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Carbon Dioxide Sequestration and Related Technologies

Scrivener Publishing 3 Winter Street, Suite 3

Salem, MA 01970

Scrivener Publishing Collections Editors

James E. R. Couper Richard Erdlac Pradip Khaladkar Norman Lieberman W. Kent Muhlbauer S. A. Sherif

Ken Dragoon Rafiq Islam Vitthal Kulkarni Peter Martin Andrew Y. C. Nee James G. Speight

Publishers at Scrivener Martin Scrivener (martin@scrivenerpublishing.com)

Phillip Carmical (pcarmical@scrivenerpublishing.com)

Carbon Dioxide Sequestration and

Related Technologies Edited by

Ying (Alice) Wu Sphere Technology Connection

John J. Carroll Gas Liquids Engineering, Ltd.

and

Zhimin Du Southwest Petroleum University

Copyright © 2011 by Scrivener Publishing LLC. All rights reserved.

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Library of Congress Cataloging-in-Publication Data:

ISBN 978-0-470-93876-8

Printed in the United States of America

10 9 8 7 6 5 4 3 2 1

Contents

Introduct ion

The Three Sisters - CCS, AGI, and EOR xix

Ying Wu, John J. Carroll and Zhimin Du

Sec t ion 1: Data and Correlat ion

1. Prediction of Acid Gas Dew Points in the Presence of Water and Volatile Organic Compounds 3 Ray. A. Tomcej 1.1 Introduction 3 1.2 Previous Studies 4 1.3 Thermodynamic Model 5 1.4 Calculation Results 6 1.5 Discussion 10 References 11

2. Phase Behavior of China Reservoir Oil at Different C 0 2 Injected Concentrations 13 Fengguang Li, Xin Yang, Changyu Sun, and Guangjin Chen 2.1 Introduction 14 2.2 Preparation of Reservoir Fluid 14 2.3 PVT Phase Behavior for the C0 2 Injected

Crude Oil 15 2.4 Viscosity of the C0 2 Injected Crude Oil 17 2.5 Interfacial Tension for C0 2 Injected Crude

Oil/Strata Water 19 2.6 Conclusions 20 Literature Cited 21

3. Viscosity and Density Measurements for Sour Gas Fluids at High Temperatures and Pressures 23 B.R. Giri, P. Biais and R.A. Marriott 3.1 Introduction 24 3.2 Experimental 25

v

vi CONTENTS

3.2.1 Density Measurement 25 3.2.2 Viscosity Measurement 27 3.2.3 Charging and Temperature Control 30

3.3 Results 31 3.4 Conclusions 37 References 37

4. Acid Gas Viscosity Modeling with the Expanded Fluid Viscosity Correlation 41 H. Motahhari, M.A. Satyro, H.W. Yarranton 4.1 Introduction 41 4.2 Expanded Fluid Viscosity Correlation 42

4.2.1 Mixing Rules 44 4.2.2 Modification for Non-Hydrocarbons 45

4.3 Results and Discussion 47 4.3.1 Pure Components 47 4.3.2 Acid Gas Mixtures 48

4.4 Conclusions 52 4.5 Acknowledgements 52 References 52

5. Evaluation and Improvement of Sour Property Packages in Unisim Design 55 Jianyong Yang, Ensheng Zhao, Laurie Wang, and Sanjoy Saha 5.1 Introduction 55 5.2 Model Description 56 5.3 Phase Equilibrium Calculation 58 5.4 Conclusions 62 5.5 Future Work 62 Reference 63

6. Compressibility Factor of High C02-Content Natural Gases: Measurement and Correlation 65 Xiaoqiang Bian, Zhimin Du, Yong Tang, and Jianfen Du 6.1 Introduction 65 6.2 Experiment 67

6.2.1 Measured Principles 67 6.2.2 Experimental Apparatus and Procedure 67 6.2.3 Experimental Results 68

CONTENTS

6.3 Methods 6.3.1 Existing Methods 6.3.2 Proposed Method

6.5 Comparison of the Proposed Method and Other Methods

6.6 Conclusions 6.7 Acknowledgements 6.8 Nomenclature References

68 68 74

78 83 84 84 85

Section 2: Process Engineering

7. Analysis of Acid Gas Injection Variables 89 Edward Wiehert and James van der Lee 7.1 Introduction 89 7.2 Discussion 90 7.3 Program Design 93 7.4 Results 94 7.5 Discussion of Results 96

