Gas Injection for Disposal and Enhanced Recovery
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Ying (Alice) Wu is currently the President of Sphere Technology Connection Ltd. (STC) in Calgary, Canada. From 1983 to 1999 she was an Assistant Professor and Researcher at Southwest Petroleum Institute (now Southwest Petroleum University, SWPU) in Sichuan, China. She received her MSc in Petroleum Engineering from the SWPU and her BSc in Petroleum Engineering from Daqing Petroleum University in Heilongjiang, China.
John J. Carroll, PhD, PEng is the Director, Geostorage Process Engineering for Gas Liquids Engineering, Ltd. in Calgary, Canada. Dr. Carroll holds bachelor and doctoral degrees in chemical engineering from the University of Alberta, Edmonton, Canada, and is a registered professional engineer in the provinces of Alberta and New Brunswick in Canada.?His fist book, Natural Gas Hydrates: A Guide for Engineers, is now in its second edition, and he is the author or co-author of 50 technical publications and about 40 technical presentations.
Qi Li, PhD, is the Professor of CCS Research Group at Institute of Rock and Soil Mechanics at the Wuhan Branch of the Chinese Academy of Sciences. He is a geoscientist with expertise in the fields of hydrogeology and engineering mechanics. Professor Li's research is currently focused in the CCS field include mechanical stability of disposal reservoirs, multiphase flow, coupled processes, and risk monitoring. He also involved some research projects using laboratory and numerical tools to design novel subsurface disposal processes and on disposal site monitoring systems on different temporal and spatial scales.
Content
Section 1: Data and Correlations
1 Densities of Carbon Dioxide-Rich Mixtures Part I: Comparison with Pure CO2 1
Erin L. Roberts and John J. Carroll
1.1 Introduction 1
1.2 Density 2
1.3 Literature Review 2
1.4 Calculations 4
1.5 Discussion 19
1.6 Conclusion 27
References 27
2 Densities of Carbon Dioxide-Rich Mixtures Part II: Comparison with Thermodynamic Models 29
Erin L. Roberts and John J. Carroll
2.1 Introduction 29
2.2 Literature Review 30
2.3 Calculations 30
2.4 Lee Kesler 31
2.5 Benedict-Webb- Rubin (BWR) 37
2.6 Peng-Robinson 43
2.7 Soave-Redlich-Kwong 49
2.8 AQUAlibrium 54
2.9 Discussion 60
2.10 Conclusion 62
References 63
3 On Transferring New Constant Pressure Heat Capacity Computation Methods to Engineering Practice 65
Sepideh Rajaeirad and John M. Shaw
3.1 Introduction 65
3.2 Materials and Methods 66
3.3 Results and Discussion 67
3.4 Conclusions 70
References 70
4 Developing High Precision Heat Capacity Correlations for Solids, Liquids and Ideal Gases 73
Jenny Boutros and John M. Shaw
4.1 Introduction 73
4.2 Databases and Methods 75
4.3 Results and Discussion 77
4.4 Conclusion 77
References 77
5 Method for Generating Shale Gas Fluid Composition from Depleted Sample 79
Henrik Sorensen, Karen S. Pedersen and Peter L. Christensen
5.1 Introduction 79
5.2 Theory of Chemical Equilibrium Applied to Reservoir Fluids 80
5.3 Reservoir Fluid Composition from a Non-Representative Sample 83
5.4 Numerical Examples 87
5.5 Discussion of the Results 94
5.6 Conclusions 96
5.7 Nomenclature 97
Greek letters 97
Sub and super indices 97
References 98
6 Phase Equilibrium in the Systems Hydrogen Sulfi de + Methanol and Carbon Dioxide + Methanol 99
Marco A. Satyro and John J. Carroll
6.1 Introduction 100
6.2 Literature Review 101
6.3 Modelling With Equations Of State 102
6.4 Summary 107
6.5 Nomenclature 108
Greek 109
Subscripts 109
References 109
