecular modeling

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Study of structural changes in the water hydrogen bonding network incurred by the hydrate inhibitors was done. A new method of analyzing the structure of water was used in this study. The results of simulation are in qualitative agreement with the experimental performance of the studied compounds. Limitations of this study are (1) the docking was performed in vacuo; (2) PVP, PVCap, and PVCA inhibitors were simulated as single monomers; (3) Scaling of the dielectric interactions was used in inhibitors effect on water structure study. A potentially better hydrate inhibitor was suggested based on the computer simulation results. Molecular dynamics simulation proved not only to replicate the real experimental data, but to predict the new compounds as well. This study suggests that the following properties should be present in a good hydrate inhibitor: 1. Presence of a carbonyl group (active site) to introduce structural changes into the water. 2. Presence of a strongly electronegative atom such as nitrogen next to the carbonyl group in order to enhance the electron cloud of the carbonyl oxygen (electron donating site). 3. Ring structure holding the active and the electron donating sites in order for electron sharing to be smoothly equilibrated. 4. A polymer chain holding the rings with active and electron donating sites to add a pattern to the active groups. The potential new kinetic inhibitors may have the structure similar to cyanuric acid and its derivatives. Mechanism of the kinetic hydrate inhibition is most likely in the structural rearrangement of water molecules. Kinetic inhibitors decrease the number of H bonded polygons driving the structure of water away from that favoring hydrate and making the formation of hydrate unfavorable. Several recommendations can be made for the future studies. Simulation 1. Use oligomers rather than monomers of inhibitor 2. Try solutions of these inhibitors with different concentrations 3. Hydrate the species before docking on the hydrate surface 4. Look at docking on different surfaces of the hydrate crystal lattice Experimental 1. Pinpoint the xenon-water-neohexane system quintuple point location above 0 °C. 2. Chromatographic analysis is needed for liquid and vapor phases composition in the xenon-water-neohexane system.

Molecular modeling Comparison of chemical performance on a solid surface Computer simulations can be used to gain an understanding of the hydrate inhibition mechanism. Docking simulation of hydrate inhibitors on surfaces of ice and gas hydrates of sI and sII reveals the energy with which they adsorb. Inhibitor chemicals included the Winter Flounder polypeptide biomolecule, PVP, PVCap, and VC-713. Modeling of water and ice was done using the SPC water model. A study was done of the effect of hydrate inhibitors on the

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10.  Research methods in flow assurance

structure of water using a polygons counting approach. A potential new hydrate inhibitor was proposed, based on this study.

Computer study of hydrate inhibition mechanism Overview of the computer simulations Reasons for the computer study

The mechanism for kinetic inhibition of hydrates can be studied on a micron scale when hydrate nuclei are sterically prevented by polymeric inhibitors from agglomeration. It also can be viewed on the scale of nanometers when the inhibitor affects the microstructure of water and defers hydrate formation. Today's experimental techniques do not allow the dynamic study of the properties of materials in time on a microscopic basis. Computer simulation (molecular dynamics) is a widely used tool which possesses several advantages over the real experiment. The first advantage is the ability to look into the dynamics of the processes on a scale of angstroms. Other advantages include 100% repeatability, ease of modification of parameters, and a safe environment. Among the disadvantages are the use of simplified, theoretical models of the real processes, high computing and data storage requirements, and computational round-off errors. Modern high-powered computers permit more complex simulations, such as phase behavior and structural properties of fluids and solids. Examples of computational research are discussed in an ever increasing number of publications. Guidelines for writing the computer simulation programs may be found in books by Allen and Tildesley (1987) and by Haile (1992). Many commercial software packages for state-of-the-art simulations are available, such as BIOSYM®, SYBYL®, and HyperChem®. SYBYL® is an extensive suite of software focused on computational molecular and biomolecular design. A modular program, SYBYL® features software for applications in drug design, biochemical research, homologous chemical modeling, property prediction, molecular dynamics, polymer research, and conformational analysis. SYBYL® includes a molecular spreadsheet which can store the obtained information. A molecular spreadsheet allows the analysis of stored information using one or more parameters. SYBYL® functions in a number of modes: command line, graphical, and a combined mode which mixes command line access with graphical selection of objects directly from the screen. The central role of SYBYL® is to enable the researcher to answer the question: “What chemical structure or structures should I synthesize next in order to more fully understand my research problem or produce more active agents?” The search for the best gas hydrate inhibitor requires the answer of this question. In order to synthesize a chemical to prevent hydrate formation completely, the mechanism of hydrate inhibition has to be known. It is necessary to determine the function of the kinetic inhibitors in preventing hydrates' formation. SYBYL® has been used previously to model SPC water. The results of previous simulations (Clark, 1992) are in good agreement with the original SPC model results (Berendsen et al., 1981). Results of the computer simulation This work attempted to provide a qualitative explanation of kinetic inhibition phenomena for hydrate formation. Two hypotheses for the inhibition mechanism were tested.



Molecular modeling

253

The first hypothesis was based upon a similarity to the inhibition of ice growth. Polypeptides present in the blood of the winter flounder allows it to survive the Arctic sea temperatures of 270.9 K. The structure of this polypeptide is described later in this chapter. It was shown (Knight et al., 1993) that polypeptide adsorption on the ice surface prevents further crystal growth. We hypothesized that adsorption on the hydrate surface might prevent hydrate growth just as in ice. This hypothesis is addressed in Section “Docking of macromolecules on hydrate and ice”. The second hypothesis was that hydrate inhibition is not the result of a crystal surface interaction, but that of interaction with the bulk liquid. The hypothesis was that the polymer changes the structure of water, making hydrate formation entropically unfavorable. This hypothesis is addressed in Section “Studying of kinetic inhibitor interaction with water: Solvation of the polymer in the bulk water”.

Docking of macromolecules on hydrate and ice Introduction The first portion of the computer study was directed to provide evidence for (or against) the adsorption hypothesis. Evidence was obtained that some of the polymeric hydrate inhibitors with relatively simple structures like polyvinylpyrrolidone (PVP) and polyvinylcaprolactam (PVCap) might adsorb on the surface of hydrate crystal. This adsorption was hypothesized to be similar to adsorption of the winter flounder polypeptide on a plane of growing ice. Method of research The molecular simulation program SYBYL® (version 6.01), a product of Tripos Associates, Inc., was used to perform the docking studies. Docking of the winter flounder polypeptide was simulated on three different surfaces of ice-I, and on crystal surfaces of sI and sII hydrate. The sequence of the aminoacids chemical formula of the winter flounder polypeptide is shown here. Docking of the hydrate inhibitor polymers VC-713, PVP, PVCap shown in Fig. 10.20 was performed on crystal surfaces of sI and sII hydrate. The crystal surface and each macromolecule were docked in vacuo and the intermolecular energy was estimated for different conformations. Adsorption energy was the main parameter studied in this calculation. The energy of adsorption is a measure of the interaction between the inhibitor and the water crystal (ice or gas hydrate). Both the polymer (inhibitor macromolecule) and the site (hydrate or ice crystal) were positioned by SYBYL® in the two separate molecular areas. The interaction of the polymer with hydrate was calculated on an atom-to-atom and charge-to-charge basis which accounted for each water molecule in the hydrate lattice. The interaction energy accounts for the steric (van der Waals) and electrostatic (Coulombic) interactions. The energy of interaction is zero at infinite separation of the site and the polymer, and it is a potential function of distance between interacting sites. A review of potential functions was presented by Prausnitz et al. (1986, sec. 5.5). The lowest interaction energies obtained in this study cannot be viewed as absolute minima. The number of possible configurations of polymer on the crystal surface is nearly infinite, only limited by computer precision. The energies obtained energies represent local minima in energy and the best attempt of the author within the available resources.

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10.  Research methods in flow assurance

FIG. 10.20  Chemical structures of PVP, PVCap and VC-713.

Surfaces of sI and sII empty hydrate lattices, and hexagonal ice lattice were prepared using SYBYL® by inputting the coordinates of the oxygen and hydrogen atoms and connecting them into water molecules. Coordinates were generated using the Fortran program which replicated the X-ray diffraction data for crystal unit cell in x, y and z directions. A surface of any size and thickness could be generated. Size of the surface was made 5 × 5 × 1 sI unit cells for sI hydrate, 4 × 4 × 1 sII unit cells for sII, and 9 × 9 × 2 repeat units for ice. The dimension of the surface was 6.1 nm or more along x and y axes. Such sizes were chosen in order to accommodate the winter flounder polypeptide (5.9 nm length), 9-link chain of the VC-713 polymer (6.1 nm length) and to reduce computation time. The polymer chain of VC-713 and winter flounder polypeptide were generated using the Hyperchem® release 2.0 program for Windows made by Autodesk, Inc. Potential energies of the macromolecules were minimized in vacuo before transferring to the IBM RS-6000 workstation. After transferring to the IBM workstation an overall energy minimization was done.



Molecular modeling

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The winter flounder polypeptide sequence of the aminoacids in standard nomenclature is: DTASDAAAAAALTAANAAAAAKLTADNAAAAAAATAA, where the letters represent D—aspartic acid, T—threonine, A—alanine, S—serine, L—leucine, N—asparagine, and K—lysine. The structures of these aminoacids can be found in every recent organic chemistry textbook. These structures are described in Table 10.8. The VC-713 polymer chain was built as a repeating sequence of monomers present in the real polymer: − ( vinylpyrrolidone − vinylcaprolactam − DMAEMA )x − . The molecules were then transferred from the 486 PC to the IBM workstation in Brookhaven format. PVP and PVCap chains were also 9 repeat units long. Fig. 10.20 shows polymer structures. These polymers were built using the SYBYL’ program. The studied macromolecule and the crystal surface were read into SYBYL’. Charges for water molecules in the crystal and for the macromolecules were computed using the method by Pullman (Berthod and Pullman, 1965). Macromolecule was equilibrated in vacuo. Periodic boundary conditions were set up around the system, and a lattice of the intermolecular potential energy field was precalculated for various relative positions of the macromolecule and the crystal surface. Six variables define a position and orientation of the rigid polymer chain in space. Docking of macromolecules on the crystal surface was performed by varying the x, y, z, Θ and Φ variables for the macromolecule. Coordinates x, y and z specify the center of the macromolecule relative to the crystal surface, Θ is the angle between the center line of the TABLE 10.8  Structure of aminoacids composing the winter flounder polypeptide. General aminoacid formula:

Aminoacid

R radical

D aspartic acid

CH2CO2H

T threonine

A alanine

CH3

S serine

CH2

L leucine

CH2CH(CH3)2

N asparagine

CH2CONH2

K lysine

(CH2)4NH2

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10.  Research methods in flow assurance

macromolecule and the initial position on the crystal surface, and Φ is the angle of the macromolecule rotation about its center line relative to the initial position. The macromolecule was flat, relative to the surface, keeping the sixth variable 0 fixed. The intermolecular energy (potential energy between molecules in current conformation relative to infinitely distant molecules) was monitored during the docking. The conformation with the lowest intermolecular energy was chosen as the preferred orientation of the macromolecule on the crystal surface. A typical value of the interaction energy prior to the relaxation of the macromolecule on the crystal surface was of the order of tens of kilocalories per mole. The energy of the whole system was minimized (the macromolecule was relaxed on the crystal surface). The final system energies are given in Table 10.9. Data analysis One run was performed for each polymer chain. For each run the following final values were inspected: (a) The number of hydrogen bonds between the macromolecule and water molecules of the crystal. Hydrogen bonds were defined by the following default values stored in SYBYLQ two water molecules were found to be hydrogen bonded if the length of hydrogen bond were less than or equal to 0.285 nm and the HO-----H angle >120%. TABLE 10.9  Analysis of macromolecules docking on crystals. Intermolecular energy, kcal/mol

Number of hydrogen bondsa

Pattern of adsorption sites

Winter flounder polypeptide on ice 011

1742

4 (100%)

Yes (1.69 nm)

ice 101

−19,850

4 (100%)

Yes (1.69 nm)

ice 110

−19,924

4 (100%)

Yes (1.69 nm)

sI hydrate

−5245

0 (0%)

Yes (1.69 nm)

sII hydrate

−12,696

4 (100%)

Yes (1.69 nm)

sI hydrate

751,600

0 (0%)

Some (3.69 nm)

sII hydrate

731,594

1 (33%)

No

sI hydrate

−5065

0 (0%)

Yes (0.6 nm)

sII hydrate

−12,495

1 (33%)

Some (1.87 nm)

sI hydrate

−5057

0 (0%)

Yes (0.6 nm)

sII hydrate

−12,504

0 (0%)

No

VC-713 on

PVP on

PVCap on

a

Percentage of bonding at available sites on macromolecule.



Molecular modeling

257

FIG. 10.21  Conformation of the winter flounder polypeptide docked on ice (surface 1). Dashed lines represent hydrogen bonds. Winter flounder polypeptide is hydrogen bonded by four hydroxyl OH groups to oxygens of water molecules in ice.

(b) Conformation geometry, repeating of docking sites on the crystal, if any. Some macromolecules exhibited a regular, periodic geometric fit of adsorption groups and adsorption sites. This can be best seen with winter flounder polypeptide in Fig. 10.21. Macromolecules retained the regular coil conformation. (c) The energy of intermolecular interaction. The energies after the final minimization were compared. Very high positive energies indicated that adsorption was impossible. This is the case for VC-713. The results of the analysis are presented in Table 10.9. Discussion of polymers docking The docking of winter flounder polypeptide was performed on five types of crystal surface: 100, 010 and 001 surfaces of ice, and 001 surfaces of sI and sII hydrate. The best results were obtained for docking of the winter flounder polypeptide on ice surfaces. This was an anticipated outcome because the winter flounder polypeptide prevents the blood of this fish from freezing at sub-zero temperatures down to 270.9 K by adsorbing on ice crystals and preventing them from growing further (Knight et al., 1993). Docking of the polypeptide on hydrate sI and sII shows that interaction energies are low (−5245 and −12,696 kcal/mol, accordingly). The winter flounder polypeptide may have a similar effect on the growth of hydrate by preventing bulk hydrate formation. Edwards (1993) presented results for the winter flounder polypeptide docking on hydrate sI. He suggested that this polypeptide adsorbs on sI hydrate in [110] direction based on the similarity of polypeptide hydroxyl groups spacing (1.686 nm) and distance between second nearest large cavity neighbors in sI hydrate (1.697 nm). Winter flounder polypeptide adsorption on all water crystals shows the repetitive pattern of adsorption sites locations. See Figs. 10.22–10.25. The main result of this study was that the polymers PVP and PVCap may inhibit hydrate growth by adsorbing on the hydrate crystal, as indicated by their low adsorption energy. However, adsorption is, probably, not the inhibition mechanism of VC-713, because the adsorption energy of VC-713 was high. Docking of VC-713 polymer on sI and sII hydrates resulted in very high interaction energy (over 730,000 kcal/mol). The high energy indicates that adsorption of VC-713 on hydrate surface is energetically unfavorable. This high energy is thought to be the consequence of DMAEMA group which sterically prevents the adsorption. This result suggests that the mechanism of kinetic inhibition for the VC-713 polymer may not

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10.  Research methods in flow assurance

FIG. 10.22  Conformation of the winter flounder polypeptide docked on ice (surface 2). Dashed lines represent hydrogen bonds. Winter flounder polypeptide is hydrogen bonded by four hydroxyl OH groups to oxygens of water molecules in ice.