7.5.1 General Comments 96 7.5.2 Overall Heat Transfer Coefficient, U 101 7.5.3 Viscosity 104

7.6 Conclusion 105 References 105

8. Glycol Dehydration as a Mass Transfer Rate Process 107 Nathan A. Hatcher, Jaime L. Nava and Ralph H. Weiland 8.1 Phase Equilibrium 108 8.2 Process Simulation 110 8.3 Dehydration Column Performance 111 8.4 Stahl Columns and Stripping Gas 114 8.5 Interesting Observations from a Mass

Transfer Rate Model 115 8.6 Factors That Affect Dehydration

of Sweet Gases 118 8.7 Dehydration of Acid Gases 119 8.8 Conclusions 119 Literature Cited

CONTENTS

Carbon Capture Using Amine-Based Technology Ben 9.1 9.2 9.3

9.4 9.5

9.6

Spooner and David Engel Amine Applications Amine Technology Reaction Chemistry 9.3.1 Nucleophilic Pathway 9.3.2 Acid-Base Pathway (Primary

Secondary and Tertiary Amines) Types of Amine Challenges of Carbon Capture 9.5.1 Prevention 9.5.2 Reclaimers 9.5.3 Purging and Replacing Amine 9.5.4 High Energy Consumption 9.5.5 Size of the Amine Facility 9.5.6 Captured C0 2

Conclusion

121

121 122 124 124

125 126 128 128 129 129 129 130 130 131

Dehydration-through-Compression (DTC): Is It Adequate? A Tale of Three Gases 133 Wes H. Wright 10.1 Background 133 10.2 Water Saturation 138 10.3 Is It Adequate? 138 10.4 The Gases 141 10.5 Results 147 10.6 Discussion 151 References 152

Diaphragm Pumps Improve Efficiency of Compressing Acid Gas and C0 2 155 Josef Jarosch, Anke-Dorothee Braun 11.1 Diaphragm Pumps 162 11.2 Acid Gas Compression 164 11.3 C0 2 Compression for Sequestration 167 11.4 Conclusion 171 Literature 172

CONTENTS ix

Section 3: Reservoir Engineering

12. Acid Gas Injection in the Permian and San Juan Basins: Recent Case Studies from New Mexico 175 David T. Lescinsky; Alberto A. Gutierrez, RG; James C. Hunter, RG; Julie W. Gutierrez; and Russell E. Bentley 12.1 Background 175 12.2 AGI Project Planning and Implementation 178

12.2.1 Project Planning and Feasibility Study 178

12.2.2 Reservoir/Cap Rock Identification and Regulatory Permitting 181

12.2.3 Well Drilling and Testing 183 12.2.4 Well Completion and Construction 186 12.2.5 Reservoir and Seal Evaluation 186 12.2.6 Documentation, System Start-up

and Reporting 188 12.3 AGI Projects in New Mexico 190

12.3.1 Permian Basin 190 12.3.1.1 LinamAGI#l 193 12.3.1.2 Jal 3 AGI #1 196

12.3.2 San Juan Basin 199 12.3.2.1 Pathfinder AGI #1 200

12.4 AGI and the Potential for Carbon Credits 204 12.5 Conclusions 207 References 208

13. C0 2 and Acid Gas Storage in Geological Formations as Gas Hydrate 209 Farhad Qanbari, Olga Ye Zatsepina, S. Hamed Tabatabaie, Mehran Pooladi-Darvish 13.1 Introduction 210 13.2 Geological Settings 211

13.2.1 Depleted Gas Reservoirs 211 13.2.1.1 Mixed Hydrate Phase

Equilibrium 211 13.2.1.2 Assumptions 213

x CONTENTS

13.3

13.4

13.5 13.6 13.7

13.2.2 Ocean Sediments 13.2.2.1 Negative Buoyancy

Zone (NBZ) 13.2.2.2 Hydrate Formation

Zone (HFZ) Model Parameters 13.3.1 Depleted Gas Reservoir 13.3.2 Ocean Sediment Results 13.4.1 Depleted Gas Reservoir 13.4.2 Ocean Sediment Discussion Conclusions Acknowledgment