7 Vapour-Liquid Equilibrium, Viscosity and Interfacial Tension Modelling of Aqueous Solutions of Ethylene Glycol or Triethylene Glycol in the Presence of Methane, Carbon Dioxide and Hydrogen Sulfide 111
Shu Pan, Na Jia, Helmut Schroeder, Yuesheng Cheng, Kurt A.G. Schmidt and Heng-Joo Ng
7.1 Introduction 111
7.2 Results and Discussion 112
7.3 Conclusions 122
7.4 Nomenclature 122
7.5 Acknowledgement 125
References 124
Appendix 7.A 125
Section 2: Process Engineering
8 Enhanced Gas Dehydration using Methanol Injection in an Acid Gas Compression System 129
M. Rafay Anwar, N. Wayne McKay and Jim R. Maddocks
8.1 Introduction 129
8.2 Methodology 130
8.3 CASE I: 100 % CO2 132
8.4 CASE II: 50 Percent CO2, 50 Percent H2S 140
8.5 CASE III: Enhanced Oil Recovery Composition 142
8.6 Conclusion 150
8.7 Additional Notes 151
References 151
9 Comparison of the Design of CO2-capture Processes using Equilibrium and Rate Based Models 153
A.R.J. Arendsen, G.F. Versteeg, J. van der Lee,R. Cota and M.A. Satyro
9.1 Introduction 155
9.2 VMG Rate Base 155
9.3 Rate Based Versus Equilibrium Based Models 157
9.4 Process Simulations 162
9.5 Conclusions 173
References 174
10 Post-Combustion Carbon Capture Using Aqueous Amines: A Mass-Transfer Study 177
Ray A. Tomcej
10.1 Introduction 178
10.2 Mass Transfer Basics 179
10.3 Factors Infl uencing Mass Transfer 182
10.4 Examples 188
10.5 Summary 190
References 191
11 BASF Technology for CO2 Capture and Regeneration 193
Sean Rigby, Gerd Modes, Stevan Jovanovic, John Wei, Koji Tanaka, Peter Moser and Torsten Katz
11.1 Introduction 195
11.2 Materials and Methods 197
11.3 Results 206
11.4 Conclusions 223
11.5 Acknowledgements and Disclaimer 225
References 226
12 Seven Deadly Sins of Filtration and Separation Systems in Gas Processing Operations 227
David Engel and Michael H. Sheilan
12.1 Gas Processing and Contamination Control 228
12.2 The Seven Deadly Sins of Filtration and Separation Systems in Gas Processing Operations 231
12.3 Concluding Remarks 240
Section 3: Acid Gas Injection
13 Development of Management Information System of Global Acid Gas Injection Projects 243
Qi Li, Guizhen Liu and Xuehao Liu
13.1 Background 243
13.2 Architecture of AGI-MIS 244
13.3 Data management 246
13.4 Data mining and information visualization 248
13.5 Interactive program 251
13.6 Conclusions 252
13.7 Acknowledgements 252
References 253
14 Control and Prevention of Hydrate Formation and Accumulation in Acid Gas Injection Systems During Transient Pressure/Temperature Conditions 255
Alberto A. Gutierrez and James C. Hunter
14.1 General Agi System Considerations 255
14.2 Composition And Properties Of Treated Acid Gases 256
14.3 Regulatory And Technical Restraints On Injection Pressures 258
14.4 Phase Equilibria, Hydrate Formation Boundaries And Prevention Of Hydrate Formation In Agi Systems 259
14.5 Formation, Remediation And Prevention Of Hydrate Formation During Unstable Injection Conditions - Three Case Studies 263
14.6 Discussion And Conclusions 272
References 273
15 Review of Mechanical Properties Related Problems for Acid Gas Injection 275
Qi Li, Xuehao Liu, Lei Du and Xiaying Li
15.1 Introduction 276
15.2 Impact Elements 276
15.3 Coupled Processes 285
15.4 Failure Criteria 286
15.5 Conclusions 286
15.6 Acknowledgements 287
References 287
16 Comparison of CO2 Storage Potential in Pyrolysed Coal Char of different Coal Ranks 293
Pavan Pramod Sripada, MM Khan, Shanmuganathan Ramasamy, VajraTeji Kanneganti, Japan Trivedi and Rajender Gupta
16.1 Introduction 294
16.2 Apparatus, Methods, & Materials 295
16.3 Results And Discussion 298