FIG. 10.23  Conformation of the winter flounder polypeptide docked on ice (surface 3). Dashed lines represent hydrogen bonds. Winter flounder polypeptide is hydrogen bonded by four hydroxyl OH groups to oxygens of water molecules in ice.

FIG.  10.24  Conformation of the winter flounder polypeptide docked on sI hydrate. Dashed lines in the polypeptide and the hydrate represent hydrogen bonds. Winter flounder polypeptide is not hydrogen bonded to water molecules in hydrate.



Molecular modeling

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FIG. 10.25  Conformation of the winter flounder polypeptide docked on sII hydrate. Dashed lines represent hydrogen bonds. Winter flounder polypeptide is hydrogen bonded by five carbonyl CO groups to hydrogens of water molecules in hydrate.

be through adsorption of the polymer on the hydrate surface. VC-713 may work in solution by restructuring of the bulk water and making it difficult for the water molecules to arrange into the hydrate crystal. This alternative hypothesis was investigated in the second part of the computer studies (Section “Studying of kinetic inhibitor interaction with water: Solvation of the polymer in the bulk water”). Locations of adsorption sites of VC-713 have little or no pattern. See Figs. 10.26 and 10.27. Docking of PVP polymer gave results very similar to those for the winter flounder polypeptide. An optimal fit of PVP on hydrate surfaces is energetically favorable (−5065 to −12,495 kcal/mol). PVP may be inhibiting hydrates through adsorption on any growth site and changing the hydrate surface properties. Adsorption sites of PVP on sI hydrate show the pattern in locations. See Figs. 10.28 and 10.29. Docking of PVCap polymer produced results very similar to those of PVP. Low interaction energies (−5057 to −12,504 kcal/mol) and presence of adsorption sites on sI can be seen. See Figs. 10.30 and 10.31. Fig. 10.32 shows separate macromolecules. Numbers in Fig. 10.32 show the distance between repeating groups which may participate in hydrogen bonding.

FIG. 10.26  Conformation of the VC-713 polymer docked on sI hydrate. Dashed lines represent hydrogen bonds. VC-713 is hydrogen bonded by one carbonyl CO group to hydrogen of water molecule in hydrate.

FIG. 10.27  Conformation of the VC-713 polymer docked on sII hydrate. Dashed lines represent hydrogen bonds. VC-713 is hydrogen bonded by one carbonyl CO group to hydrogen of water molecule in hydrate.

FIG. 10.28  Conformation of the PVP polymer docked on sI hydrate. Dashed lines in the hydrate lattice represent hydrogen bonds. PVP is not hydrogen bonded water molecules in hydrate.

FIG. 10.29  Conformation of the PVP polymer docked on sII hydrate. Dashed lines represent hydrogen bonds. PVP is hydrogen bonded by one carbonyl CO group to hydrogen of water molecule in hydrate.

FIG. 10.30  Conformation of the PVCap polymer docked on sI hydrate. Dashed lines in the hydrate lattice represent hydrogen bonds. PVCap is not hydrogen bonded to water molecules in hydrate.



Molecular modeling

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FIG. 10.31  Conformation of the PVCap polymer docked on sII hydrate. Dashed lines in the hydrate lattice represent hydrogen bonds. PVCap is not hydrogen bonded to water molecules in hydrate.

FIG. 10.32  Examples of natural antifreeze polypeptide and of kinetic hydrate inhibitors.

Conclusions for docking study Molecular mechanics was used for examining potential kinetic inhibitors' interaction with ice or gas hydrate surface. Docking of the winter flounder polypeptide on three surfaces of ice Ih and surfaces of sI and sII hydrates was performed. Adsorption energy is favorable. Simulation provides some insight into the ice inhibition mechanism. Energies for VC-713 docking on water crystals are shown to be unfavorable. Long DMAEMA groups sterically hinder the ability of a VC-713 polymer chain to lie flat on adsorption site. Results for the other kinetic hydrate inhibitors PVP and PVCap are very similar to the results for winter flounder

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polypeptide. Docking may well be the mechanism of hydrate inhibition by these polymers. However, there is a contradiction between the difference in performance of these polymers in inhibiting hydrate formation and similarity of results of the docking study. This suggests that a more detailed study of adsorption of inhibitors on hydrate in water solution is necessary.

Studying of kinetic inhibitor interaction with water: Solvation of the polymer in the bulk water Introduction Structural changes in liquid water were investigated in the second part of the computer studies of gas hydrate inhibition. This testing of the second kinetic hydrate inhibition mechanism hypothesis (destruction of structure in the bulk water) was performed using molecular dynamics. Different polymers or their monomers were solvated in SPC water, depending on the desired polymer concentration. Effects of each polymer on the structure of water was obtained by comparing it with the structure of pure SPC water at the same conditions. The work was started with selecting the SPC water model for use after the comparison of water models available in SYBYIT. Melting point of the SPC water model was fit to 200 K as reported (Karim et al., 1990) by scaling of the electrostatic interactions. This was followed by determination of the structure of water at 203 and 220 K (scaled 277 and 298 K). Simulation of the polymer solutions and analysis of the structure of solvent concluded this work. Initially the models of water available in SYBYL were verified by comparing the oxygen‑oxygen radial distribution function of simulated and real water at 298 K, with results presented in Fig. 10.33. The radial distribution function (RDF) measures local density as a function of distance. RDF can be viewed as the probability of finding a water molecule at a certain distance from a particular water molecule. Integration of the area under the first peak represents the number of the nearest neighbors. The best fits of simulation to data were obtained for the SPC (simple point charge) and the TIP3p (transferable intermolecular potential 3 point) models. Based on this result the SPC water model was selected. A comparison of oxygen- hydrogen radial distribution functions for the SPC model and water was made. The oxygen-hydrogen radial distribution function indicates the average length of hydrogen bonds in water through the position of the first peak. A good comparison was obtained between the experimental data (Soper and Phillips, 1986) and the simulation results (Fig.  10.34). This completed the verification of the water model radial distribution function. The most interesting outcome of this part of the work is that the kinetic inhibitors affect the structure of hydrogen bonded network of water molecules in such a way as to make hydrate formation more difficult. This was discovered through the counting of rings in three dimensional hydrogen bonded network of water in a fashion similar to that described by Rahman and Stillinger (1973). The structure of water can be described as a network of hydrogen bonds connecting almost all water molecules, with only a small number of molecules free of the network. At higher temperatures, the energy of hydrogen bonding (approximately 5 kcal/mol) is insufficient to keep the moving water molecules together and the network of hydrogen bonds becomes very loose. As the temperature decreases, water molecules vibrate less and a dense network of dynamic hydrogen bonds is formed. Hydrogen bonds in this network are arranged in rings which form and rearrange with time. Rings sizes are measured in terms of the number of participating water molecules. The most probable sizes of hydrogen bonded rings are 5 and 6. For a comparison, water molecules in ice (hexagonal Ih) are arranged exclusively as 6-membered rings,



Molecular modeling

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FIG. 10.33  RDF oxygen‑oxygen for all water models available in SYBYL® compared with experiment.

which is determined by the molecular structure of water, which is in turn determined by the electron cloud configuration. Rings of these sizes dominate the structure of water (Rahman and Stillinger, 1973; Speedy et al., 1987). Water molecules usually participate in several rings simultaneously. A schematic of the network of hydrogen bonds between water molecules is shown in Fig. 10.35. Near the freezing point almost all water molecules are hydrogen bonded to the common network. In order to form ice, all rings of a size other than 6 must rearrange and form 6-membered rings. Since 5- and 6-membered rings are the most numerous in the network, little rearrangement is required. At very fast cooling rates, though, the network does not rearrange and water freezes into amorphous ice. This is a common outcome of attempts at computer simulations of freezing the water. Similarly, substantial water structure is already present before gas hydrate is formed. Dissolved guest molecules are driven into the lattice of water molecules arranged mostly in 5- and 6-membered rings. It should be noted that 5- and 6- membered rings are the only ones present in the structure of gas hydrate. The aqueous solutions of polymers used as gas hydrate inhibitors were simulated for VC-713, PVP, PVCap

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FIG.  10.34  Oxygen‑hydrogen radial distribution function for SPC water model simulation (this work)—solid line, and experiment (Soper and Phillips, 1986)—line with circles.

and a prospective chemical ­polyvinyl cyanuric acid (PVCA). The structure of the new chemical is presented in Fig. 10.36. The last three inhibitors were simulated as single monomers in order to match the halves can't be equal in size, even−>can be equal halves) and compare snext to start1,2 of shorter or of both halves of the ring. Then proceed as in main routine until ns>=dist or found finish.}

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proceed:=false; if ((nr mod 2)=0)and(dist=(nr/2)) then begin {dist is same as equal halves of ring} if (snext>start1)and(snext>start2) then proceed:=true; {snext can start a good short circuit} end else begin {different halves of ring} if psstart1 then proceed:=true; end;

{snext can start a good short circuit}

repeat S4: begin {search for sh.circ. starting with snext} if order[snext]=2 then begin {easy find: only one possibility} sfound:=true; ns:=ns+1; srin[ns]:=snext; for js:=1 to n do begin if (nhb[js,1]=snext)and(nhb[js,2]srin[ns−1])then snext:=nhb[js,1]; if (nhb[js,2]=snext)and(nhb[js,1]srin[ns−1])then snext:=nhb[js,1]; end; if snext=srin[ns] then snext:=nhb[js,2]; sbonds[ns]:=js; end else {search the tedious way} for js:=1 to n do if (nhb[js,1]=snext)or(nhb[js,2]=snext) then begin sfound:=false; if nhb[js,1]=snext then begin {one of atoms in bond fits} snothere:=true; for ks:=2 to ns do {see if link was found already} if srin[ks]=nhb[js,2] then snothere:=false; for ks:=1 to pf-1 do {see if link is in the ring} if rin[ks]=nhb[js,2] then snothere:=false; {avoiding test of finish position} if pf nr then for ks:=pf+1 to nr do

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if rin[ks]=nhb[js,2] then snothere:=false; if snothere then begin {new point in short circuit found} sfound:=true; ns:=ns+1; srin[ns]:=snext; {write to short circuit array} sbonds[ns]:=js; {write to short circ. bonds list} snext:=nhb[js,2]; {define next atom for search} goto S2; end; end; if nhb[js,2]=snext then begin {another atom in bond fits} snothere:=true; for ks:=2 to ns do {see if link was found already} if srin[ks]=nhb[js,1] then snothere:=false; for ks:=1 to pf−1 do {see if link is in the ring} if rin[ks]=nhb[js,1] then snothere:=false; {avoiding test of finish position} if pf nr then for ks:=pf+1 to nr do if rin[ks]=nhb[js,1] then snothere:=false; if snothere then begin {new point in short circuit found} sfound:=true; ns:=ns+1; srin[ns]:=snext; {write to short circuit array} sbonds[ns]:=js; {write to short circ. bonds list} snext:=nhb[js,1]; {define next atom for search} goto S2; end; end; end; {end of loop on js over all bonds} if (not sfound)and(ns x' write(*,*)'  0' write(*,*)'Enter the distance from 0 to top surface in Z direction % - ' if(a.eq.1) then write(6,31)diag else write(6,32)diag endif open(unit=1,file='fd3m.hyd',status='old') C set flag that B is within limits read(*,*) B BFlag=0 do while (b.LT.0.) b=b+diag bflag=1 end do do while (b.GT.diag) b=b-diag bflag=1 end do



Computer code (Makogon, 1994, 1997)

if (bflag.eq.0) then write(6,34)B else write(6,35)B endif C end of check for proper slice position input else C input slice position for sI hydrate write(*,*)'Using structure I hydrate',ietc,' slice' write(*,*)'Slice size for sI will be increased to 2x2x1' write(*,*)'Reading the unit cell data from the file pm3n.dat' write(*,*)' z ^' write(*,*)' | unit cell' write(6,30)diag write(*,*)' | |' write(*,*)' |____________|top position' write(*,*)' | ^ |' write(*,*)' | thickness |' write(*,*)' |______v_____|' write(*,*)' | |' write(*,*)' 0-|------------|---> x' write(*,*)' 0' write(*,*)'Enter the distance from 0 to top surface in Z direction % - ' if(a.eq.1) then write(6,31)diag else write(6,32)diag endif open(unit=1,file='pm3n.hyd', status='old') 30 FORMAT(F6.2,'|____________') 31 FORMAT(1X,'Choose from 0 to',F8.4,' Angstroms') 32 FORMAT(1X,'Choose from 0 to',F7.3,' Angstroms') read(*,*) B C set flag that B is within limits BFlag=0 do while (b.LT.0.D0) b=b+diag bflag=1 end do do while (b.GT.diag) b=b-diag bflag=1 end do

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if (bflag.eq.0) then write(6,34)B else write(6,35)B 34 FORMAT(1X,'Position set to ',F10.6) 35 FORMAT(1X,'Position reset to ',F10.6) endif C end of check for proper slice position input endif C write(*,*)'Enter desired slice thickness in Z direction:' read(*,*) C C read in the unit cell do i=1, npts read(1,*)ii,x1(i),y1(i),z1(i),x2(i),y2(i),z2(i), - x3(i),y3(i),z3(i) end do C ------------[111]------------------if(ap.eq.2) then C if constructing the [111] surface, the unit cell will be C replicated 12 times for slicing do 45 ix=0, nx do 45 iy=0, ny do 45 iz=0, nz do 45 i=1, npts x1(i+ix*6*npts+iy*3*npts+iz*npts)=x1(i)-ix y1(i+ix*6*npts+iy*3*npts+iz*npts)=y1(i)-iy z1(i+ix*6*npts+iy*3*npts+iz*npts)=z1(i)-iz x2(i+ix*6*npts+iy*3*npts+iz*npts)=x2(i)-ix y2(i+ix*6*npts+iy*3*npts+iz*npts)=y2(i)-iy z2(i+ix*6*npts+iy*3*npts+iz*npts)=z2(i)-iz x3(i+ix*6*npts+iy*3*npts+iz*npts)=x3(i)-ix y3(i+ix*6*npts+iy*3*npts+iz*npts)=y3(i)-iy z3(i+ix*6*npts+iy*3*npts+iz*npts)=z3(i)-iz 45 continue C determine which molecules should be sliced off in [111] do i=1,npts*12 remflag(i)=0 C check the cell in direction of equation 1: -2x+y+z=1 xyz=-x1(i)-x1(i)+y1(i)+z1(i) c correct computational error if(abs(xyz-dnint(xyz)).lt.1d-10) xyz=dnint(xyz) if(xyz.GT.1.D0) remflag(i)=1



Computer code (Makogon, 1994, 1997)