References

213

213

214 216 216 217 218 218 221 221 223 224 224

14. Complex Flow Mathematical Model of Gas Pool with Sulfur Deposition 227 W. Zhu, Y. Long, Q. Liu, Y. Ju, and X. Huang 14.1 Introduction 227 14.2 The Mathematical Model of Multiphase

Complex Flow 228 14.2.1 Basic Supposition 228 14.2.2 The Mathematical Model

of Gas-liquid-solid Complex Flow in Porous Media 229 14.2.2.1 Flow Differential Equations 229 14.2.2.2 Unstable Differential

Equations of Gas-liquid-solid Complex Flow 230

14.2.2.3 Relationship between Saturation and Pressure of Liquid Phase 231

14.2.2.4 Auxiliary Equations 232 14.2.2.5 Definite Conditions 232

14.3 Mathematical Models of Flow Mechanisms 232 14.3.1 Mathematical Model of Sulfur

Deposition 232 14.3.2 Thermodynamics Model of Three-phase

Equilibrium 234 14.3.3 State Equations 236

CONTENTS xi

14.3.4 Solubility Calculation Model 236 14.3.5 Influence Mathematical Model of Sulfur

Deposition Migration to Reservoir Characteristics 237

14.4 Solution of the Mathematical Model Equations 238 14.4.1 Definite Output Solutions 238 14.4.2 Productivity Equation 239

14.5 Example 240 14.5.1 Simulation Parameter Selection 240 14.5.2 Oil-gas Flow Characteristics near Borehole

Zones of Gas-well 240 14.5.3 Productivity Calculation 240

14.6 Conclusions 242 14.7 Acknowledgement 242 References 242

Section 4: Enhanced Oil Recovery (EOR)

15. Enhanced Oil Recovery Project: Dunvegan C Pool Darryl Burns 15.1 15.2 15.3 15.4

Introduction Pool Data Collection Pool Event Log Reservoir Fluid Characterization 15.4.1 Fluid Characterization Program Design

Questions 15.4.2 Fluid Characterization Program 15.4.3 Solubility of Acid Gas Mixtures in the

Dunvegan C Oil 15.5 Material Balance 15.6 15.7

15.8 15.9

Geological Model Geological Uncertainty 15.7.1 Formation Bulk Volume 15.7.2 Porosity 15.7.3 Permeability 15.7.4 Residual (Immobile) Fluid Saturations 15.7.5 Relative Permeability Curve Parameters 15.7.6 Fluid Contacts History Match Black Oil to Compositional Model Conversion

247

248 249 252 255

255 257

263 263 264 269 269 269 269 270 270 272 272 282

CONTENTS

15.10 15.11 15.12 15.13

15.14

Recovery Alternatives Economics Economic Uncertainty Discussion and Learning 15.13.1 15.13.2 15.13.3 15.13.4 15.13.5

15.13.6 15.13.7

Reservoir Fluid Characterization Material Balance Geological Model History Match Black Oil to Compositional Model Conversion Recovery Alternatives Economics

End Note References

290 307 312 312 312 315 315 316

317 317 317 317 318

C0 2 Flooding as an EOR Method for Low Permeability Reservoirs 319 Yongle Hu, Yunpeng Hu, Qin Li, Lei Huang, Mingqiang Hao, and Siyu Yang 16.1 Introduction 319 16.2 Field Experiment of C0 2 Flooding in China 320 16.3 Mechanism of C0 2 Flooding Displacement 321 16.4 Perspective 324 16.5 Conclusion 326 References 326

Pilot Test Research on C0 2 Drive in Very Low Permeability Oil Field of in Daqing Changyuan 329 Weiyao Zhu, Jiecheng Cheng, Xiaohe Huang, Yunqian Long, and Y. Lou 17.1 Introduction 329 17.2 Laboratory Test Study on C0 2 Flooding in Oil

Reservoirs with Very Low Permeability 330 17.2.1 Research on Phase Behavior

and Swelling Experiments 330 17.2.2 Tubule Flow Experiments 331 17.2.3 Long Core Test Experiments 332

