Contents
Cover
Half Title page
Title page
Copyright page
Introduction
Capture
Compression
Pipeline
Injection
Geochemistry
Summary
References
Section 1: Data and Correlation
Chapter 1: Prediction of Acid Gas Dew Points in the Presence of Water and Volatile Organic Compounds
1.1 Introduction
1.2 Previous Studies
1.3 Thermodynamic Model
1.4 Calculation Results
1.5 Discussion
References
Chapter 2: Phase Behavior of China Reservoir Oil at Different CO2 Injected Concentrations
2.1 Introduction
2.2 Preparation of Reservoir Fluid
2.3 PVT Phase Behavior for the CO2 Injected Crude Oil
2.4 Viscosity of the CO2 Injected Crude Oil
2.5 Interfacial Tension for CO2 Injected Crude Oil/Strata Water
2.6 Conclusions
Literature Cited
Chapter 3: Viscosity and Density Measurements for Sour Gas Fluids at High Temperatures and Pressures
3.1 Introduction
3.2 Experimental
3.3 Results
3.4 Conclusions
References
Chapter 4: Acid Gas Viscosity Modeling with the Expanded Fluid Viscosity Correlation
4.1 Introduction
4.2 Expanded Fluid Viscosity Correlation
4.3 Results and Discussion
4.4 Conclusions
4.5 Acknowledgements
References
Chapter 5: Evaluation and Improvement of Sour Property Packages in Unisim Design
5.1 Introduction
5.2 Model Description
5.3 Phase Equilibrium Calculation
5.4 Conclusions
5.5 Future Work
Reference
Chapter 6: Compressibility Factor of High CO2-Content Natural Gases: Measurement and Correlation
6.1 Introduction
6.2 Experiment
6.3 Methods
6.5 Comparison of the Proposed Method and Other Methods
6.6 Conclusions
6.7 Acknowledgements
6.8 Nomenclature
References
Section 2: Process Engineering
Chapter 7: Analysis of Acid Gas Injection Variables
7.1 Introduction
7.2 Discussion
7.3 Program Design
7.4 Results
7.5 Discussion of Results
7.6 Conclusion
References
Chapter 8: Glycol Dehydration as a Mass Transfer Rate Process
8.1 Phase Equilibrium
8.2 Process Simulation
8.3 Dehydration Column Performance
8.4 Stahl Columns and Stripping Gas
8.5 Interesting Observations from a Mass Transfer Rate Model
8.6 Factors That Affect Dehydration of Sweet Gases
8.7 Dehydration of Acid Gases
8.8 Conclusions
Literature Cited
Chapter 9: Carbon Capture Using Amine-Based Technology
9.1 Amine Applications
9.2 Amine Technology
9.3 Reaction Chemistry
9.4 Types of Amine
9.5 Challenges of Carbon Capture
9.6 Conclusion
Chapter 10: Dehydration-through-Compression (DTC): Is It Adequate? A Tale of Three Gases
10.1 Background
10.2 Water Saturation
10.3 Is It Adequate?
10.4 The Gases
10.5 Results
10.6 Discussion
References
Chapter 11: Diaphragm Pumps Improve Efficiency of Compressing Acid Gas and CO2
11.1 Diaphragm Pumps
11.2 Acid Gas Compression
11.3 CO2 Compression for Sequestration
11.4 Conclusion
Literature
Section 3: Reservoir Engineering
Chapter 12: Acid Gas Injection in the Permian and San Juan Basins: Recent Case Studies from New Mexico
12.1 Background
12.2 AGI Project Planning and Implementation
12.3 AGI Projects in New Mexico
12.4 AGI and the Potential for Carbon Credits
12.5 Conclusions
References
Chapter 13: CO2 and Acid Gas Storage in Geological Formations as Gas Hydrate
13.1 Introduction
13.2 Geological Settings
13.3 Model Parameters
13.4 Results
13.5 Discussion
13.6 Conclusions
13.7 Acknowledgment
References
Chapter 14: Complex Flow Mathematical Model of Gas Pool with Sulfur Deposition
14.1 Introduction
14.2 The Mathematical Model of Multiphase Complex Flow
14.3 Mathematical Models of Flow Mechanisms
14.4 Solution of the Mathematical Model Equations
14.5 Example
14.6 Conclusions
14.7 Acknowledgement
References
Section 4: Enhanced Oil Recovery (EOR)
Chapter 15: Enhanced Oil Recovery Project: Dunvegan C Pool
15.1 Introduction
15.3 Pool Event Log
15.4 Reservoir Fluid Characterization
15.5 Material Balance
15.6 Geological Model
15.7 Geological Uncertainty
15.8 History Match
15.9 Black Oil to Compositional Model Conversion
15.10 Recovery Alternatives
15.11 Economics
15.12 Economic Uncertainty
15.13 Discussion and Learning
15.14 End Note
References