C check the cell in direction of equation 2: x-2y+z=1 xyz=x1(i)-y1(i)-y1(i)+z1(i) if(abs(xyz-dnint(xyz)).lt.1d-10) xyz=dnint(xyz) if(xyz.GT.1.D0) remflag(i)=1 C check the cell in direction of equation 3: x-2y+z=-2 xyz=x1(i)-y1(i)-y1(i)+z1(i) if(abs(xyz-dnint(xyz)).lt.1d-10) xyz=dnint(xyz) if(xyz.LE.-2.D0) remflag(i)=1 C check the cell in direction of equation 4: -2x+y+z=-2 xyz=-x1(i)-x1(i)+y1(i)+z1(i) if(abs(xyz-dnint(xyz)).lt.1d-10) xyz=dnint(xyz) if(xyz.LE.-2.D0) remflag(i)=1 C check the cell in direction of equation 5: x+y+z=1 xyz=x1(i)+y1(i)+z1(i) if(abs(xyz-dnint(xyz)).lt.1d-10) xyz=dnint(xyz) if(xyz.GT.1.D0) remflag(i)=1 C check the cell in direction of equation 6: x+y+z=-2 xyz=x1(i)+y1(i)+z1(i) if(abs(xyz-dnint(xyz)).lt.1d-10) xyz=dnint(xyz) if(xyz.LE.-2.D0) remflag(i)=1 end do C move the unremoved molecules to the front of coordinate arrays nrem=0 do i=1,npts*12 if(remflag(i).eq.0) then x1(i-nrem)=x1(i) y1(i-nrem)=y1(i) z1(i-nrem)=z1(i) x2(i-nrem)=x2(i) y2(i-nrem)=y2(i) z2(i-nrem)=z2(i) x3(i-nrem)=x3(i) y3(i-nrem)=y3(i) z3(i-nrem)=z3(i) else nrem=nrem+1 endif enddo C modify the number of molecules in [111] slice npts=npts*12-nrem C reorient the basic [111] block to align the top surface with C the x-y plane at position z=0 and with center at x=0, y=0 do i=1, npts

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C shift the block up by 1/2 unit cell to put block center at 000 z1(i)=z1(i)+0.5D0 z2(i)=z2(i)+0.5D0 z3(i)=z3(i)+0.5D0 C rotate the [111] block around Z for +45 degrees tempx=x1(i) x1(i)= x1(i)*DCOS(Pi/4.D0)+y1(i)*DSIN(Pi/4.D0) y1(i)=-tempx*DSIN(Pi/4.D0)+y1(i)*DCOS(Pi/4.D0) tempx=x2(i) x2(i)= x2(i)*DCOS(Pi/4.D0)+y2(i)*DSIN(Pi/4.D0) y2(i)=-tempx*DSIN(Pi/4.D0)+y2(i)*DCOS(Pi/4.D0) tempx=x3(i) x3(i)= x3(i)*DCOS(Pi/4.D0)+y3(i)*DSIN(Pi/4.D0) y3(i)=-tempx*DSIN(Pi/4.D0)+y3(i)*DCOS(Pi/4.D0) C rotate the [111] block around Y for -54.74 degrees D=-DACOS(1.D0/DSQRT(3.D0)) tempx=x1(i) x1(i)= x1(i)*DCOS(D)+z1(i)*DSIN(D) z1(i)=-tempx*DSIN(D)+z1(i)*DCOS(D) tempx=x2(i) x2(i)= x2(i)*DCOS(D)+z2(i)*DSIN(D) z2(i)=-tempx*DSIN(D)+z2(i)*DCOS(D) tempx=x3(i) x3(i)= x3(i)*DCOS(D)+z3(i)*DSIN(D) z3(i)=-tempx*DSIN(D)+z3(i)*DCOS(D) C rotate the [111] block around Z for -30 degrees tempx=x1(i) x1(i)= x1(i)*DCOS(-Pi/6.D0)+y1(i)*DSIN(-Pi/6.D0) y1(i)=-tempx*DSIN(-Pi/6.D0)+y1(i)*DCOS(-Pi/6.D0) tempx=x2(i) x2(i)= x2(i)*DCOS(-Pi/6.D0)+y2(i)*DSIN(-Pi/6.D0) y2(i)=-tempx*DSIN(-Pi/6.D0)+y2(i)*DCOS(-Pi/6.D0) tempx=x3(i) x3(i)= x3(i)*DCOS(-Pi/6.D0)+y3(i)*DSIN(-Pi/6.D0) y3(i)=-tempx*DSIN(-Pi/6.D0)+y3(i)*DCOS(-Pi/6.D0) C shift the block down by sqrt(3)/2 unit cell to locate top at z=0 z1(i)=z1(i)-0.5D0*DSQRT(3.D0) z2(i)=z2(i)-0.5D0*DSQRT(3.D0) z3(i)=z3(i)-0.5D0*DSQRT(3.D0) end do C end of slicing of the basic [111] block endif C ------------[100]----------------if (ap.eq.1) then



Computer code (Makogon, 1994, 1997)

C shift the [100] cell down to locate top at z=0 do i=1,npts z1(i)=z1(i)-1.D0 z2(i)=z2(i)-1.D0 z3(i)=z3(i)-1.D0 end do endif C ------------[110]------------------if (ap.eq.3) then C if constructing the [110] surface, the unit cell will be C replicated 2 times for slicing do 46 iy=0, ny do 46 i=1, npts x1(i+iy*npts)=x1(i) y1(i+iy*npts)=y1(i)-iy z1(i+iy*npts)=z1(i) x2(i+iy*npts)=x2(i) y2(i+iy*npts)=y2(i)-iy z2(i+iy*npts)=z2(i) x3(i+iy*npts)=x3(i) y3(i+iy*npts)=y3(i)-iy z3(i+iy*npts)=z3(i) 46 continue C determine which molecules should be relocated in [110] do i=1,npts*2 remflag(i)=0 C check the cell in direction of equation 1: x+y=1 xyz=x1(i)+y1(i) c correct computational error if(abs(xyz-dnint(xyz)).lt.1d-10) xyz=dnint(xyz) if(xyz.GT.1.D0) then x1(i)=x1(i)-1.D0 y1(i)=y1(i)-1.D0 x2(i)=x2(i)-1.D0 y2(i)=y2(i)-1.D0 x3(i)=x3(i)-1.D0 y3(i)=y3(i)-1.D0 endif C check the cell in direction of equation 2: x-y=1 xyz=x1(i)-y1(i) if(abs(xyz-dnint(xyz)).lt.1d-10) xyz=dnint(xyz) if(xyz.GT.1.D0) then x1(i)=x1(i)-1.D0

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y1(i)=y1(i)+1.D0 x2(i)=x2(i)-1.D0 y2(i)=y2(i)+1.D0 x3(i)=x3(i)-1.D0 y3(i)=y3(i)+1.D0 endif end do C modify the number of molecules in [110] slice npts=npts + npts C reorient the basic [110] block to align the top [110] surface with C the x-y plane at position z=0 and with center at x=0, y=0 do i=1, npts C shift the block down by 1/2 unit cell to put block center at 000 z1(i)=z1(i)-0.5D0 z2(i)=z2(i)-0.5D0 z3(i)=z3(i)-0.5D0 C rotate the [110] block around Z for +45 degrees tempx=x1(i) x1(i)= x1(i)*DCOS(Pi/4.D0)+y1(i)*DSIN(Pi/4.D0) y1(i)=-tempx*DSIN(Pi/4.D0)+y1(i)*DCOS(Pi/4.D0) tempx=x2(i) x2(i)= x2(i)*DCOS(Pi/4.D0)+y2(i)*DSIN(Pi/4.D0) y2(i)=-tempx*DSIN(Pi/4.D0)+y2(i)*DCOS(Pi/4.D0) tempx=x3(i) x3(i)= x3(i)*DCOS(Pi/4.D0)+y3(i)*DSIN(Pi/4.D0) y3(i)=-tempx*DSIN(Pi/4.D0)+y3(i)*DCOS(Pi/4.D0) C rotate the [110] block around Y for -90 degrees D=-Pi/2.D0 tempx=x1(i) x1(i)= x1(i)*DCOS(D)+z1(i)*DSIN(D) z1(i)=-tempx*DSIN(D)+z1(i)*DCOS(D) tempx=x2(i) x2(i)= x2(i)*DCOS(D)+z2(i)*DSIN(D) z2(i)=-tempx*DSIN(D)+z2(i)*DCOS(D) tempx=x3(i) x3(i)= x3(i)*DCOS(D)+z3(i)*DSIN(D) z3(i)=-tempx*DSIN(D)+z3(i)*DCOS(D) C shift the block down by sqrt(2)/2 unit cell to locate top at z=0 z1(i)=z1(i)-0.5D0*DSQRT(2.D0) z2(i)=z2(i)-0.5D0*DSQRT(2.D0) z3(i)=z3(i)-0.5D0*DSQRT(2.D0) C shift the block by 1/2 unit cell to locate edge at x=0 x1(i)=x1(i)+0.5D0 x2(i)=x2(i)+0.5D0



Computer code (Makogon, 1994, 1997)

x3(i)=x3(i)+0.5D0 C shift the block by sqrt(2)/2 unit cell to locate edge at y=0 y1(i)=y1(i)+0.5D0*DSQRT(2.D0) y2(i)=y2(i)+0.5D0*DSQRT(2.D0) y3(i)=y3(i)+0.5D0*DSQRT(2.D0) end do C end of slicing of the basic [110] block endif C correct the upper surface position C top boundary is strict, i.e. z.GE.0. is shifted. do i=1,npts z1(i)=z1(i)+(diag-B)/unitside z2(i)=z2(i)+(diag-B)/unitside z3(i)=z3(i)+(diag-B)/unitside if(z1(i).ge.0.D0) then z1(i)=z1(i)-diag/unitside z2(i)=z2(i)-diag/unitside z3(i)=z3(i)-diag/unitside endif end do C add more unit cells in height if needed nadd=0 CC=C do while (CC.gt.diag) nadd=nadd+1 do i=1,npts x1(i+nadd*npts)=x1(i) y1(i+nadd*npts)=y1(i) z1(i+nadd*npts)=z1(i)-diag/unitside*nadd x2(i+nadd*npts)=x2(i) y2(i+nadd*npts)=y2(i) z2(i+nadd*npts)=z2(i)-diag/unitside*nadd x3(i+nadd*npts)=x3(i) y3(i+nadd*npts)=y3(i) z3(i+nadd*npts)=z3(i)-diag/unitside*nadd end do CC=CC-diag end do npts=npts+npts*nadd C Correct the slice thickness to requested value. Adjust lower surface. C Lower boundary is relaxed i.e. z.LT.-C is removed do i=1,npts

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remflag(i)=0 if(z1(i).lt.(-C/unitside)) then remflag(i)=1 endif enddo nrem=0 do i=1,npts if(remflag(i).eq.0) then x1(i-nrem)=x1(i) y1(i-nrem)=y1(i) z1(i-nrem)=z1(i) x2(i-nrem)=x2(i) y2(i-nrem)=y2(i) z2(i-nrem)=z2(i) x3(i-nrem)=x3(i) y3(i-nrem)=y3(i) z3(i-nrem)=z3(i) else nrem=nrem+1 endif end do npts=npts-nrem C C C C C c C C

if desired, the unit cell will be enlarged to a NxMx1 surface size currently set to enlarge [100], [110] and [111] sI surfaces to 2x2; 2x1; 2x2 respectively. For a sII[111] surface a 2x2 enlargement is done for polymers with >8 units.

replicate molecules in xyz arrays and adjust surface parameters if(ap.eq.1.and.a.eq.1) then C for [100] (ap=1) do 461 ix=0, 1 do 461 iy=0, 1 do 461 i=1, npts x1(i+ix*2*npts+iy*npts)=x1(i)+ix y1(i+ix*2*npts+iy*npts)=y1(i)+iy z1(i+ix*2*npts+iy*npts)=z1(i) x2(i+ix*2*npts+iy*npts)=x2(i)+ix y2(i+ix*2*npts+iy*npts)=y2(i)+iy z2(i+ix*2*npts+iy*npts)=z2(i) x3(i+ix*2*npts+iy*npts)=x3(i)+ix y3(i+ix*2*npts+iy*npts)=y3(i)+iy z3(i+ix*2*npts+iy*npts)=z3(i) 461 continue



Computer code (Makogon, 1994, 1997)

npts=npts*4 side=side*2.D0 xmaxh = xmax ymaxh = ymax xmax = xmax + xmax ymax = ymax + ymax endif if(ap.eq.3.and.a.eq.1) then C for [110] (ap=3) do 462 ix=0, 1 do 462 i=1, npts x1(i+ix*npts)=x1(i)+ix y1(i+ix*npts)=y1(i) z1(i+ix*npts)=z1(i) x2(i+ix*npts)=x2(i)+ix y2(i+ix*npts)=y2(i) z2(i+ix*npts)=z2(i) x3(i+ix*npts)=x3(i)+ix y3(i+ix*npts)=y3(i) z3(i+ix*npts)=z3(i) 462 continue npts=npts + npts xmaxh= xmax xmax = xmax + xmax endif if((a.eq.1.and.ap.eq.2).or. (a.eq.2.and.ap.eq.2.and.ngroups.gt.8)) then C for [111] do 463 ix=0, 1 do 463 iy=0, 1 do 463 i=1, npts x1(i+ix*2*npts+iy*npts)=x1(i)+(ix*xmax+iy*xmaxh)/unitside y1(i+ix*2*npts+iy*npts)=y1(i)+iy*ymax/unitside z1(i+ix*2*npts+iy*npts)=z1(i) x2(i+ix*2*npts+iy*npts)=x2(i)+(ix*xmax+iy*xmaxh)/unitside y2(i+ix*2*npts+iy*npts)=y2(i)+iy*ymax/unitside z2(i+ix*2*npts+iy*npts)=z2(i) x3(i+ix*2*npts+iy*npts)=x3(i)+(ix*xmax+iy*xmaxh)/unitside y3(i+ix*2*npts+iy*npts)=y3(i)+iy*ymax/unitside z3(i+ix*2*npts+iy*npts)=z3(i) 463 continue npts=npts*4 C adjust parameters for [111] &

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10.  Research methods in flow assurance

side=side*2.D0 xmaxh = unitside * Dsqrt(2.D0) ymaxh = unitside * Dsqrt(1.5D0) xmax = 2.D0 * xmaxh ymax = 2.D0 * ymaxh C now center a [111] surface do i=1,npts x1(i)=x1(i)-xmaxh/unitside*0.75D0 y1(i)=y1(i)-ymaxh/unitside*0.5D0 x2(i)=x2(i)-xmaxh/unitside*0.75D0 y2(i)=y2(i)-ymaxh/unitside*0.5D0 x3(i)=x3(i)-xmaxh/unitside*0.75D0 y3(i)=y3(i)-ymaxh/unitside*0.5D0 end do endif C check if geometries of water molecules are still intact do i=1, npts d1=(x1(i)-x2(i))**2+(y1(i)-y2(i))**2+(z1(i)-z2(i))**2 d1=dsqrt(d1) * unitside d2=(x1(i)-x3(i))**2+(y1(i)-y3(i))**2+(z1(i)-z3(i))**2 d2=dsqrt(d2) * unitside if(d1.gt.1.1.or.d2.gt.1.1.or.d1.lt.0.9.or.d2.lt.0.9) then write(*,*)'Error in water geometry O-H bond length ',d1,d2 endif end do write(6,47)npts format(1X,'A surface consisting of',I5,' water molecules was gener %ated') write(*,*)'Top surface was placed at z=0' if (ap.eq.1) then C write(6,49)side,side,C write(6,49)xmax,ymax,C write(6,48)xmaxh,ymaxh else C write(6,49)side*sqrt(2.),side*sqrt(1.5),C write(6,49)xmax,ymax,C write(*,*)'Center of the surface is at x=0, y=0' endif 48 FORMAT('Center of the surface is at x=',F5.2,', y=',F5.2) 49 FORMAT(' Maximum surface size along axes x=',F6.2,', y=',F6.2, _', z=',F6.2) C code for writing the water box coordinates to a file surface.dat C open(unit=2,file='surface.dat',status='unknown') 47