17.3 Field Testing Research 333 17.3.1 Geological Characteristics of Pilot 333

17.3.1.1 Structural Characteristics 334 17.3.1.2 Characteristics of Reservoir 334

CONTENTS Xlll

17.3.1.3 Reservoir Properties and Lithology Characteristics 336

17.3.2 Distribution and Features of Fluid 339 17.3.3 Designed Testing Scheme 339 17.3.4 Field Test Results and Analysis 340

17.3.4.1 Low Gas Injection Pressure and Large Gas Inspiration Capacity 340

17.3.4.2 Production Rate and Reservoir Pressure Increase after Gas Injection 341

17.3.4.3 Reservoir Heterogeneity Is the Key to Control Gas Breakthrough 342

17.3.4.4 C0 2 Throughput as the Supplementary Means of Fuyu Reservoir's Effective Deployment 343

17.3.4.5 Numerical Result Shows that Carrying Out Water Flooding after Injecting Certain Amount of C0 2 Slug is Better 344

17.4 Conclusion 346 17.5 Acknowledgement 349 References 349

18. Operation Control of C02-Driving in Field Site. Site Test in Wellblock Shu 101, Yushulin Oil Field, Daqing 351 Xinde Wan, Tao Sun, Yingzhi Zhang, Tiejun Yang, and Changhe Mu 18.1 Test Area Description 352

18.1.1 Characteristics of the Reservoir Bed in the Test Area 352

18.1.2 Test Scheme Design 352 18.2 Test Effect and Cognition 353

18.2.1 Test Results 353 18.2.2 The Stratum Pressure Status 354 18.2.3 Air Suction Capability of the Oil Layer 356 18.2.4 The Different Flow Pressure Control 356 18.2.5 Oil Well with Poor Response 358

18.3 Conclusions 359 References 359

xiv CONTENTS

19. Application of Heteropolysaccharide in Acid Gas Injection 361 Jie Zhang, Gang Guo and Shugang Li 19.1 Introduction 361 19.2 Application of Heteropolysaccharide in C0 2

Reinjection Miscible Phase Recovery 363 19.2.1 Test of Clay Polar Expansion Rate 364

19.2.1.1 Test Method 364 19.2.1.2 Testing results as the Figure 2

and Table 1 shows 366 19.2.2 Test of Water Absorption of Mud Ball

in Heteropolysaccharide Collosol 367 19.3 Application of Heteropolysaccharide in H2S

Reinjection formation 370 19.3.1 Experiment Process, Method

and Instruction 370 19.3.1.1 Experiment Process 370 19.3.1.2 Experiment Method 370 19.3.1.2 Experiment Results 372

19.4 Conclusions 373 References 373

Section 5: Geology and Geochemistry

20. Impact of S 0 2 and NO on Carbonated Rocks Submitted to a Geological Storage of C02: An Experimental Study 377 Stéphane Renard, Jérôme Sterpenich, Jacques Pironon, Aurélien Randi, Pierre Chiquet and Marc Lescanne 20.1 Introduction 377 20.2 Apparatus and Methods 378

20.2.1 Solids and Aqueous Solution 379 20.2.2 Gases 380

20.3 Results and Discussion 381 20.3.1 Reactivity of the Blank Experiments 381 20.3.2 Reactivity with pure S02 384 20.3.3 Reactivity with pure NO 387

20.4 Conclusion 391 Acknowledgments 392 References 392

CONTENTS XV

21. Geochemical Modeling of Huff 'N' Puff Oil Recovery With C0 2 at the Northwest Mcgregor Oil Field 393 Yevhen I. Holubnyak, Blaise A.F. Mibeck, Jordan M. Bremer, Steven A. Smith, James A. Sorensen, Charles D. Gorecki, Edward N. Steadman, and John A. Harju 21.1 Introduction 393 21.2 Northwest McGregor Location

and Geological Setting 395 21.3 The Northwest McGregor Field, E. Goetz #1

Well Operational History 395 21.4 Reservoir Mineralogy 397 21.5 Preinjection and Postinjection Reservoir

Fluid Analysis 398 21.6 Major Observations and the Analysis of the

Reservoir Fluid Sampling 400 21.7 Laboratory Experimentations 401 21.8 2-D Reservoir Geochemical Modeling

with GEM 402 21.9 Summary and Conclusions 403 21.10 Acknowledgments 404 21.11 Disclaimer 404 References 405