Chapter 16: CO2 Flooding as an EOR Method for Low Permeability Reservoirs
16.1 Introduction
16.2 Field Experiment of CO2 Flooding in China
16.3 Mechanism of CO2 Flooding Displacement
16.4 Perspective
16.5 Conclusion
References
Chapter 17: Pilot Test Research on CO2 Drive in Very Low Permeability Oil Field of in Daqing Changyuan
17.1 Introduction
17.2 Laboratory Test Study on CO2 Flooding in Oil Reservoirs with Very Low Permeability
17.3 Field Testing Research
17.4 Conclusion
17.5 Acknowledgement
References
Chapter 18: Operation Control of CO2-Driving in Field Site. Site Test in Wellblock Shu 101, Yushulin Oil Field, Daqing
18.1 Test Area Description
18.2 Test Effect and Cognition
18.3 Conclusions
References
Chapter 19: Application of Heteropolysaccharide in Acid Gas Injection
19.1 Introduction
19.2 Application of Heteropolysaccharide in CO2 Reinjection Miscible Phase Recovery
19.3 Application of Heteropolysaccharide in H2S Reinjection formation
19.4 Conclusions
References
Section 5: Geology and Geochemistry
Chapter 20: Impact of SO2 and NO on Carbonated Rocks Submitted to a Geological Storage of CO2: An Experimental Study
20.1 Introduction
20.2 Apparatus and Methods
20.3 Results and Discussion
20.4 Conclusion
Acknowledgments
References
Chapter 21: Geochemical Modeling of Huff ‘N’ Puff Oil Recovery With CO2 at the Northwest Mcgregor Oil Field
21.1 Introduction
21.2 Northwest McGregor Location and Geological Setting
21.3 The Northwest McGregor Field, E. Goetz #1 Well Operational History
21.4 Reservoir Mineralogy
21.5 Preinjection and Postinjection Reservoir Fluid Analysis
21.6 Major Observations and the Analysis of the Reservoir Fluid Sampling
21.7 Laboratory Experimentations
21.8 2–D Reservoir Geochemical Modeling with GEM
21.9 Summary and Conclusions
21.10 Acknowledgments
21.11 Disclaimer
References
Chapter 22: Comparison of CO2 and Acid Gas Interactions with Reservoir Fluid and Rocks at Williston Basin Conditions
22.1 Introduction
22.2 Rock Unit Selection
22.3 CO2 Chamber Experiments
22.4 Mineralogical Analysis
22.5 Numerical Modeling
22.6 Results
22.7 Carbonate Minerals Dissolution
22.8 Mobilization of Fe
22.9 Summary and Suggestions for Future Developments
22.10 Acknowledgments
22.11 Disclaimer
References
Section 6: Well Technology
Chapter 23: Well Cement Aging in Various H2S-CO2 Fluids at High Pressure and High Temperature: Experiments and Modelling
23.1 Introduction
23.2 Experimental Equipment
23.3 Materials, Experimental Conditions and Analysis
23.4 Results and Discussion
23.5 Reactive Transport Modelling
23.6 Conclusion
Acknowledgments
References
Chapter 24: Casing Selection and Correlation Technology for Ultra-Deep, Ultra- High Pressure, High H2S Gas Wells
24.1 Introduction
24.2 Material Selection Recommended Practice
24.3 Casing Selection and Correlation Technology
24.4 Field Applications
24.4 Conclusions
24.5 Acknowledgments
References
Chapter 25: Coupled Mathematical Model of Gas Migration in Cemented Annulus with Mud Column in Acid Gas Well
25.1 Introduction
25.2 Coupled Mathematical Model
25.3 Illustration
25.4 Conclusions
25.5 Nomenclature
25.6 Acknowledgment
References
Section 7: Corrosion
Chapter 26: Study on Corrosion Resistance of L245/825 Lined Steel Pipe Welding Gap in H2S+CO2 Environment
26.1 Introduction
26.2 Welding Process of Lined Steel Pipe
26.3 Corrosion Test Method of Straight and Ring Welding Gaps of L245/825 Lined Steel Pipe
26.4 Corrosion Test Results of Straight and Ring Welding Gaps of 1245/825 Lined Steel Pipe
26.5 Conclusions
26.6 Acknowledgments
References
Index
Also of Interest
Carbon Dioxide Sequestration and Related Technologies
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Introduction
The Three Sisters – CCS, AGI, and EOR
Ying Wu1 John J. Carroll2 Zhimin Du3
1 Sphere Technology Connection, Calgary, AB, Canada
2 Gas Liquids Engineering, Calgary, AB, Canada
3Southwest 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 dioxide 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.