Computer code (Makogon, 1994, 1997)

C do i=1, npts C write(2,50)i,x1(i),y1(i),z1(i),x2(i),y2(i),z2(i),x3(i),y3(i),z3(i) C end do C50 format(I3,9F8.4) C*************************************************************** C END OF THE HYDRATE SURFACE CODE

Nwatrs=npts C move the water coordinates to the water array and scale the coordinates C ... positions of oxygen atoms DO 100 I = 1, Nwatrs xw(I,3) = x1(i) * unitside yw(I,3) = y1(i) * unitside zw(I,3) = z1(i) * unitside C ... positions of hydrogens xw(I,1) = x2(I) * unitside yw(I,1) = y2(I) * unitside zw(I,1) = z2(I) * unitside C xw(I,2) = x3(I) * unitside yw(I,2) = y3(I) * unitside zw(I,2) = z3(I) * unitside 100 CONTINUE C code for writing the water box coordinates to a file surface.dat C open(unit=2,file='surface.dat',status='unknown') C do i=1, npts C write(2,50)i,xw(i,3),yw(i,3),zw(i,3),xw(i,1),yw(i,1),zw(i,1), C _ xw(i,2),yw(i,2),zw(i,2) C end do C50 format(I3,9F8.4) C C some code to print the surface positions visually on screen do 110 i=1,80 do 110 j=1,25 110 screen(i,j)=' ' if (ap.eq.1.or.ap.eq.3)then C construct a [100] or a [110] surface do 115 i=1,Nwatrs if(zw(i,3).ge.-5.D0) then C for oxygens nx=+nint(xw(i,3)*2.D0) ny=25-nint(yw(i,3)) C and for hydrogens lx=nint(xw(i,2)*2.D0) ly=25-nint(yw(i,2)) mx=nint(xw(i,1)*2.D0)

433

434

115

10.  Research methods in flow assurance

my=25-nint(yw(i,1)) if(nx.lt.1.or.nx.gt.80.or.ny.lt.1.or.ny.gt.25)goto 115 if(lx.lt.1.or.lx.gt.80.or.ly.lt.1.or.ly.gt.25)goto 115 if(mx.lt.1.or.mx.gt.80.or.my.lt.1.or.my.gt.25)goto 115 screen(lx,ly)='.' screen(mx,my)='.' screen(nx,ny)='o' endif continue screen(1,1)='2' screen(2,1)='4' screen(1,5)='2' screen(2,5)='0' screen(1,9)='1' screen(2,9)='6' screen(1,13)='1' screen(2,13)='2' screen(1,17)='8' screen(1,21)='4' screen(1,25)='0' screen(8,25)='4' screen(16,25)='8' screen(24,25)='1' screen(25,25)='2' screen(32,25)='1' screen(33,25)='6' screen(40,25)='2' screen(41,25)='0' screen(48,25)='2' screen(49,25)='4' screen(56,25)='2' screen(57,25)='8' screen(64,25)='3' screen(65,25)='2' screen(72,25)='3' screen(73,25)='6' endif

if(ap.eq.2) then C construct a [111] surface do 120 i=1,Nwatrs if(zw(i,3).ge.-5.D0) then C for oxygens nx=40+nint(xw(i,3)*2.D0) ny=13-nint(yw(i,3))



Computer code (Makogon, 1994, 1997)

C and for hydrogens lx=40+nint(xw(i,2)*2.D0) ly=13-nint(yw(i,2)) mx=40+nint(xw(i,1)*2.D0) my=13-nint(yw(i,1)) if(nx.lt.1.or.nx.gt.80.or.ny.lt.1.or.ny.gt.25)goto 120 if(lx.lt.1.or.lx.gt.80.or.ly.lt.1.or.ly.gt.25)goto 120 if(mx.lt.1.or.mx.gt.80.or.my.lt.1.or.my.gt.25)goto 120 screen(lx,ly)='.' screen(mx,my)='.' screen(nx,ny)='o' endif 120 continue screen(2,1)='1' screen(3,1)='2' screen(2,5)='8' screen(2,9)='4' screen(2,13)='0' screen(2,17)='-' screen(3,17)='4' screen(2,21)='-' screen(3,21)='8' screen(2,25)='-' screen(3,25)='1' screen(4,25)='2' screen(7,25)='-' screen(8,25)='1' screen(9,25)='6' screen(15,25)='-' screen(16,25)='1' screen(17,25)='2' screen(23,25)='-' screen(24,25)='8' screen(31,25)='-' screen(32,25)='4' screen(40,25)='0' screen(48,25)='4' screen(56,25)='8' screen(64,25)='1' screen(65,25)='2' screen(72,25)='1' screen(73,25)='6' endif C now print the constructed surface

435

436 130 135 C

10.  Research methods in flow assurance

do 130 j=1,25 write(6,135)(screen(i,j),i=1,79) format(79A) RETURN END

C C------------------------------------------------------------------C

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440

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Murowchick, J.B., Barnes, H.L., 1987. Effects of temperature and degree of supersaturation on pyrite morphology. Am. Mineral. 72, 1241. Myerson, A.S., 1993. Handbook of Industrial Crystallization. Butterworth-Heinemann, New York37. Nakahara, J., Shigesato, Y., Higashi, A., Hondoh, T., Langway Jr., C.C., 1988. Raman spectra of natural clathrates in deep ice cores. Philos. Mag. B 57, 421. Narten, A.H., Lewy, H.A., 1971. Liquid water: molecular correlation functions from X-ray diffraction. J. Chem. Phys. 55, 2263–2269. Ohmine, I., Tanaka, H., 1993. Fluctuation, relaxations, and hydration in liquid water. Hydrogen-bond rearrangement dynamics. Chem. Rev. 93, 2545. Palmer, H.A., 1950. Dissertation. U. of Oklahoma. Pratt, R.M., 1994. Ph.D. Dissertation. Colorado School of Mines. Prausnitz, J.M., et  al., 1986. Molecular Thermodynamics of Fluid-Phase Equilibria, second ed. Prentice-Hall Inc., Englewood Cliffs, N.J.. Priestley, J., 1790. Experiments and Observations on Different Kinds of air and Other Branches of Natural Philosophy Connected With the Subject in Three Volumes. T. Pearson Publisher, Birmingham. Rahman, A., Stillinger, F.H., 1973. Hydrogen-bond patterns in liquid water. J. Am. Chem. Soc. 95, 7943–7948. Rappe, A.K., Goddard, W.A., 1991. Charge equilibration for molecular dynamics simulation. J. Phys. Chem. 95, 3358. Reid, R.C., Prausnitz, J.M., Poling, B.E., 1987. The Properties of Gases and Liquids, fourth ed. McGraw-Hill, New York. Ripmeester, J.A., 1995. Conference on Natural Gas Hydrates Drilling and Development, CSM, 18–23 January, Golden. Ripmeester, J.A., Ratcliffe, C.I., 1990. 129Xe NMR studies of clathrate hydrates: new guests for structure II and structure H. J. Phys. Chem. 94, 8773. Ripmeester, J.A., et al., 1987. A new clathrate hydrate structure. Nature 325, 135. Roberts, O.L., et al., 1940. Constitution diagrams and composition of methane and ethane hydrates. Oil Gas J. 39, 37. Rodger, P.M., 1989. Cavity potential in type I gas hydrates. J. Phys. Chem. 93, 6850. Rodger, P.M., 1991. Lattice relaxation in type I gas hydrates. AIChE J 37, 1511. Rodger, P.M., 1992. In: Davies, J.E. (Ed.), Spectroscopic and Computational Studies of Supramolecular Systems. Kluwer Academic Publishers, the Netherlands, pp. 239–267. Rodger, P.M., 1994a. Towards a microscopic understanding of clathrate hydrates. Ann. N. Y. Acad. Sci. 715, 207. Rodger, P.M., 1994b. The stability of gas hydrates. J. Phys. Chem. 94, 6080. Sloan, E.D., 1990. Clathrate Hydrates of Natural Gases. Marcel-Dekker, New York. Sloan, E.D., 1996a. Personal Communication. . Golden. Sloan, E.D., 1996b. Personal Communication. . Golden. Sloan, E.D., 1996c. Personal Communication. . Golden. Smelik, E.A., King, H.E., 1997. Crystal growth studies of natural gas clathrate hydrates using a pressurized optical cell. Am. Mineral. Smirnov, L.F., Dyachenko, V.K., 1989. Method of production and storage of gas hydrates. . Pat. No. 1723407. Soper, A.K., Finney, J.L., 1993. Hydration of methanol in aqueous solution. Phys. Rev. Lett. 71, 4346–4349. Soper, A.K., Phillips, M.G., 1986. A new determination of the structure of water at 25°C. Chem. Phys. 107, 47–60. Soutar, I., Swanson, L., Thorpe, F.G., Zhu, C.Y., 1996. Fluorescence studies of the dynamic behavior of poly(dimethylacrylamide) and its complex with poly(methacrylic acid) in dilute solution. Macromolecules 29, 918. Sparks, K., 1991. Ph.D. Dissertation. Colorado School of Mines. Speedy, R.J., et al., 1987. Network topology in simulated water. J. Phys. Chem. 91, 909–913. Stillinger, F.H., Rahman, A., 1974. Improved simulation of liquid water by molecular dynamics. J. Chem. Phys. 60, 1545. Svartas, T.M., Fadnes, F.H., 1992. Methane hydrate equilibrium data for the methane-water-methanol system up to 500 Bara. In: Proceedings of the Second (1992) International Offshore and Polar Engineering Conference (June 14–19, 1992) San Francisco, USA. pp. 614–619. Tanaka, H., Kyohara, K., 1993a. On the thermodynamic stability of clathrate hydrate I. J. Chem. Phys. 98, 4098. Tanaka, H., Kyohara, K., 1993b. The thermodynamic stability of clathrate hydrate. II. Simulataneous occupation of larger and smaller cages. J. Chem. Phys. 98, 8110. Tanaka, H., Nakanishi, K., 1994. The stability of clathrate hydrates: temperature dependence of dissociation pressure in Xe and Ar hydrate. Mol. Simul. 12, 317. Tester, J.W., Bevins, R.L., Herrick, C.C., 1972. Use of Monte Carlo in calculating the thermodynamic properties of water clathrates. AIChE J. 18, 1220. Thomas, M., Behar, E., 1994. Structure H hydrate equilibria of methane and intermediate hydrocarbon molecules. In: 73rd GPA Convention, New Orleans, March 7–9.



Further reading

441

Tomisaka, S., et al., 1990. Pollution of Atmosphere and Global Warming. Safety Engineering (in Japanese). 54. 8–12. Tomoko, 1996. Personal Communication. Hokkaido University. Tse, J.S., 1994. Dynamical properties of clathrate hydrates. Ann. N. Y. Acad. Sci. 715, 187. Tse, J.S., Klein, M.L., 1987. Dynamical properties of the structure II clathrate hydrate of krypton. J. Phys. Chem. 91, 5789. Tse, J.S., Klein, M.L., 1988. A molecular dynamics study of the effect of pressure on the properties of water and ice. J. Phys. Chem. 92, 315. Tse, J.S., Klein, M.L., McDonald, I.R., 1983a. Molecular dynamics studies of ice Ic and the structure I clathrate hydrate of methane. J. Phys. Chem. 87, 4198. Tse, J.S., Klein, M.L., McDonald, I.R., 1983b. Dynamical properties of the structure I clathrate hydrate of xenon. J. Chem. Phys. 79, 2096. Tse, J.S., Klein, M.L., McDonald, I.R., 1984. Computer simulation studies of the structure I clathrate hydrates if methane, tetrafluoromethane, cyclopropane, and ethylene oxide. J. Chem. Phys. 81, 6146. Tse, J.S., Handa, Y.P., Ratcliffe, C.I., Powell, B.M., 1986. Structure of oxygen clathrate hydrate by neutron powder diffraction. J. Incl. Phenom. 4, 235. Tse, J.S., McKinnon, W.R., Marchi, M., 1987. Thermal expansion of structure I ethylene oxide hydrate. J. Phys. Chem. 91, 4188. U.S. Geological Survey, 2016. Burning gas hydrate. www.usgs.gov/media/images/burning-gas-hydratehttps:// prd-wret.s3-us-west-2.amazonaws.com/assets/palladium/production/s3fs-public/thumbnails/image/gas_ hydrate_flame_loop.gif. accessed 3 Jan 2019. van de Waal, B.W., 1996. Cross-twinning model of fcc crystal growth. J. Cryst. Growth 158, 153. van der Waals, J.H., Platteeuw, J.C., 1959. Clathrate solutions. Adv. Chem. Phys. 2, . van Hinsberg, M.G.E., Verbrugge, R., Schouten, J.A., 1993. High temperature-high pressure experiments on H2ON2. Fluid Phase Equilib. 88, 115. Verlet, L., 1967. Computer “experiments” on classical fluids. I. Thermodynamical properties of Lennard-Jones molecules. Phys. Rev. 159, 98. Vos, W.L., Finger, L.W., Hemley, R.J., 1993. Novel H2-H2O clathrates at high pressures. Phys. Rev. Lett. 71, 3150–3153. Wagner, R.S., 1960. On the growth of Germanium dendrites. Acta Metall. 8, 57. Letters to the editor. Wallqvist, A., 1991. Molecular dynamics study of hydrophobic aggregation in water/methane/methanol systems. Chem. Phys. Lett. 182, 237. Wallqvist, A., 1992. On the stability of type I gas hydrates in the presence of methanol. J. Chem. Phys. 96, 5377–5382. Wallqvist, A., 1994. Computer simulations of type I gas hydrates in presence of methanol. Ann. N. Y. Acad. Sci. 715, 540. Ward, Z.T., Deering, C.E., Marriott, R.A., Sum, A.K., Sloan, E.D., Koh, C.A., 2015. Phase equilibrium data and model comparisons for H2S hydrates. J. Chem. Eng. Data 60(2), 403–408. Yamal, 2015. http://siberiantimes.com/PICTURES/SCIENCE/Yamal-crater-November-2014/Yamal-craterBogoyavlensky/inside_yamal_hole_gv_bogoyavl.jpg (Accessed 4/29/2015). Westacott, R.E., Rodger, P.M., 1994. Direct free energy calculations for clathrate hydrates. Ann. N. Y. Acad. Sci. 715, 537. Zajac, R., Chakrabarti, A., 1994. Kinetics and thermodynamics of end-functionalized polymer adsorption and desorption processes. Phys. Rev. E 49 (pt. A), 3069. Zazzera, L., Tirrell, M., Evans, J.F., 1993. In situ study of poly(methyl methacrylate) adsorption from solution onto chemically modified Si(100) surfaces by internal reflection infrared spectroscopy. J. Vac. Sci. Technol. 11, 2239. Zhan, Y., Mattice, W.L., Napper, D.L., 1993. Monte Carlo simulation of the adsorption of diblock copolymers from a nonselective solvent. I. Adsorption kinetics and adsorption isotherms. J. Chem. Phys. 98, 7502.