22. Comparison of C0 2 and Acid Gas Interactions with reservoir fluid and Rocks at Williston Basin Conditions 407 Yevhen I. Holubnyak, Steven B. Hawthorne, Blaise A. Mibeck, David J. Miller, Jordan M. Bremer, Steven A. Smith, James A. Sorensen, Edward N. Steadman, and John A. Harju 22.1 Introduction 407 22.2 Rock Unit Selection 409 22.3 C0 2 Chamber Experiments 411 22.4 Mineralogical Analysis 412 22.5 Numerical Modeling 413 22.6 Results 413 22.7 Carbonate Minerals Dissolution 414 22.8 Mobilization of Fe 416

xvi CONTENTS

22.9 Summary and Suggestions for Future Developments 418

22.10 Acknowledgments 418 22.11 Disclaimer 418 References 419

Section 6: Well Technology

23 Well Cement Aging in Various H2S-C02 Flui( is at High Pressure and High Temperature: Experiments and Modelling Nicolas Jacquemet, Jacques Pironon, Jérémie Saint-Marc 23.1 Introduction 23.2 Experimental equipment

Vincent

23.3 Materials, Experimental Conditions and Analysis 23.3.1 Cement 23.3.2 Casing 23.3.3 Environment 23.3.4 Exposures (Figure 3): 23.3.5 Analyses

23.4 Results and Discussion 23.4.1 Cement 23.4.2 Steel

23.5 Reactive Transport Modelling 23.6 Conclusion Acknowledgments References

Lagneau, 423

424 425

426 426 427 427 427 427 428 428 430 430 432 433 434

24. Casing Selection and Correlation Technology for Ultra-Deep, Ultra- High Pressure, High H2S Gas Wells 437 Yongxing Sun, Yuanhua Lin, Taihe Shi, Zhongsheng Wang, Dajiang Zhu, Liping Chen, Sujun Liu, and Dezhi Zeng 24.1 Introduction 438 24.2 Material Selection Recommended Practice 438 24.3 Casing Selection and Correlation Technology 441

CONTENTS xvii

24.3.1 Casing Selection and match Technology Below 90°C 442

24.3.2 Casing Selection and Match Technology Above 90°C 443

24.4 Field Applications 443 24.4 Conclusions 445 24.5 Acknowledgments 447 References 447

25. Coupled Mathematical Model of Gas Migration in Cemented Annulus with Mud Column in Acid Gas Well 449 Hongjun Zhu, Yuanhua Lin, Yongxing Sun, Dezhi Zeng, Zhi Zhang, and Taihe Shi 25.1 Introduction 449 25.2 Coupled Mathematical Model 450

25.2.1 Gas Migration in Cement 451 25.2.2 Gas Migration in Stagnant Mud 452 25.2.3 Gas Unloading and Accumulation

at Wellhead 454 25.2.4 Coupled Gas Flows in Cement

and Mud 456 25.3 Illustration 458 25.4 Conclusions 459 25.5 Nomenclature 460 25.6 Acknowledgment 461 References 461

Sect ion 7: Corros ion

26. Study on Corrosion Resistance of L245/825 Lined Steel Pipe Welding Gap in H2S+C02 Environment 465 Dezhi Zeng, Yuanhua Lin, Liming Huang, Daijiang Zhu, Tan Gu, Taihe Shi, and Yongxing Sun 26.1 Introduction 466 26.2 Welding Process of Lined Steel Pipe 466 26.3 Corrosion Test Method of Straight and Ring

Welding Gaps of L245/825 Lined Steel Pipe 467 26.4 Corrosion Test Results of Straight and Ring

Welding Gaps of 1245/825 Lined Steel Pipe 472

xviii CONTENTS

26.4.1 Atmospheric Corrosion Test Results 472 26.4.2 Corrosion Test Results at High Pressure 472 26.4.3 Field Corrosion Test Results 474

26.5 Conclusions 477 26.6 Acknowledgments 477 References 477

Index 479

Introduction

The Three Sisters - CCS, AGI, and EOR

Ying Wu1, John J. Carroll2 and Zhimin Du3

1 Sphere Technology Connection, Calgary, AB, Canada 2 Gas Liquids Engineering, Calgary, AB, Canada

3 Southwest Petroleum University, Chengdu, People's Republic of China

Although there remains some debate about whether or not man is changing the global climate and, if so, whether or not carbon diox-ide is the cause of it, there is a significant capital, both political and financial, to reduce carbon emissions. It is not the purpose of this introduction, or this volume for that matter, to enter this debate. The purpose is to review the technology to achieve this and the inter-relations within available technologies.