16.4 Conclusion 302
References 302
Section 4: Carbon Dioxide Storage
17 Capture of CO2 and Storage in Depleted Gas Reservoirs in Alberta as Gas Hydrate 305
Duo Sun, Nagu Daraboina, John Ripmeester and Peter Englezos
17.1 Experimental 306
17.2 Results And Discussion 307
17.3 Conclusions 310
Reference 310
18 Geological Storage of CO2 as Hydrate in a McMurray Depleted Gas Reservoir 311
Olga Ye. Zatsepina, Hassan Hassanzadeh and Mehran Pooladi-Darvish
18.1 Introduction 312
18.2 Fundamentals 313
18.3 Reservoir 314
18.4 Sensitivity Studies 322
18.5 Long-term storage 326
18.6 Summary and conclusions 327
18.7 Acknowledgements 329
References 329
Section 5: Reservoir Engineering
19 A Modified Calculation Method for the Water Coning Simulation Mode in Oil Reservoirs with Bottom Water Drive 331
Weiyao Zhu, Xiaohe Huang and Ming Yue
19.1 Introduction 331
19.2 Mathematical Model 332
19.3 Solution 334
19.4 Results and Discussion 335
19.5 Conclusions 336
19.6 Nomenclature 336
References 337
20 Prediction Method on the Multi-scale Flow Patterns and the Productivity of a Fracturing Well in Shale Gas Reservoir 339
Weiyao Zhu, Jia Deng and M.A. Qian
20.1 Introduction 340
20.2 Multi-scale flow state analyses of the shale gas reservoirs 340
20.3 Multi-scale seepage non-linear model in shale gas reservoir 343
20.4 Productivity prediction method of fracturing well 348
20.5 Production Forecasting 351
20.6 Conclusions 354
20.7 Acknowledgements 354
References 355
21 Methane recovery from natural gas hydrate in porous sediment using gaseous CO2, liquid CO2, and CO2 emulsion 357
Sheng-li Li, Xiao-Hui Wang, Chang-Yu Sun,Qing-Yuan and Guang-Jin Chen
21.1 Introduction
21.2 Experiments 359
21.3 Results and Discussion 361
21.4 Conclusion 368
21.5 Acknowledgements 369
References 369
Section 6: Hydrates
22 On the Role of Ice-Solution Interface in Heterogeneous Nucleation of Methane Clathrate Hydrates 371
PaymanPirzadeh and Peter G. Kusalik
22.1 Introduction 371
22.2 Method Summary 373
22.3 Results and Discussion 373
22.4 Summary 378
References 379
23 Evaluating and Testing of Gas Hydrate Anti-Agglomerants in (Natural Gas + Diesel Oil + Water) Dispersed System 381
Chang-Yu Sun, Jun Chen, Ke-Le Yan, Sheng-Li Li, Bao-ZiPeng and Guang-Jin Chen
23.1 Introduction 381
23.2 Experimental Apparatus And Analysis 382
23.3 Results And Discussion 382
23.4 Conclusion 385
Section 7: Biology
24 "Is That a Bacterium in Your Trophosome, or Are You Just Happy to See Me?" - Hydrogen Sulfide, Chemosynthesis, and the Origin of Life 387
Neil Christopher Griffin
24.1 Introducing the extremophiles 387
24.2 Tempted by the guts of another 388
24.3 Chemosynthesis 101 389
24.4 Chemosynthetic bacteria and the origins of life 391
References 392
Index 399
Chapter 1
Densities of Carbon Dioxide-Rich Mixtures Part I: Comparison with Pure CO2
Erin L. Roberts and John J. Carroll
Gas Liquids Engineering, Calgary, AB, Canada
Abstract
The design of a gas injection scheme requires knowledge of the physical properties of the injection stream. These are required for both the design of the surface equipment and the modeling flow in the reservoir. One of the important physical properties is the density of the stream. The physical properties of pure carbon dioxide have been measured over a very wide range of pressure and temperature and there are several reviews of these measurements. However, the stream injected in the field is rarely pure carbon dioxide. For acid gas injection, the common impurity is methane and for carbon capture and storage, the common impurity is nitrogen.