Further reading BIOSYM software, 1994. BIOSYM Technologies, Inc., San Diego, CA. Buerger, M.J., 1960. Crystal-Structure Analysis. Wiley, New York. Englezos, P., et al., 1992. Atmospheric climate changes and the stability of the in-situ methane hydrates in the Arctic. In: Proceedings of the Second (1992) International Offshore and Polar Engineering Conference (June 14–19, 1992), San Francisco, USA. pp. 644–652.

442

10.  Research methods in flow assurance

Handa, Y.P., et al., 1992. Structural transition of xenon and krypton as a function of gas composition. J. Phys. Chem. 94, 4363–4365. HyperChem. AUTODESK, Inc., Sausalito, CA. Kvenvolden, K.A., 1993a. International Conference on Natural Gas Hydrates. Abstracts. (June 20–24, 1993) The New York Academy of Sciences. 12. Kvenvolden, K.A., 1993b. Worldwide distribution of subaquatic gas hydrates. Geo-Mar. Lett. 13, 32–40. Sloan Jr., E.D., 1990. Clathrate Hydrates of Natural Gases. Marcel Dekker, New York. SYBYL software, 1994. Tripos Associates, Inc., St. Louis, MO.

C H A P T E R

11 Toolkit O U T L I N E Free modeling tool for hydrate stability calculation

Free modeling tool for scale stability 443

Free modeling tool for chemical injection distribution system 443 Free modeling tool for single phase fluid flow use for water injection system 444

444

Free hydrate plug remediation software 447 Free LNG cryogenic heat exchangers solids deposition

448

Free gas, gas condensate and LNG thermodynamic property calculator 448

There is a number of software tools which have been made available to public domain through partial funding by the USA Government or other entities. These software tools are free as of the date of publication.

Free modeling tool for hydrate stability calculation Software for hydrate stability calculation is available from the Colorado School of Mines Center for Research on Hydrates as shown in Fig. 11.1. The software is appropriate and sufficiently accurate for hydrate prediction in systems with moderate pressure and salinity. The software is available at: http://hydrates.mines.edu/CHR/Software_files/CSMHyd. zip. It can run under Windows 10 (with right click—Properties-Compatibility-Windows XP enabled) or earlier operating systems.

Free modeling tool for chemical injection distribution system The EPANET2 single phase hydraulic network analysis tool is available from United States Environmental Protection Agency.

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11. Toolkit

FIG. 11.1  Hydrate stability and inhibitor dosage software.

The tool is designed for use with water distribution networks as shown in Fig. 11.2. As it provides the ability to update fluid viscosity, it can be used for chemical injection distribution system analysis. Frictional pressure drop is evaluated with the HazenWilliams, Darcy-Weisbach, or Chezy-Manning methods. The model also has many additional capabilities such as chemical growth or decay reaction in the flowing fluid, pump curves, etc. The software allows to model chemical injection into the fluid stream and track chemical concentration in the network, and is available at: https://www.epa.gov/water-research/ epanet

Free modeling tool for single phase fluid flow use for water injection system The EPANET2 tool may also be used for single phase flow networks as shown in Fig. 11.3. The software is available at: https://www.epa.gov/water-research/epanet

Free modeling tool for scale stability PHREEQC water ion saturation analysis tool is available from United States Geological Survey as shown in Fig. 11.4.



Free modeling tool for scale stability

445

FIG. 11.2  Example of EPANET2 network flow tool (United States Environmental Protection Agency).

FIG. 11.3  Example of EPANET2 tool use for water injection network (United States Environmental Protection Agency).

446

11. Toolkit

FIG. 11.4  Scale mineral solubility software.

The tool calculates scale saturation index for the following minerals: CaSO4 Aragonite BaSO4 CaCO3 SrSO4 CO2 CaMg(CO3)2 Fe(OH)3 FeOOH CaSO4*2H2O NaCl Fe2O3 FeSO4*7H2O FeCO3 SrCO3 KCl BaCO3 as well as scale mass fraction, water density, water activity and ionic strength.



Free hydrate plug remediation software

447

The software is available at: https://wwwbrr.cr.usgs.gov/projects/GWC_coupled/ phreeqc/ or https://www.usgs.gov/software/phreeqc-version-3 Several flow assurance packages from the University of Western Australia are described in www.fsr.ecm.uwa.edu.au/what-we-do/software/ including.

Free hydrate plug remediation software HyPRISM allows components up to C70+ and calculates hydrate, oil and gas and properties at the user-specified P and T and the P and T of hydrate stability as shown in Fig. 11.5. HyPRISM also calculates the pressure in the system after dissociation of hydrate to help determine if it is safe to heat up a closed system containing hydrate. Software is available at: www.fsr.ecm.uwa.edu.au/wp-content/uploads/2017/10/ HyPRISM.zip

FIG. 11.5  Hydrate plug remediation model.

448

11. Toolkit

Free LNG cryogenic heat exchangers solids deposition CryoFAST estimates risk of deposition for hydrocarbon solids such as solid hexane in cryogenic heat exchangers as shown in Fig. 11.6. Software is available at: www.fsr.ecm.uwa.edu.au/wp-content/uploads/2017/10/ CryoFAST.zip

Free gas, gas condensate and LNG thermodynamic property calculator Thermofast allows components up to C19 and calculates oil and gas properties at the ­user-specified P and T as shown in Fig. 11.7. Software is available at: www.fsr.ecm.uwa.edu.au/wp-content/uploads/2018/07/ ThermoFAST-FULL.zip

FIG. 11.6  LNG process solid deposition software.



Free gas, gas condensate and LNG thermodynamic property calculator

FIG. 11.7  Fluid PVT flash property calculation software.

449

C H A P T E R

12 Flow assurance modeling Flow assurance model relies on system description including • Reservoir characterization • PVT fluid characterization • Material characteristics The sequence of flow assurance modeling in time follows the exploration process. 1. At the time of selection of region for exploration, find analog fluids to estimate properties. – Only analog fluids may be available for flow assurance study. estimate density ±10°API. estimate viscosity @ T_reservoir ±10 cP. estimate wax appearance temperature ±20 °C. estimate rock material and consolidation. limited understanding about porosity, permeability, aquifer presence and strength, water composition, GOR, hydrate, asphaltene, etc. Appropriate flow assurance work at this stage: none. What minimum work could be done: – estimate hydrate curve based on guessed GOR and analog composition, using PVT modeling tools. – estimate scale tendency based on analog water composition. – estimate wax appearance temperature based on analog fluid. – estimate asphaltene tendency based on deBoer plot and/or SARA ratio. – prepare a list of flow assurance laboratories and chemical supplier candidates. 2. By the time exploration well is in place. – First fluids are available Measure P_res, P_sat, GOR, density, viscosity, AOP, WAT, SARA; Limited understanding about aquifer pressure support strength, reservoir compartmentalization, water composition. Basic understanding of wax, asphaltene onset pressure, GOR, hydrate conditions, porosity, permeability, fines and sand from side core plugs.

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12.  Flow assurance modeling

Appropriate flow assurance work at this stage: Line sizing and preliminary routing using a steady state flow tool, insulation requirement to avoid wax/hydrate for steady state flow in early or late life. Erosion velocity limits for mid life plateau production and for late life with increased gas. Identify flow assurance threats (slugging in early or late life, hydrate, asphaltene, wax, scale, diamondoids. 3. Appraisal well is in place and flow test performed. – More live fluids are available for tests. – Possibly a drill stem test. Obtain water composition, sufficient oil sample for hydrate plugging evaluation, asphaltene deposition. Some understanding of reservoir compartmentalization. Limited understanding about aquifer. Appropriate flow assurance work: Concept evaluation. Line sizing update, using multiphase flow models for transient analysis. Wells placement, flowlines layout, rock consolidation which determines well ramp-up time. Develop several concepts with transient analysis (startup based on ramp-up for one well, cooldown shutdown, blowdown separator sizing, slugging separator sizing. 4. Concept selection Decide on host facility as FPSO, semi-submersible, spar, island, etc. based on country risks. Decide on water injection program. Decide on gas lift or boosting based on NPV of incremental fluids recovery vs. capex and opex. Appropriate flow assurance work: Evaluate technical possibility of mitigating flow assurance threats (slugging in early or late life, reservoir souring from water injection). Erosion velocity limits in risers or flowlines for gas lift. Network flow analysis using flow model for steady state flow rates and or transient multiphase flow simulators for transient startup and shutdown sequencing. Support of operating procedures development.

C H A P T E R

13 Risk analysis O U T L I N E Introduction

453

Project cost optimization CapEx vs OpEx 453 Historic frequency of blockages based on remediation 453

Modeling dynamic behavior

454

Integration of various precipitation phenomena

454

Impact on overall planning

454

Introduction Several operator companies are migrating their project development approach from flow assurance issues prevention to issue risk probability management. This approach allows to defer cost for the facility development while possibly increasing the operating cost and difficulty.

Project cost optimization CapEx vs OpEx Projects tend to be CapEx-lean and OpEx heavy due to the uncertainty in reservoir performance. If reservoir is a strong producer and the produced commodity market is expected to be strong, then additional facilities may be developed.

Historic frequency of blockages based on remediation The risk-based approach to flow assurance relies on historic frequency of blockages to forecast the future probability of a blockage. Historic blockage frequencies and trends were presented in Chapter 5.

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13.  Risk analysis

Modeling dynamic behavior Probabilities of individual flow assurance issues should be tabulated along with the impact of such an event. Individual risks should be integrated in a dynamic field development model to evaluate a range of probabilistic scenarios for reaching the target profitability performance for the field. Time-dependent events such as aquifer water breakthrough or injection water breakthrough should be reflected by the increased risk to project performance. After the project starts, with time, more understanding of the relative weights and consequences for individual flow assurance risks becomes available. Risk based model should be kept updated to both optimize the risk evaluation for the existing field and to serve as probability basis for the future fields.

Integration of various precipitation phenomena All flow assurance and production chemistry issues should be evaluated simultaneously. The likelihood of one issue may increase the probability of a different issue. An example from a West African subsea tieback operation shows that a wax deposition risk was not managed and wax was allowed to deposit and remain in the pipe as it was not causing a significant hydraulic resistance to flow. A hydrate plug then formed, became solid. During pressure changes attempting to resolve the blockage, the hydrate plug became mobile and scraped wax off the pipe wall like a pig, compacting it into a secondary blockage. While hydrate could be dissociated by depressurization, the paraffin blockage could not. This caused a significant downtime to gradually dissolve the paraffin blockage with a solvent. A similar example from USA deepwater shows a flowline where asphaltene was allowed to deposit, which provided local restrictions in the pipe cross-section and promoted hydrate accumulation and blockage.

Impact on overall planning The combined field development plan should be prepared with input from and interaction with flow assurance and production chemistry specialists, as well as corrosion engineers. A systematic approach to risk analysis of the individual flow assurance issues and their integration in a field development model can be used to support investment decisions.

C H A P T E R

14 Case studies/reference material O U T L I N E PVT gas properties

455

Advanced flow assurance fluid properties 463

Abbreviations and definitions

460

Flow correlations

464

Monitoring and instrumentation for flow assurance

465

Units and conversions

465

Standard temperature and pressure

467

Regulatory requirements and environmental law which may affect flow assurance

460

Pipe roughness

463

Sample requirements

463

PVT gas properties We present several tables with properties evaluated with PR78 EoS for methane, lean gas, rich gas and retrograde gas as shown in Tables 14.1–14.4. The properties include density, viscosity and Z-factor for compressibility, and aim both to illustrate how these properties vary in different fluid types and to serve as initial estimate values for a gas of similar gravity. Gas gravity is relative to air density 1.225 kg/m3. Methane, gravity = 0.554. Lean gas, gravity = 0.588. Components: nitrogen, H2S, methane, ethane, propane, hexane; 4.283, 0.0001, 92.41, 3.242, 0.036, 0.023 mol Rich gas, gravity = 0.995. Components: nitrogen, CO2, H2S, methane, ethane, propane, iC4, nC4, iC5, nC5, hexane, heptane; 0.13, 3.5, 4.9, 46.4, 21.4, 16.9, 1.8, 3.8, 0.49, 0.47, 0.16, 0.003 mol Gas from volatile oil/retrograde condensate, gravity = 0.787. Components: nitrogen, CO2, methane, ethane, propane, iC4, nC4, iC5, nC5, hexane, heptane; 0.93, 0.32, 71.9, 14.4, 7.6, 0.82, 2.2, 0.47, 0.6, 0.42, 0.2, 0.05 mol

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14.  Case studies/reference material

TABLE 14.1  Variation of methane properties with temperature and pressure Density, kg/m3

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.7178

0.6788

0.606

0.5244

0.4622

50

41.22

37.92

32.49

27.18

23.51

100

92.25

82.58

68.16

55.48

47.31

200

184.8

166.5

136.7

109.9

92.84

500

301.5

286.8

257.2

222.0

194.72

1000

369.5

359.4

338.0

309.7

284.74

2000

–

416.9

402.8

383.3

365.0

Viscosity, cP

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.0102

0.0107

0.01179

0.01327

0.01467

50

0.01105

0.01147

0.01239

0.0137

0.01492

100

0.01348

0.01351

0.01396

0.01491

0.01593

200

0.0213

0.01969

0.0181

0.01779

0.01822

500

0.04052

0.03698

0.03119

0.02641

0.02423

1000

0.06317

0.05843

0.04985

0.04087

0.03484

2000

–

0.09363

0.08134

0.06781

0.05758

Z factor

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.9972

0.9976

0.9984

0.9991

0.9995

50

0.8682

0.8928

0.931

0.9637

0.9826

100

0.7758

0.8201

0.8876

0.9444

0.9767

200

0.7744

0.8136

0.8849

0.9537

0.9954

500

1.187

1.181

1.176

1.18

1.186

1000

1.937

1.884

1.79

1.692

1.623

2000

–

3.249

3.004

2.734

2.532



457

PVT gas properties

TABLE 14.2  Variation of lean gas properties with temperature and pressure Density, kg/m3

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.7623

0.7209

0.6435

0.5569

0.4909

50

43.91

40.37

34.55

28.89

24.97

100

98.49

88.03

72.54

58.96

50.25

200

196.5

176.9

145.3

116.7

98.53

500

318.1

302.7

271.7

234.7

205.97

1000

389

378.4

356.1

326.5

300.34

2000

–

438.3

423.7

403.3

384.2

Viscosity, cP

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.01048

0.011

0.01211

0.01363

0.01506

50

0.01137

0.0118

0.01274

0.01408

0.01533

100

0.01393

0.01394

0.01437

0.01533

0.01637

200

0.02221

0.02046

0.01871

0.01833

0.01874

500

0.04212

0.03843

0.03236

0.02732

0.025

1000

0.06546

0.06056

0.05166

0.04234

0.03606

2000

–

0.09686

0.08413

0.07015

0.05959

Z factor

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.9971

0.9976

0.9984

0.9991

0.9995

50

0.8654

0.8906

0.9297

0.9631

0.9823

100

0.7717

0.8169

0.8857

0.9436

0.9765

200

0.7738

0.8129

0.8844

0.9539

0.996

500

1.195

1.188

1.182

1.186

1.191

1000

1.954

1.9

1.804

1.704

1.634

2000

–

3.281

3.033

2.759

2.554

458

14.  Case studies/reference material

TABLE 14.3  Variation of rich gas properties with temperature and pressure Density, kg/m3