One of the main foci for reducing carbon emission is the so-called process, carbon capture and storage (CCS), removing carbon dioxide from combustion gases and storing them in subsurface formations. The main source of these combustion gases is coal-fired power plants, but other sources are targeted as well.

In the petroleum and natural gas business there are two other mature technologies for injecting gas streams. The first of these is acid gas injection (AGI), and the other is injecting carbon dioxide for enhanced oil recovery (EOR). This makes CCS, AGI and EOR three sisters, of sorts. Whereas AGI and EOR are relatively mature processes, CCS is not and there is much those working in the CCS world can learn from both AGI and CCS. Table 1 summarizes the main components for the three technologies. Each of these will be discuss here.

Whereas the impetus for acid gas injection is to eliminate sulfurous emissions, and there is little doubt about the effect of these emissions, they also sequester C02 . On the other hand, the purpose of injecting C0 2 for EOR is to produce more oil. Burns [1], in a chapter in this volume discusses, the economics of an EOR

xix

xx C0 2 SEQUESTRATION AND RELATED TECHNOLOGIES

Table 1. The three sisters: CCS, AGI, and EOR.

Source of fluid

Pressure

Pipeline

Well

Purpose

By-product

CCS

capture from flue gas

compression

probably a network

i. probably multiple wells

ii. probably deviated wells to achieve high injectivity

storage

AGI

sweetening of natural gas

compression

commonly a single pipeline

commonly a single well

disposal

reduced C0 2

emissions

EOR

i. virgin ii. recovered

compression

pipeline network

multiple, injection pattern (5-spot, for example)

oil recovery

co2 sequestration

project. Nonetheless, sequestration of C0 2 is a by-product of these EOR schemes. For CCS the purpose is simply to eliminate carbon emission into the atmosphere. However, C0 2 captured from flue gas may have value as a source of virgin C0 2 for EOR projects.

Capture

The flue gas stream from a combustion process produces a flue gas that is from 5% to 15% carbon dioxide. The rest of this stream con-tains mostly nitrogen but also some oxygen and smaller amount of sulfur oxides and nitrogen oxides. The volume of the raw flue gas is too large to make compression and injection feasible. Thus the first step is to "capture" the C0 2 from the flue gas.

In the natural gas business the removal of carbon dioxide (and hydrogen sulfide for that matter) is called sweetening. Much of the technology developed over 75 years in the natural gas business can be transferred to the capture of C02 . However there are many

INTRODUCTION xxi

problems associated with capturing C0 2 that are not as common in the natural gas business. These include the low pressure of the flue gas stream (near atmospheric pressure versus tens of bars for natu-ral gas) and the contaminants. Oxygen is poison to the common solvents used in the natural gas business.

The chapter by Spooner and Engel [2] in this volume discusses the use of amine technology for capturing C0 2 from flue gas. Among the problems Spooner and Engel address are the high oxygen con-tent of the flue gas and the low pressure.

In EOR there must be a source of carbon dioxide when the project begins. This is the so-called "virgin" C02 . Once the project starts, some of the C0 2 will be produced with the oil. This C0 2 is recov-ered from the oil and used for re-injection. Initially the recycled C0 2

will be small but as the project matures this may become as large as 80% or 90% of the carbon dioxide injected.

Compression

The next step for each of the three processes is to compress the stream to sufficient pressure such that it can be injected into a sub-surface reservoir.

In EOR the virgin C0 2 is usually delivered at such a pressure that little or no compression is required. However the recycled C0 2 is at low pressure and must be compressed for injection. In AGI the acid gas stream is at low pressure and in comes the sweetening process, where low pressure is used to regenerate the solvent.

In acid gas injection and the compression of C0 2 for EOR it is common to use compression and cooling alone to reduce the water content of an acid gas stream. The water holding capacity of acid gas was discussed in the previous volume in this series by Marriott et al. [3] and also by Satyro and van der Lee [4].