This paper reviews the literature for measurements of the density of carbon dioxide with methane containing less than 20 mol% methane and for mixtures of carbon dioxide with nitrogen again with less than 10 mol% nitrogen.
1.1 Introduction
The injection of carbon dioxide into subsurface reservoirs is one tool to combat increasing carbon dioxide in the atmosphere. Typically the CO2 comes from the combustion of fossil fuels, but can also come from other industrial processes such as the production of natural gas.
The transport properties of the fluid to be injected, and the density in particular, are important in the design of these processes. For example, to estimate the pressure required to inject the stream requires the density in order to calculate the hydrostatic head of fluid in the well.
To inject the gas stream it must be compressed to sufficient pressure to achieve injection. It is also important to know the density of the fluid during compression. High speed compressors are not design to handle high density fluids.
The CO2 to be injected is rarely in the pure form. If it is separated from eat natural gas then methane is a common impurity, whereas if it comes from flue gas then the major impurity is nitrogen. These mixtures tend to be rich in carbon dioxide with only a few per cent of impurities.
1.2 Density
Typically the density is expressed as the mass density in kg/m3 or the molar density in kmol/m3. However, depending upon the experimental technique used and the personal preference of the investigator, various other quantities can be used. For example, the specific volume, m3/kg, and molar volume, m3/kmol, are merely reciprocals of the density expression given above.
It is also common to express the density in terms of the compressibility factor or z-factor. The z-factor is defined as
(1.1)
where: ρ – density, kg/m3M – molar mass, kg/kmol
z – compressibility factor, unitless
P – pressure, kPa
R – universal gas constant, 8 314 m3•Pa/kmol•K
T – absolute temperature, K
1.3 Literature Review
A review of the literature was undertaken to find all of the experimental data for the density (in its various forms) for mixtures of CO2+CH4 and CO2 + N2 regardless of the concentration of the various components. The results of that review are summarized in this section and the data of importance to this new study are highlighted.
1.3.1 CO2 + Methane
Table 1.1 summarizes the experimental data for mixtures of carbon dioxide and methane. Many of the density data were taken in association with vapor-liquid equilibrium measurements and thus are the density for the saturated phases.
Table 1.1 Summary of Experimental Measurements of the Density of Carbon Dioxide + Methane Mixtures
The first significant measurements of the densities of CO2 + methane mixtures were those of Reamer et al. [1]. They report compressibility factors for five compositions: pure CO2, 79.65 mol% (91.48 wt%) CO2, 59.44 mol% (80.09 wt%) CO2, 39.50 mol% (64.17 wt%) CO2, and 15.31 mol% (33.15 wt%) CO2. The temperatures and pressure of this study are such that all of the data are for the gas phase. Although the composition is slightly outside of the range of interest in this study, the density for the 79.65% CO2 will be examined in detail.