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

1.289

1.218

1.086

0.9391

0.8272

50

70.91

72.82

73.92

55.23

45.5

100

–

–

204.7

126.9

97.6

200

–

–

–

252.7

197.1

500

–

–

–

399.3

354.2

1000

–

–

–

–

453.9

2000

–

–

–

–

533.6

Viscosity, cP

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.009187

0.009678

0.01074

0.01223

0.01366

50

0.01148

0.01186

0.01255

0.0134

0.01456

100

–

–

0.0256

0.01728

0.01702

200

–

–

–

0.03102

0.02456

500

–

–

–

0.05883

0.04665

1000

–

–

–

–

0.07412

2000

–

–

–

–

0.1189

Z factor

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.9917

0.9929

0.9949

0.9968

0.9979

50

0.7168

0.7167

0.7311

0.8475

0.9071

100

–

–

0.5281

0.7379

0.8457

200

–

–

–

0.7407

0.8377

500

–

–

–

1.172

1.165

1000

–

–

–

–

1.819

2000

–

–

–

–

3.094



459

PVT gas properties

TABLE 14.4  Variation of volatile oil / retrograde condensate properties with temperature and pressure Density, kg/m3

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

1.02

0.9648

0.8609

0.7446

0.6565

50

59.83

57.74

50.72

40.79

34.58

100

206

157.9

116.8

87.12

71.47

200

317.4

288

231

175.6

143.1

500

–

–

361

316.4

278.7

1000

–

–

–

405

376.8

2000

–

–

–

475.7

457.1

Viscosity, cP

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.009451

0.009937

0.01098

0.01244

0.01382

50

0.01109

0.01138

0.01208

0.01325

0.01445

100

0.02586

0.01847

0.01563

0.01542

0.0161

200

0.04581

0.03874

0.02811

0.0219

0.02041

500

–

–

0.05382

0.04157

0.03421

1000

–

–

–

0.06635

0.05493

2000

–

–

–

0.1069

0.09058

Z factor

Temperature, °C

Pressure, atm

0

15.56

50

100

150

1

0.9945

0.9953

0.9967

0.998

0.9988

50

0.7671

0.7886

0.8444

0.9105

0.9476

100

0.492

0.5982

0.7341

0.8527

0.9172

200

0.6435

0.6698

0.7446

0.8483

0.9212

500

–

–

1.197

1.183

1.184

1000

–

–

–

1.848

1.752

2000

–

–

–

3.146

2.887

460

14.  Case studies/reference material

Gas phase envelopes 300 METHANE LEAN GAS RICH GAS RETROGRADE

250

Pressure (atm)

200 C

150

100

C C C

50

0 –200

–150

–100

–50

0 50 100 Temperature (°C)

150

200

250

300

FIG. 14.1  Comparison of phase envelopes for methane, lean gas, rich gas, and retrograde fluid.

The difference of retrograde fluid may be seen in the location of its critical point, where liquid and vapor densities are the same, on the P-T graph, being on the low temperature side of the phase envelope as shown in Fig. 14.1.

Abbreviations and definitions Commonly used abbreviations, acronyms, and definitions as as well as some of the industry standards applicable to flow assurance are are shown in Tables 14.5 and 14.6.

Regulatory requirements and environmental law which may affect flow assurance Regional regulatory requirements have to be identified at the project consideration stage because of their high impact on the project. A list of applicable regulatory requirements have to be included as a list in the basis of design document. Examples of requirements that may affect flow assurance include: • • • •

Guidelines or restrictions on production and chemical use methods Guidelines on use of gas gradient for shut-in tubing pressure calculation Imposed chemical restrictions or toxicity limits Waste management/handling regulations



Regulatory requirements and environmental law which may affect flow assurance

461

TABLE 14.5  Abbreviations, acronyms, and definitions Acronym or name

Description

AA

Anti-agglomerant chemical

AAPG

American Association of Petroleum Geologists

AI

Asphaltene inhibitor chemical

AOP

Asphaltene onset pressure

ARN

Tetra-carboxylic naphthenic acid (old Norwegian arn, eagle)

Blockage

A restriction impermeable to flow

BOD

Basis of design

CI

Corrosion inhibitor chemical

CPM

Cross-polarized microscope

D

Diameter

Deepwater

Projects in water deeper than 1000 ft

DEH

Direct electrical heating

DF

Defoamer chemical

DSC

Differential scanning calorimeter

DSP

Decision support package

DTHYD

Difference between hydrate stability and ambient temperature

EB

Emulsion breaker chemical

EtOH

Ethyl alcohol chemical

FBHP

Flowing bottomhole pressure

FBHT

Flowing bottomhole temperature

FIV

Flow induced vibration

FWHP

Flowing wellhead pressure

FWHT

Flowing wellhead temperature

GOR

Gas oil ratio

GUTS

Grand unified thermodynamic simulator software

HPHT

High pressure high temperature

HTGC

High temperature gas chromatograph

JT

Joule-Thomson cooling effect

KHI

Kinetic hydrate inhibitor chemical

LDHI

Low dosage hydrate inhibitor chemical (KHI or AA)

MAOP

Maximum allowable operating pressure Continued

462

14.  Case studies/reference material

TABLE 14.5  Abbreviations, acronyms, and definitions—Cont’d Acronym or name

Description

MARS

Multiple Application Reinjection System intervention interface for trees

MEG

Mono ethylene glycol chemical

MEOH

Methyl alcohol (methanol) chemical

NORM

Naturally occurring radioactive materials, such as strontium sulfate scale

PLET

Pipeline end termination

PPD

Pour point depressant chemical

PVT

Pressure volume temperature

Q

Flow rate

Restriction

Accumulation of material in a flow channel limiting flow

ROV

Remotely operated vehicle

Safe-out time

Time after a shut-in required to bring the system to a condition safe from flow assurance threats arising from cooling to ambient, e.g. by displacement, depressurization, heating or chemical treatment.

SCSSV

Surface-controlled subsurface safety valve

SGN

Nitrogen generation system

SI

Scale inhibitor

SITP

Shut in tubing pressure

SME

Subject matter expert

SOP

Site operating procedure

TDS

Total dissolved solids

TEG

Triethyleneglycol chemical

THPS

Tetrakis (hydroxymethyl) phosphonium sulfate biocide chemical

TSS

Total suspended solids

VIT

Vacuum-insulated tubing

WAT

Wax appearance temperature

• • • • • • • •

Discharge fluid property requirements Flaring restrictions and requirements Local content requirements for labor and materials Automated valve closure requirements such as HIPPS Maintenance, inspection and testing frequency requirements Metering and calibration requirements Guidelines or restrictions on handling of produced water Restrictions on injection at or above reservoir fracture pressure



463

Advanced flow assurance fluid properties

TABLE 14.6  Some of the industry standards applicable to flow assurance Document No.

Description

API 17TR14

Flow Assurance Considerations in Subsea Production Systems

API 17TR5

Avoidance of Blockages in Production Control Systems

API 17TR6

Attributes of Production Chemicals in Subsea Production Systems

API 17 TR13

General Overview of Subsea Production Systems—Section 10.8 HIPPS

API 17O

Recommended Practice for High Integrity Pressure Protection Systems (HIPPS)

ASME B31.3

Process Piping, ASME Code for pressure piping, An American National Standard

Pipe roughness Typical roughness of pipe materials is shown in Table 14.7.

Sample requirements Usual samples required for basic flow assurance analysis are shown in Table 14.8.

Advanced flow assurance fluid properties Fluid properties required for more advanced flow assurance analysis are shown in Table 14.9. TABLE 14.7  Pipe roughness Material

Roughness, microns

Carbon steel, low-carbon steel

45

Stainless steel (hot rolled)

450

Stainless steel (cold drawn)

40

Duplex stainless steel

40

Glass-lined carbon steel (new)

5

Glass-lined carbon steel (old)

50

Galvanized carbon steel

150

Epoxy lined pipe

150

Fiber pipe, plastic pipe

15

Glass reinforced epoxy

5

Titanium

45

464

14.  Case studies/reference material

TABLE 14.8  Basic sample requirements for flow assurance analysis Black oil

Compositional analysis to C36+ with C7-C9 aromatics broken out Constant composition expansion at reservoir temperature Constant composition expansion at wellhead temperature and at temperature between wellhead and reservoir (optional) Differential liberation Oil viscosity Separator test

Volatile oil

Compositional analysis to C36+ with C7-C9 aromatics broken out Constant composition expansion at reservoir temperature Constant composition expansion at wellhead temperature and at temperature between wellhead and reservoir (optional) Differential liberation and/or constant volume depletion Oil viscosity Separator test

Retrograde condensate

Compositional analysis to C36+ with C7-C9 aromatics broken out Constant composition expansion at reservoir temperature Constant composition expansion at wellhead temperature and at temperature between wellhead and reservoir (optional) Constant volume depletion Oil viscosity of separator liquid at reservoir temperature (optional)

Wet and dry gases

Compositional analysis

TABLE 14.9  Advanced fluid properties required for flow assurance analysis Advanced fluid properties for flow assurance

Dead oil WAT Dead oil HTGC Dead oil pour point Dead oil gel strength Live oil high pressure CPM Live oil AOP isothermal depressurization Dead oil refractive index with n-C5/n-C7 titration Dead oil viscosity as a function of temperature Live oil viscosity as a function of temperature H2S, CO2 and mercaptan content Mercury, Arsenic, Selenium metals content Total acid number Total base number Dead oil ARN acid content Connate water composition, especially barium content Water TDS Sulfur content in oil

Flow correlations Pressure drop in single phase liquid turbulent flow. Darcy's equation. Pressure drop in gas flow. Panhandle equation.



465

Units and conversions

Gravity driven flow is characterized by Froude (pronounced fru:d) formula Fr = v/(g D)^0.5. Fr  12 mist. Froude allows an important insight at energies of entrainment and deposition. V = 2√gD is a transition where flowing gas starts to entrain liquid. This may be of use for TOLC corrosion inhibition. Flow correlations applicability to vertical or horizontal flow is shown in Table 14.10.

Monitoring and instrumentation for flow assurance Possible locations for produced fluids monitoring instrumentation are shown in Table 14.11.

Units and conversions Acceleration of gravity (standard) near 45° latitude; gravity near equator is 0.25% less and gravity in polar regions is 0.25% more. g = 32.17 ft/s2 = 9.807 m/s2 Avogadro's number NA = 6.023 * 1023 molecules/g-mole Newton's conversion constant gc = 32.17 lbm-ft/lbf s2 = 1.000 kg m/N s2 TABLE 14.10  Flow correlations applicability to vertical or horizontal flow Near-vertical liquid dominated flow

Inclined liquid Near-horizontal Near-vertical Near-horizontal dominated liquid gas dominated gas dominated flow dominated flow flow flow

Ansari

+

−

+

−

−

Beggs and Brill

+

+

+

+

+

Duns & Ross

+

+

+

+

+

Govier, Aziz and Forgasi

+

+

+

+

+

Gray

−

−

+

−

−

Hagedorn and Brown

+

−

+

−

−

Mukherjee and Brill

+

+

+

+

+

Oliemans

−

−

−

+

+

Orkiszewski

+

−

+

−

−

466

14.  Case studies/reference material

TABLE 14.11  Possible locations of instrumentation for fluids conditions monitoring

Temperature Reservoir

Pressure

Downhole T, Distributed (fiber) temperature

Downhole pressure

Tree

Yes

Yes—standard equipment upstream and downstream of the tree choke

Jumper

Yes

Manifold

Yes Yes

Distributed (fiber) temperature

Riser Topsides

Composition GC

Water injection or producer wells may be converted into monitoring wells

Wellbore

Flowline

Sand/ acoustic

Resistivity corrosion monitor or coupon

Yes

Export line

Yes onshore Riser base pressure

Yes

Yes

Yes

Yes at each end

Heat of fusion of water at 1 atm, 0 °C 79.7 cal/g = 144 Btu/lbm Heat of vaporization of water at 1 atm, 100 °C 540 cal/g = 972 Btu/lbm 1 J/kg K = 2.3886 * 10−4 Btu/lbm °F 1 cal = 4.184 J 1 Btu = 1055 J 1 N = 1 kg m/s2 1 N = 100,000 dyne 1 N = 0.22481 lbf 1 N = 0.1019501 kgf 1 psi = 6894.73 Pa 1 psi = 0.07029264 kg/cm2 1 kg/cm2 = 98,066 Pa 1 Pa = 1 N/m2 1 Pa = 1 kg/(m s2) 1 Pa = 1.01973E-05 kg/cm2 1 bar = 100,000 Pa

Yes onshore

Yes

Online Gas chromatograph



Standard temperature and pressure

467

1 atm = 101,325 Pa 1 Torr = 1 mmHg 1 atm = 760 mmHg 1 ft = 0.3048 m 1 ft = 12 in 1 mile = 5280 ft 1 Nautical mile = 1852 m 1 US offshore block = 9 sq. Nautical miles 1 acre = 43,560 sq. ft 1 W/(m2 K) = 0.1761 Btu/(h ft2 °F) 1 W/(m K) = 0.57782 Btu/(h ft °F) 1 W = 1 J/s = 3.4123 Btu/h 1 kg = 2.2046 lbm 1 pound = 16 oz = 453.592 g 1 ton = 1000 kg 1 US ton = 907.185 kg 1 imperial ton = 1016.05 kg 1 m3 = 6.2898 bbl 1 bbl = 158.987 L = 0.158987 m3 1 bbl = 9702 in3 1 gal = 3.78541 L 1 gal = 231 in3 1 gal = 4 quarts = 8 pints = 128 fluid ounces = 768 teaspoons 1 L = 1000 cm3 1 m3 = 1000 L = 35.3134 ft3 1 cP = 0.001 Pa s

Standard temperature and pressure There is no internationally accepted standard for STP. In 1980 GPA adopted 15 °C, 101.3250 kPa (abs) as standard conditions for SI units. Thus standard molar volumes are: 23.645 std. m3/kmol at 15 °C (288.15 K), 101.3250 kPa GPA SI standard conditions. 379.49 std. ft3/lb. mol at 60 °F (519.67 °R), 14.696 psia.

Index Note: Page numbers followed by f indicate figures and t indicate tables.