In a chapter in this volume Wright [5] discusses the use of com-pression and cooling in order to dehydrate an acid gas stream. In particular Wright addresses when dehydration is required and when it is not based on the composition of the gas and its water holding capacity.

In some cases, compression alone cannot achieve sufficiently high pressures to inject the stream. In these cases, the stream can be liquefied (using a combination of high pressure and low temperature) and then pumped to higher pressure. Later in this

xxii C0 2 SEQUESTRATION AND RELATED TECHNOLOGIES

book Janusch and Braun [6] discuss the pumping of acid gas with diaphragm pumps.

Pipeline

For all of the three sisters the compressed gas is transported via pipeline to the injection well(s).

In an EOR project the compressed C0 2 must be distributed through the oil filed such that the optimum oil recovery can be achieved. This requires a network of pipes.

For small AGI projects usually only a single injection well is used and thus a single pipeline. However, for very large projects, AGI may require a network of line similar to an EOR project.

The volumes injected in a typical CCS project will be very large and thus a single well is probably not an option.

Injection

Again in each of the three sisters, the compressed fluid enters a well and travels downward to the target formation.

In EOR it is common to have multiple wells arranged in a pat-tern, some for injecting C0 2 and some for producing oil. It is also possible to use C0 2 for huff 'n puff. This involves injecting C0 2 for a period of time and then allowing the C0 2 to soak (the "huff"). The same well is the used for producing the oil (the "puff").

Because of the properties of the gas injected and the phase behav-ior encountered, some unusual behavior can be observed in acid gas injection wells. Mirreault et al. [7] in the previous volume in this series, describe some seeming unusual behaviour in an injection well that have some relatively simple explanation.

Geochemistry

The effect of the acid gas, and perhaps more specifically C02 , on the reservoir rock is an important consideration in the design of an injection scheme. How does the injected fluid affect the native rock?

A case study related to the geochemical interactions is presented in this volume by Holubnyak et al. [8].

INTRODUCTION xxiii

Summary

The three sisters: CCS, AGI, and EOR share many common com-ponents. Many lessons can be shared especially between the more mature technologies of AGI and EOR and the newer one, CCS. These commonalities demonstrate that carbon capture and storage is a feasible technology.

The remaining chapters in this volume discuss specific aspects of these three sisters and the reader should keep in mind the common aspects of these seemingly different technologies.

References

1. Burns, D. "Enhanced Oil Recovery Project: Dunvegan C Pool", Carbon Dioxide Sequestration and Related Technologies, Scrivener Publishing, Salem, MA. (2011).

2. Spooner, B. and D. Engel, "Carbon Capture Using Amine-Based Technology", Carbon Dioxide Sequestration and Related Technologies, Scrivener Publishing, Salem, MA (2011).

3. Marriott, R.A., E. Fitzpatrick, E Bernard, H. H. Wan, K. L. Lesage, P. M. Davis, and P. D. Clarke, "Equilibrium Water Content Measurements For Acid Gas Mixtures" Acid Gas Injection and Related Technologies, Scrivener Publishing, Salem, MA, (2011).

4. Satyro, M. and J. van der Lee, "The Performance of State of the Art Industrial Thermodynamic Models for the Correlation and Prediction of Acid Gas Solubility in Water", Acid Gas Injection and Related Technologies, Scrivener Publishing, Salem, MA, (2011).

5. Wright, W. "Dehydration-through-Compression: Is it Adequate? A Tale of Three Gases", Carbon Dioxide Sequestration and Related Technologies, Scrivener Publishing, Salem, MA, (2011).

6. Janusch, J. and A.-D. Braun, "Diaphragm Pumps improve Efficiency of Compressing Acid Gas and C02", Carbon Dioxide Sequestration and Related Technologies, Scrivener Publishing, Salem, MA, (2011).

7. Mireault, R., R. Stocker, D. Dunn, and M. Pooladi-Darvish, "Dynamics of Acid Gas Injection Well Operation", Acid Gas Injection and Related Technologies, Scrivener Publishing, Salem, MA, (2011).