The paper of Magee and Ely [3] is particularly interesting to this study. They measured the density of a mixture of CO2 (98 mol%) and methane (2 mol%) over a wide range of temperatures -46° to 127°C (-55° to 260°F) and pressures up to 34.5 MPa (up to 5000 psia). However most of their data are for temperatures less than 77°C (170°F); only one isochore1 had measurements as high as 127°C (260°F). They state that the measured densities are accurate to ±0.1%. They also report a few points for the density of pure CO2 and their measured values are almost all within ±0.1% of the calculated value from Span and Wager (1996) with the exception of a single point and there is a typographical error in the table presented by Magee and Ely [3].
1.3.2 CO2 + Nitrogen
As with methane and ethane, there is a significant amount of data available for the density of carbon dioxide nitrogen mixtures. These experimental studies are summarized in Table 1.2.
Table 1.2 Summary of Experimental Measurements of the Density of Carbon Dioxide + Nitrogen Mixtures
1.4 Calculations
An attempt was made to compare the experimental data to the compressibilities of pure carbon dioxide using the principle of corresponding states with pure CO2 as the reference fluid.
Four different methane mixtures were investigated, 2% methane from Magee and Ely [3], two mixtures of 10% methane from Hwang et al. [11] and Brugge et al. [5], and 20% methane from Reamer et al. [1]. The 10% methane mixture from Brugge et al. [5] had data taken entirely in the vapour phase.
One nitrogen mixture of 10% was investigated, with data from two papers by Brugge et al. [5, 12].
An additional data set by Arai et al. [2] containing mixtures ranging from 4.3% to 22% methane was used. However due to each mixture having few data points, all near the critical point, the data was not included in this analysis.
Several methods for estimating the mixture critical properties where employed.
Two objective functions were calculated for all methods to minimize the error. The absolute average difference, AAD, is defined as:
(1.2)
where: NP – number of pointszexp – experimental z-factor
zcalc – calculated z-factor
A similar equation could be used for the densities, however for densities the average absolute errors, AAE, were used.
(1.3)
where: ρexp – experimental densityρcalc – calculated density
Two other error functions were also used in the analysis but not in the optimization. For the compressibility factors the average deviations, AD, were also calculated.
(1.4)
For the density, the average errors were calculated.
(1.5)
1.4.1 Kay’s Rule
As a first approximation the pseudo-critical temperatures and pressures mixture were calculated using Kay’s rule, mole fraction-weighted averages of the pure component properties:
(1.6)
where: pTc – pseudo-critical temperature, KpPc – pseudo-critical pressure, kPa
yi – mole fraction of component i, unitless
(1.7)
where: Tci – critical temperature of component i, KPci – critical pressure of component i, kPa
The critical temperatures and pressures for carbon dioxide, methane, and nitrogen used in this study are summarized in Table 1.3.
Table 1.3 Critical Temperature, Volume, Pressure and Compressibility for Carbon Dioxide, Methane and Nitrogen*
The experimental compressibility factors were compared to those from pure CO2 calculated from the pseudo-reduced pressures and pseudo-reduced temperatures based on Kay’s Rule. For each mixture the results are shown in Figures 1.1 through 1.5. For the 2% methane, only the isotherms of 280 K through 350 K are shown, however all data was included in the error calculations. These plots show that this is a reasonable approach to calculating the z-factors for these mixtures although these can be improved. The AAD for the 2 mol%, 10 mol%, and 20 mol% mixtures are 0.002 75, 0.009 78 [11], 0.001 11 [5], and 0.007 22 respectively. The AAD for the 9% nitrogen mixture was 0.002 13.
Figure 1.1 Experimental and Calculated z-factors Using Kay’s Rule for 2% Methane Mixture [3].
Figure 1.2 Experimental and Calculated z-factors Using Kay’s Rule for 9.9% Methane Mixture 11].
Figure 1.3 Experimental and Calculated z-factors Using Kay’s Rule for 9.9% Methane Mixture [12].
Figure 1.5 Experimental and Calculated z-factors Using Kay’s Rule for 9.1% Nitrogen Mixture [5, 12].
Figures 1.6 through 1.10 show the experimental densities compared to the calculated densities using this approach. The...