A Acrolein, 177 Activity coefficients, 174, 180 Alcohol chemical, 128 hydrate, 294 prevent hydrate formation, 233 thermodynamic inhibitors, 111, 233, 287 American Association of Petroleum Geologists (AAPG), 461–462t American Petroleum Institute, 12 Anionic surfactants, 287 Anti-agglomerant (AA) chemical, 114, 193, 461–462t Anti-bacterial coating, 91 Artificial lift method, 206, 207t, 214 Asphaltene dispersant, 144, 147, 193 Asphaltene instability test (ASIST) method, 142–143, 147 Asphaltenes, 36 chemical structure, 141 deposition, 144 enhanced oil recovery, 143 environmental impact of, 146 gas condensate, 143 inhibitor, 193 irreversible thermodynamics, 147 light oil effect, 143 mass fractions, 159 microbubble capture, role, 144 monitoring, 145–146 precipitation, 142–144 prevention of, 147–148 remediation of, 146 remote sensing of, 145–146 reservoir, 141–142 reversible thermodynamics, 146 wellbore plugging, 141–142 ASTM D97 test, 194

B Bacterial deposit, 36 Bacterial growth management, 148–149 periodic biocide treatment, 148 water injection wells, 148 Barium sulfate, 10, 41t, 178–181



Barocel differential electronic manometer, 237 Bench scale tests, 342–343 Biodegradation, 65 BIOSYM®, 252 Biotechnology, gas hydrates in, 225 Black oil, 464t Blockages, 453–454. See also Hydrate blockage chemical tubing, 200 extreme cases, 15–16 natural gas production, 20 in onshore wells, 16 production monitoring tools correlations, 89 software, 89 remediation plan, 42 Boiling point analysis, 52–53 Boltzmann constant, 173 Bravais Friedel Donnay Harker method, 295 Brownian diffusion, 158–159

C Calcium cabonate, 10, 178, 180 Calcium naphthenate, 197 Calcium sulphate, 296 CapEx and OpEx, 452 Carbonate, 178 Carbon dioxide disposal at ocean bottom, 225, 226f greenhouse effect, 223–224, 224–225f, 282 Carbon steel pipelines, 23, 149 Cationic surfactants, 287 Cavity radial distribution function (CRDF), 294 Cerius2 program, 295–296 CGR. See Condensate-gas ratio (CGR) CHARMm software, 296 Chemical delivery system, 13, 13–14t Chemical injection distribution system, EPANET2 tool, 443–444, 445f Chemical injection systems, 194 Chemical potential, 245–247, 293–294, 336 Chemical tubing blockage, 200 Chilly choke conditions, 84 Clathrate hydrates. See also Gas hydrates characteristics, 297, 298t cold-storage process, 284

469

470 Index Clathrate hydrates (Continued) computer modeling at CSM, 313 crystal growth (see Hydrate crystal growth) forms of, 282 structure H, 285 structure I, 284 structure II hydrate, 284 hydrate growth, 294–296 kinetic inhibitors and computer modeling, 280 interaction between, 280 pressure and temperature, 280 THF hydrate crystal, 280 separation techniques, 284 size, 284 thermodynamic properties, 292 translational and vibrational spectra, 293 Clausius-Clapeyron equation, 233, 235 Cleanliness, production chemicals, 192 Cloud point, 60 Cold filter plug, 60 Cold finger, 60, 342 Cold flow method, 207–208 Cold-storage process, 284 Commercial software packages, 295 Compatibility, production chemicals, 192 Computer coded program counting H bonded rings in water, 346–367 generating radial distribution function in water, 343–346 Monte Carlo program for polymer adsorption on hydrate, 367–436 Concentration, production chemicals, 192–193 Condensate-gas ratio (CGR), 151 Conference in Brussels on the Global Environment, 282 Consistency, production chemicals, 192 Core flood test, 142 Correlations, 464–465, 465t blockages, production monitoring tools, 89 flow modeling, 84–85 pipeline, production monitoring tools, 88 Corrosion, 37 control techniques, 219 flow parameters, 217 hydrate formation carbon steel coupons, 123f Cr 13 steel, 125f stainless steel caliper, 124f stainless steel 316 exhibits corrosion, 124f inhibitor, 193 management, 217 monitoring methods, 218 products, 36–37, 149 risk, 206

test procedures, 193 types, 218 Corrosion-resistant alloys (CRA), 23, 177 CRDF. See Cavity radial distribution function (CRDF) Cross-polarized microscope (CPM), 8, 40, 42, 60, 342 Crude biodegradation, 65 Crude oil, 5. See also Asphaltenes; Naphthenic acids composition of, 163 live, 172f methanol solubility in, 195 SARA analysis, 142 stock tank, 172f water content, 195 CryoFAST, 448, 448f

D Deepwater production challenges, 30–31 fluid sampling, 44–45 operations, 29, 183–184 Diamondoids, 37, 149–150 Differential scanning calorimeter (DSC), 60, 343 Diffusion-limited aggregation (DLA) fractal models, 313 DMAEMA monomers, 250 Drag reducing agents, 199 DREIDING forcefield, 313 Droplet models, 152 Dynamic field development model, 454 Dynamic tube plugging test, 179

E Electric conductivity, 225, 282 Electric power plants, 223 Emulsion, 37, 182, 195 breaker, 13, 13–14t, 196 characteristics, 64–65 and cold flow, 207–208 rheology, 208, 208f viscosity, 208, 208f Enhanced oil recovery (EOR), 143 Enthalpy, 233, 235–236, 241 Entropy, 233 EOR. See Enhanced oil recovery (EOR) EPANET2 tool chemical injection distribution system, 443–444, 445f for water injection system, 444, 445f Equilibrium line, 232, 235, 241, 243, 245 Erosion, 37, 220

F The Flory-Huggins solubility model, 146 Flow assurance

Index 471

advanced fluid properties, 463 background, 17–21 basis of design, 21–22 blockages, 2–3 correlations, 464–465, 465t data mining, 28 definitions, 2, 21 design chemical injection program, 15 flow restrictions, 2–3 fluid characterization, 22 hardware cost, 24–26 hydrates and electrical heating, 3 ice blockages, 5 industry standards to, 463t integrity issues corrosion (see Corrosion) erosion, 220 internal boundaries, 12 issues, 12 lack of training/experience, 15 measuring system, 30 monitoring, 28 multiphase technology & OLGA, 3 operations, 28–29 operator error, 15 outlooks, 30–31 pipe roughness, 463 prevention methods, 13 problems, 5–10 process safety, 30 produced fluids monitoring instrumentation, 465 production chemistry items, 10, 11–12t project design, 14 PVT-related fluid analysis, 22 regional regulatory requirements, 460 sample requirements, 463 standard temperature and pressure, 467 systematic approach, 29–30 units and conversions, 465–467 Flow assurance model concept selection, 452 exploration, 451–452 flow test, 452 material characteristics, 451 PVT fluid characterization, 451 reservoir characterization, 451 Flow-induced vibration, 37 Flowline deliverability issues arrival pressure, 207 artificial lift methods, 206, 207t cold flow and emulsion, 207–208 design process, 205–206 emulsion rheology, 208, 208f heavy oil viscosity, 208

optimization of sizes, 206 topsides equipment, 207 Flow loop tests, 341–342 Flow modeling correlations, 84–85 dimensionless numbers, 85–86 erosion modeling, 87 multiphase production problems, 87 software, 86–87 Flow rate, 3, 35, 37, 70, 77, 88, 115, 145–146, 149, 160, 167, 206, 214 Fluid characterization process group contribution method, 53 laboratory studies, 59–60 lumping, 56–57 oil viscosity, 56 properties and measurements, 51–52 pseudocomponents, 56 PVT tuning, 60–61 solid-liquid equilibrium, 57–59 Fluid physical properties, 61–63, 61–63t Fluid quality BOEM component shut-ins per facility, 196, 197f BOEM warnings per facility, 196, 197f emulsions and foams, 195–196 hydrocarbon gas, 195 hydrocarbon oil, 195 produced water, 195 topsides process design, 195–196 water treatment management, 195–196 Fluid sampling deepwater samples, 44 H2S sample collection, 44 hydrocarbon fluid, 45 mercury samples, 44–45 onshore samples, 44 quality checks, 45–51 Fluid velocity, 155 Fluid viscosity, 444 Foaming, 37, 64

G Gas condensate, 143 ThermoFast, 448, 449f Gas dew point analyzer, 139 Gas-dominated systems, 122 Gas hydrate formation chemistry, 106 flow restriction, 182 light hydrocarbons and sour gases, 183 mechanical expansion, 183 mechanical movement, 183 of microbubbles, 102 of nanobubbles, 102

472 Index Gas hydrate formation (Continued) solid particles, 183 water-based compounds, 183 in wells and in natural settings, 125–126 Gas hydrates annual cost for preventing, 280–281 applications, 282 deposition, 222 greenhouse effect, 223–224, 224–225f, 282 industrial applications, 224–225, 226–227f as industrial hazards, 223 kinetics experimental studies, 235 factors, 235 growth rate, 234 inhibitors, 235 locations in world, 281, 281f in nature, 281 offshore deposits, 282, 283–284f in oil and gas industry, 222 phase transitions in, 235–236 pressure and temperature of, 222 properties and structures, 282 crystalline compound, 228 cubic structure I and II, 228, 230, 231f geometric properties, 228, 231t guest and water molecules, 228, 229f, 232 hexagonal, 230, 232f pure components, 232 sI and sII hydrate formation, 228, 230f small size, 230–232 thermodynamics model, 232 related substances on computers, 297, 298t reserve of carbon in, 281 as source of hydrocarbon fuel, 226–228, 229f in space, 282 stability, 293–294 storage and main-line transportation, 282 at thermodynamics conditions with inhibitors, 233–234 without inhibitors, 233 Gas oil ratio (GOR), 122 liquid components vs.vapor components, 49 reservoir fluid sample, 45 Geothermal profile, 126, 126f Gibbs free energy, 102 Gibbs's phase rule, 233 Global warming, 223, 224f Glycols combination of salt and, 117 modern recovery method, 112 prevent hydrate formation, 233 properties, 113 reboiler, 176

regeneration plants product, 122 thermodynamic inhibitors, 111, 115 types, 112 Grease-sealed glass flask, 237 Greenhouse effect, 223–224, 224–225f, 282 Gypsum, 178, 180

H Halley comet hypothesis, 128f Hardware cost infrastructure-led exploration, 24 Na-Kika semi-submersible platform, 25 net present value, 24 Heat accumulator, hydrate as, 225 Heavy oil, 143–144 management, 198 viscosity, 208 Heterogeneous nucleation, 102 High integrity pressure protection system (HIPPS), 73, 81, 207, 462, 463t High pressure high temperature (HPHT) reservoirs, 23, 56–57, 207, 461–462t High temperature gas chromatograph (HTGC), 163, 168 The Hill-Wood model, 75 Hirschberg model, 142, 146 Historic pigging models, 171–173 H2S samples, 44 HTGC. See High temperature gas chromatograph (HTGC) Hydrate blockage calculating location in pipe, 109–110 case studies in flowlines, 131 causes of pipeline ruptures, 132 characteristics, 37 multiple, 16 onshore field, 15–16 partial, 16 rate of, 104 remediation dissociation temperature, 119, 120–121t melting temperature, 119 versus other flowline time, 99–101 preliminary estimation, 118 prevention of, 110–117 projects, 100–101 rate of, 104 regional environmental regulations, 122 Hydrate control chemicals, 192–193 Hydrate crystal growth computer modeling, 295 in directions of crystal vertices, 303 at gas-liquid interface, 286 inhibition, 296–297 measurements, 312

Index 473

mechanism, 311, 311f morphology axes of rotation, 302, 303f effect of temperature, 299–300 face-centered cubic crystals, 300, 302f {111} faces, 303 fast-growing crystal face, 299, 299f kinetic hydrate inhibitors effect, 304–308, 305–307f NaCl salt effect on THF hydrates, 308–311, 309t, 310f, 312f octahedral crystal shape of sII, 300, 301f, 302, 303f single crystal of THF, 300, 301f variables, 299 visual apparatus, 299, 300f natural gas, 287 recorded by Olympus SZ-CTV microscope, 300 tetrahydrofuran, 286–287, 286f THF + water + inhibitors solution with NaCl salt, 312 types of, 287 Hydrate formation loop, 342 Hydrate inhibition computer modeling clathrate hydrates at CSM, 313 comparison and contrast results, 327–329, 328f, 328t design inhibitors, 336–338, 337t, 338f guest molecules adsorption, 334 methane adsorption model, 334–335 monomer adsorption with Cerius2 program, 313–320, 314–315f, 315–317t, 318–320f, 319t Monte Carlo simulation, 338–340, 339t, 340f short polymer adsorption, 329–336, 330–331f, 332t, 333–334f simulation of methane adsorption, 335–336, 335f software for water and monomers interactions, 320–329, 321f, 323f, 324t, 325–326f, 326–327t computer simulations (molecular dynamics) reasons for, 252 results, 252–253 formation affecting crystal morphology, 287–288 kinetic inhibitors, 288, 289f thermodynamic hydrate inhibitors, 287 Hydrate prevention method active heating, 122 biological remediation, 128 chemical inhibition, 111–116, 122 cold flow, 129 commissioning/dewatering, 139 dry insulation, 122 gas dehydration, 111 partial gas separation, 129 pressure management, 117

static mixer concept, 129 thermal insulation, 111 wellwork safety, 117 wet insulation, 122 Hydrates computer modeling, 290 definition, 101 dissociation, 117–118 docking of macromolecules on, 253–262, 254f, 255–256t, 257–261f formation, 8f, 9 gas hydrate, 102–104 kinetic inhibitor, 193 management, 127–128 risk, 206 structures, 290–291, 291f Hydrate-saturated zones, 125 Hydrate stability calculation, free modeling software tool, 443, 444f computer studies, evaluation of, 250–251 gas hydrates (see Gas hydrates) methane hydrate (see Methane hydrate) xenon sI and xenon + neohexane sH hydrate experiments (see Xenon sI and xenon + neohexane sH hydrate experiments) Hydrate thermodynamic inhibitor, 193 Hydraulic restrictions assessment and management, 69 deliverables of, 69–70 design, 70–71 frictional pressure drop, 71 hydraulic restrictions, 68–74 mitigation examples, 71, 71t network flow optimization process, 91–92 remediation examples, 71, 71t technologies, 73–74 work scope, 69 Hydrocarbon fluid sample, 45 Hydrocarbon gas, 195 Hydrocarbon oil, 195 Hydrogen bonded network, 268–273, 270–271f Hydrogen bonding, 282 HYDR_88 program, 245 HyperChem®, 252 Hyperchem® release 2.0 program, 254 HyPRISM, 447, 447f

I Ice blockage, 37 characteristics, 297, 298t docking of macromolecules on, 253–262, 254f, 255–256t, 257–261f formation, 150

474 Index Ice (Continued) growth inhibition, 253 modeling of, 251–252 xenon gas hydrate formation, 242 ILX. See Infrastructure-led exploration (ILX) Indirect corrosion monitoring methods, 218 Induction time, 102 Infrastructure-led exploration (ILX), 24–25 Inhibitor chemicals, corrosion, 219 In-line inspection (ILI) tool, 219 Integrated models, 219–220 Integrity issues corrosion control techniques, 219 flow parameters, 217 management, 217 monitoring methods, 218 types, 218 erosion, 220 Irreversible thermodynamics, 147 Isoparaffinic, 159