8. Holubnyak, Y.I., S.B. Hawthorne, B.A. Mibeck, D.J. Miller, J.M. Bremer, S.A. Smith, J.A. Sorensen, E.N. Steadman, and J.A. Harju, "Comparison of C0 2

and Acid Gas Interactions with Reservoir Fluid and Rocks at Williston Basin Conditions ", Carbon Dioxide Sequestration and Related Technologies, Scrivener Publishing, Salem, MA, (2011).

9. Taiman, S.J. and E.H. Perkins, "Concentration Gradients Associated With Acid Gas Injection", Acid Gas Injection and Related Technologies, Scrivener Publishing, Salem, MA, (2011).

SECTION 1 DATA AND CORRELATION

1

Prediction of Acid Gas Dew Points in the Presence of Water and Volatile

Organic Compounds Ray. A. Tomcej

Tomcej Engineering Inc. Edmonton, AB, Canada

Abstract Aromatic hydrocarbons which are present in sour natural gas streams can be absorbed into the amine treating solution at the bottom of the contactor and exit in the rich amine stream. Depending on the process configura-tion, these dissolved hydrocarbons can end up in the acid gas leaving the amine regenerator. In acid gas injection facilities, trace amounts of heavy hydrocarbons in the acid gas may lead to the formation of a sour hydro-carbon liquid phase in the compressor interstage scrubbers.

In this exploratory work, a cubic equation-of-state (EOS) model was used to make predictions of non-aqueous (Lj) dew points in acid gas sys-tems. The objective was to develop a better understanding of the condi-tions under which this phenomenon can occur, and to reinforce the need for accurate experimental vapor-liquid equilibrium data to support cost effective design and model development.

1.1 Introduction

Benzene, toluene, ethyl benzene and xylene isomers are commonly referred to collectively as BTEX compounds. These compounds are known to be toxic to humans and their containment and disposal are of special interest to the hydrocarbon industry. BTEX environ-mental contamination is often linked to leakage from underground gasoline storage tanks or accidental spills. Awareness of this toxic-ity led to regulated clean air emission standards that directly impact

Wu/Carroll/Du (ed.) Carbon Dioxide Sequestration and Related Technologies, (3-12) © Scrivener Publishing LLC

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4 CO SEQUESTRATION AND RELATED TECHNOLOGIES

the natural gas processing industry as trace amounts of BTEX com-pounds are associated with produced fluids such as natural gas.

Sour gas production generally involves a subsequent process-ing step in which the hydrogen sulphide (H2S) and carbon dioxide (C02) are removed to produce an acid gas stream that may be a can-didate for acid gas injection. Liquid solvents that are used to remove the H2S and C0 2 from the gas stream are often aqueous solutions of organic chemicals that have a high affinity for the BTEX compounds.

Distribution of the BTEX compounds within the various streams of a natural gas processing plant is a complex phenomenon involv-ing many interrelated process variables such as operating pressures and temperatures, amine composition, amine circulation rates, and others. Of particular interest in acid gas injection, is the amount of BTEX compounds that end up in the acid gas product leaving the amine regenerator.

The presence of trace quantities of BTEX compounds in the acid gas, if unaccounted for at the design stage, may lead to the unex-pected formation of a sour non-aqueous liquid phase in the com-pressor train, and considerable operational difficulties. The objective of this work was to develop a better understanding of the conditions under which this phenomenon can occur, and to reinforce the need for accurate experimental vapor-liquid equilibrium data to support cost effective design and model development.

1.2 Previous Studies

In order to estimate the levels of BTEX compounds that will be pres-ent in the acid gas, there is a need for accurate vapor-liquid equi-libria (VLE) and/or vapor-liquid-liquid equilibria (VLLE) data for BTEX and similar hydrocarbons in amine treating solutions under rich amine conditions. Operating plant data are also useful to verify the predictions of any thermodynamic model.

Ng et al. (1999) provided an overview of specific phase equilibria data and physical properties that are required for reliable design of acid gas injection facilities. Hegarty and Hawthorne (1999) pre-sented valuable operating data for a Canadian gas plant using MDEA in which measured BTEX compositions were reported. Mclntyre et al. (2001) and Bullin and Brown (2004) tabulated the experimental data available for hydrocarbon and BTEX solubil-ity in amine treating solutions and demonstrated general trends