J Joukowski equation, 215 Joule-Thomson cooling effect, 37, 70, 84, 150

K Katz method, 130 Kerosene lamps, 17 Kinetic hydrate inhibitors (KHI), 104–105, 108, 113, 117, 123 Kinetic inhibitors, 235, 251 Kolmogorov energy dissipation, 109

L Lactam ring, 278 Laminar flow, 72, 158, 219 Laplace's law, 102 LDHI. See Low dosage hydrate inhibitors (LDHI) Lean gas critical point location, 460, 460f density, 457t gas gravity, 455 viscosity, 457t Z factor, 457t Liberation test, 47, 47–48t Light oil, 143 Liquid holdup condensate-gas ratio, 151 liquid accumulation, 152–153 steam transmission lines, 151 Liquid slug, 214 Liquid water characteristics, 297, 298t structures, 290–291, 291f

LNG cryogenic heat exchangers CryoFAST, 448, 448f LNG liquefaction process, 29 LNG thermodynamic property, ThermoFast, 448, 449f Low dosage hydrate inhibitors (LDHI), 104–105, 111

M Macrocrystalline wax, 156, 159, 169t Material Safety Data Sheet (MSDS), 123 MEG. See Monoethylene glycol (MEG) Mercury accumulation, 38 management, 199 samples, 44–45 Methane critical point location, 460, 460f density, 456t gas gravity, 455 greenhouse effect, 282 viscosity, 456t Z factor, 456t Methane hydrate burning, 225, 227f experiments Clausius-Clapeyron equation, 241 equilibrium data, 236, 236f, 238, 239–240t, 240f equipment and procedure, 237–238, 237–238f measurements, 238 results, 238–241 stoichiometric formula, 241 greenhouse effect, 223–224, 224–225f phase transition, 249 Methanol-water mixture, 233–234 Microbially influenced corrosion (MIC), 218 Microbubbles, 102, 118 Microcrystalline, 159 Molecular modeling chemical performance on solid surface, 251–252 hydrate inhibition (see Hydrate inhibition) Monitoring instrumentation, 465 Monoethylene glycol (MEG) density, 200 specific gravity, 201f viscosity, 200, 202f Monte Carlo computer program, 298, 367–436 Monte Carlo (MC) method, 295, 329 Multiphase flow flow resistance, 153 hydrodynamics design technique, 79–80 Fanning equation, 77 liquid holdup, vertical vs. horizontal, 80–81 pressure drop, vertical vs. horizontal, 74–79 slugging/liquid loading control, 80 loop, 4, 75, 342

Index 475

models, 219 vacuum condition, 153

N Na-Kika semi-submersible platform, 25 Nanobubbles, 102, 118 Naphthenates calcium, 197 deposition, 38 management, 197–198 properties, 197–198 Naphthenic acids, 198 Natural gas hydrates calculating location, 109–110 chemical reactions, 106 corrosion effect, 123–125 crystal growth, 287 environmental impacts, 122 formation of, 102–104 gas dehydration, 111 gas hydrate stability, 129–131 health impact, 123 overpressurization, 104–106 plug formation, 109 problems related, 108–109 propensity, 104–106 stability of, 108 subcooling, 104–106 supercooling, 104–106 thermodynamic features, 106–108 Natural gas production, 281 Neslab cryocool CC-100 II 2-stage immersion cooler, 237 Neslab on/off temperature controller, 242 Newtonian fluids transport methods, 154 Nitrate-reducing bacteria (NRB), 148, 177 Non-stick coatings, 146 NRB. See Nitrate-reducing bacteria (NRB)

O Offshore production design technique, 79 drilling rig, 19f operations, 28 Oil/gas development project blockage monitoring, 91 flow restriction, 91 hydraulic design, 89–90 water injection management, 90–91 Oil-in-water emulsions, 65 Oil quality noncompliance, 38 Omega platinum resistance thermometer, 237 Online monitoring software tools, 88 Onshore production challenges, 30–31 operations, 28

Operations deepwater production, 29 offshore production, 28 onshore production, 28

P Paraffin wax, 159 Brownian diffusion, 159 chemistry, 159 cold finger, 342 composition, 159, 163 comprehensive modeling, 173–174 conventional techniques, 171 cross-polarized microscope, 40, 342 deposition, 5–6 deposition loop, 341 deposits collection data, 160t emerging techniques, 171 environmental impacts of, 168 historic pigging models, 171–173 laboratory measurements, 168–171 management of, 164 miscellaneous factors, 163 monitoring, 171 operating parameters, 160, 161t PVT conditions, 161–162 remediation techniques, 167–168 remote sensing, 171 structure, 160 thermal diffusion, 159 waxy gels, 174–176 wellbores and surface gathering lines, 160–161, 161f Periodic biocide treatment, 148 Petroleum fluids, 156, 192 industry, 20 production global, 17 large scale, 17 Ludvig Nobel, 20 product, 194 quality hydrocarbon gas, 195 hydrocarbon oil, 195 produced water, 195 reservoirs, 9–10 solids, 58 use of, 17 Petroleum Jelly, 20 Phase diagram/phase map, 29 PHAS_88 program, 245 PHREEQC water ion saturation analysis tool, 444, 446f, 447 Physico-chemical corrosion, 218

476 Index Pipeline gas hydrate formation, 223 production monitoring tools correlations, 88 software, 88 Piper Alpha offshore platform, 15–16 Pipe roughness, 463 Poly(N,N-diethyl acrylamide) (PNNDEAM), 288 Poly(vinyl alcohol) (PVA), 288, 289f Poly-N-vinyl caprolactam (PVCap) inhibitor, 288, 289f chemical structures, 253, 254f conformation of, 260–261f effect on water structure, 277, 277t Poly-N-vinyl pyrrolidone (PVP) inhibitor, 288, 289f adsorption, 297, 313, 318 chemical structures, 253, 254f conformation, 260f docking, 259, 279 effect on water sturcture, 275–276, 277t molecular weight, 305f results for, 314 Potential models, 290 Pressure volume temperature (PVT) crude biodegradation, 65 emulsion characteristics, 64–65 fluid characterization process, 51–61 fluid physical properties, 61–63, 61–63t fluid sampling, 44–45 gas properties, 455–460 GOR range, 45–50 non-Newtonian fluid, 63–64 phase behavior, 43–44, 44f quality checks, samples, 45–51 simulation software, 56 true boiling point analysis, 55 tuning, 60–61 wellwork fluids formulation, 51 PROCAP 1000, 5 Produced water, 195 Production chemicals characteristics, 200 chemical injecting system, 194 chemical performance asphaltene dispersant, 193 asphaltene inhibitor, 193 corrosion inhibitor, 193 criteria for, 193 hydrate antiagglomerant chemical, 193 hydrate kinetic inhibitor, 193 scale inhibitor, 193 wax inhibitor, 193 chemical tubing blockage, 200 4Cs quality, 192–193

dosage selection and optimization, 200 effectiveness and economics of, 194 estimated properties, 203t lab equipment requirements, 193 MEG data density, 200 specific gravity, 201f viscosity, 200, 202f operating expenditure, 192–193 sampling fluids, 191–192 test procedures, 193–194 Production issues blockage remediation plan, 42 causes of asphaltene, 36 bacterial deposit, 36 corrosion products, 36–37 diamondoids deposition, 37 emulsions, 37 erosion of pipes, pipe elbows or valves, 37 fines production, 37 flow-induced vibration, 37 foaming, 37 hydrate blockage, 37 ice blockage, 37 Joule-Thomson cooling, 37 liquids holdup in flow lines, 37 loading of wells, 37 mercury accumulation, 38 naphthenates deposition, 38 oil quality noncompliance, 38 pressure-temperature-composition conditions, 39 productivity damage, 38 sand deposition, 38 scale deposition and scale products accumulation, 38 slugging, 38 souring of produced fluids, 38–39 stuck pig, 39 sulfur deposition, 39 underdeposit corrosion, 39 viscous oil/viscous emulsion flow, 39 water quality noncompliance, 39 wax deposition, 39 differential pressure change, 35–36, 36t hydrate plugs, 35 pressure measurement, 35 solid samples identification, 40 field analysis, 40 field laboratory initial tests, 40 laboratory analysis, 40–42, 41t time, 35 Production monitoring tool, 88

Index 477

Pullman method, 275–276, 278 PVCA inhibitor, 277–278, 277t PVT. See Pressure volume temperature (PVT)

Q Quality checks hydrocarbon fluid sample, 45–50 oil sample, 45 water sample, 50–51

R Radial distribution function (RDF), 262–264 Raman spectroscopy, 343 Research objectives, 297–298 Reservoir souring commercial models, 178 mitigation of, 177 treatment, 177 Retrograde gas, 464t critical point location, 460, 460f density, 459t gas gravity, 455 viscosity, 459t Z factor, 459t Reverse demulsifier chemicals, 195–196 Reversible thermodynamics, 146 Reynolds number, 72 Rheology, 64–65, 343 Rich gas critical point location, 460, 460f density, 458t gas gravity, 455 viscosity, 458t Z factor, 458t Risk analysis, flow assurance bowtie, 22 economic balance, 24 product value, 24 Risk probability management blockage, 453–454 dynamic field development model, 454 prevention, 453 project cost optimization CapEx vs. OpEx, 453 wax deposition, 454

S SAGD. See Steam assisted gravity drainage (SAGD) Sand deposition, 38 Sand transport erosional velocity limits, 155–156 liquid with solids, 156 minimum transport velocity, 154–155 multiphase transport models, 154 SARA analysis, 142

Scale deposition, 38 Scale inhibitor, 193 Scale saturation index, 50 PHREEQC, 444, 446f, 447 SCSSV safety valve, 117, 125 SGN chemical reaction, 167 The Shea model, 75 Simple point charge (SPC) water model, 250 melting point, 250 simulation results, 262–264, 264f Slack flow, 68–69 Slugging hydrodynamic, 38 impact, 214–215 pressure surge calculating method, 215 severe, 38, 211–213 Boe criterion for, 213 flow regime map, 212, 212f frequency correlation, 211 impact on production system, 211 periodic, 211 stability criterion, 212–213 suppression techniques, 213 transient operation flow rate ramp-up and ramp-down, 214 in gathering lines, 214 shut-in and start-up production, 213–214 vacuum condition in flow, 216 Software packages, 74, 86–87 Software tools CryoFAST, 448, 448f CSMHYD, 443, 444f EPANET2 tool, 443–444, 445f for hydrate stability calculation, 443, 444f HyPRISM, 447, 447f PHREEQC, 444, 446f, 447 Thermofast, 448, 449f Solid scale calcium sulfate, 178–179 carbonate, 178 laboratory tests, 179 management, 181 precipitation prediction, 179–180 remediation methods, 180–181 Solid solution models, 290 SPE Hydrate Engineering monograph, 131 Spherical stainless steel reactor, 237, 242 Spreadsheet, 91 SRB. See Sulfate-reducing bacteria (SRB) Static bottle test, 179 Steam assisted gravity drainage (SAGD), 151 Stress-controlled rheometer, 343 Sulfate, 178–179 Sulfate-reducing bacteria (SRB), 177

478 Index Sulfur deposition, 39, 199 SYBYL®, 252–253

T Tetrahydrofuran (THF) hydrate, 286–287 hydrate crystal morphology, 339–340 NaCl salt effect, 308–311, 309t, 310f needle-like growth, 311, 312f octahedral crystal shape, 300, 301f, 302, 303f single crystal, 300, 301f visual apparatus, 299, 300f Thermal effects heat transfer, 81, 82–83t Joule-Thomson effect, 84 Thermodynamic hydrate inhibitors, 287 Thermodynamics, of hydrate formation with inhibitors, 233–234 without inhibitors, 233 ThermoFast, 448, 449f Thermolyne orbital shaker, 242 Tiller multiphase flow loop, 4 TIP3p (transferable intermolecular potential 3 point) model, 262–264, 266–268, 279 Toluene soak, 146 Top of the line corrosion (TOLC), 206 Topside equipment, 207 Topsides process design, 195–196 Transient operation flow rate ramp-up and ramp-down, 214 in gathering lines, 214 shut-in and start-up production, 213–214 Trivac vacuum pump, 242 Tubular plugging composition role, 163 miscellaneous factors, 164 PVT conditions, 163

U Univariant curve, 233

V Vacuum condition, 216 at stock oil flow, 216 Vacuum insulation tubing (VIT), 163, 167 Vaseline, 20 VC-713 inhibitor, 305, 312 adsorption energy, 257–259 chemical structures, 253, 254f conformation of, 259–260f docking, 261–262 effect on water structure, 274–275, 275t, 276f polymer chain of, 254

Viscosity, 56 emulsion, 208, 208f heavy oil, 208 lumping, 56 of MEG, 200, 202f pseudocomponents, 56 Viscous oil characteristics, 39 management, 198–199 VIT. See Vacuum insulation tubing (VIT) VLE phase diagram, 44 Volatile oil, 464t

W WAT. See Wax appearance temperature (WAT) Water and liquid hydrocarbon, 242 Water injection system, EPANET2 tool, 444, 445f Water-in-oil emulsions, 64, 144 Water-methane-methanol mixtures, 234 Water models, kinetic inhibitor interaction with hydrogen bonded network connectivity, 270–272, 272–273f outcomes, 273 schematic of, 262–264, 265f structural determination, 268–270, 270–271f macromolecules effect hypothesis, 274 PVCA inhibitor, 277–278, 277t PVCap inhibitor, 277, 277t PVP inhibitor, 275–276, 277t VC-713 inhibitor, 274–275, 275t, 276f monomer structure, 262–264, 265f overview, 278–279 oxygen-oxygen radial distribution function, 262–264, 263f SPC water model (see Simple point charge (SPC) water model) verification analysis, 267–268, 267–269f comparison between SPC, TIP3p and proprietary Tripos model, 266 procedure, 266 Water quality noncompliance, 39 Water sample, 192 drilling mud contamination, 50 ionic balance, 50 rare cases, 51 scale saturation index, 50 Water structure, 234, 251 Wax appearance temperature (WAT), 6–8, 131, 158, 162, 167 Wax deposition, 39 Wax dissolution temperature (WDT), 6–8 Wax formation, prevention techniques

Index 479

comparative economics of, 167 electrical heat, 167 management of, 164 mechanical wax removal method, 164–165, 165f pigging, 165 remediation technologies, 164 vacuum insulation tubing, 167 Wax inhibitor, 193 Wax loop, 342 Wax, remediation techniques chemical removal, 167 comparative economics of, 168 mechanical removal, 167 thermal removal, 167 Wet and dry gases, 464t Winter flounder polypeptide adsorption of, 253, 257 aminoacids structure, 255, 255t chemical formula, 253

conformation on, 257, 257–259f docking of, 253, 257, 261–262 Hyperchem® release 2.0 program, 254 sequence of aminoacids, 255

X

Xenon sI and xenon + neohexane sH hydrate experiments calculated phase composition, 244–245, 247t crossover of equilibrium curves, 244, 246–247f equilibrium calculation, 248, 249f, 250t equilibrium data, 243–244, 244t, 245f, 246t equipments, 237f, 242 literature data, 241 procedure, 242–243, 243f two phase diagrams, 249 two-step process, 245 vapor phase composition, 245–247 XHPHT reservoirs, 56–57