Table 1. The th ree sis ters: CCS, AGl, and EaR.
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 CO2. On the other hand, the purpose of injecting CO2 for EOR is to produce more oil. Burns [1], in a chapter in this volume discusses, the economics of an EOR project. Nonetheless, sequestration of CO2 is a by-product of these EOR schemes. For CCS the purpose is simply to eliminate carbon emission into the atmosphere. However, CO2 captured from flue gas may have value as a source of virgin CO2 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 contains 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 CO2 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 CO2. However there are many problems associated with capturing CO2 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 natural 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 CO2 from flue gas. Among the problems Spooner and Engel address are the high oxygen content 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” CO2. Once the project starts, some of the CO2 will be produced with the oil. This CO2 is recovered from the oil and used for re-injection. Initially the recycled CO2 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 subsurface reservoir.
In EOR the virgin CO2 is usually delivered at such a pressure that little or no compression is required. However the recycled CO2 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 CO2 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 compression 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 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 CO2 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 pattern, some for injecting CO2 and some for producing oil. It is also possible to use CO2 for huff’n puff. This involves injecting CO2 for a period of time and then allowing the CO2 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 behavior 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 CO2, 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].
Summary
The three sisters: CCS, AGI, and EOR share many common components. 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, F. 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 Technobgies, 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 CO2”, 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 CO2 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. Talman, 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
Chapter 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 configuration, 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 hydrocarbon 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 (L1) dew points in acid gas systems. The objective 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.
1.1 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 environmental contamination is often linked to leakage from underground gasoline storage tanks or accidental spills. Awareness of this toxicity led to regulated clean air emission standards that directly impact the natural gas processing industry as trace amounts of BTEX compounds are associated with produced fluids such as natural gas.
Sour gas production generally involves a subsequent processing step in which the hydrogen sulphide (H2S) and carbon dioxide (CO2) are removed to produce an acid gas stream that may be a candidate for acid gas injection. Liquid solvents that are used to remove the H2S and CO2 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 involving 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 unexpected formation of a sour non-aqueous liquid phase in the compressor 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 present in the acid gas, there is a need for accurate vapor-liquid equilibria (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) presented valuable operating data for a Canadian gas plant using MDEA in which measured BTEX compositions were reported. McIntyre et al. (2001) and Bullin and Brown (2004) tabulated the experimental data available for hydrocarbon and BTEX solubility in amine treating solutions and demonstrated general trends in amine plant BTEX absorption using computer simulation. Valtz et al. (2002) presented a comprehensive set of fundamental solubility data for aromatic hydrocarbons in aqueous amine solutions. Miller and Hawthorne (2000) and Jou and Mather (2003) measured the solubility of BTEX compounds in water.
Clark et al. (2002) measured bubble and dew points for a nominal 10 mol% H2S/90 mol% CO2 mixture and regressed an equation of state to match the phase envelope. Satyro and van der Lee (2009) demonstrated that with suitable modification to interaction parameters, a cubic equation of state can provide reliable predictions of phase behavior in sour gas mixtures.
1.3 Thermodynamic Model
A rigorous treatment of the complex phase behavior in the H2S-CO2-water-BTEX system was beyond the scope of this work, which was intended to be exploratory in nature. The Peng-Robinson equation-of-state with classical van der Waals mixing rules was used in this study. The interaction parameter for the H2S-CO2 binary was set to 0.1 and all others were set to zero. Table 1 contains the critical properties used for the system components.
Table 1. Compo ne nt cri tica l proper ties.
The performance of the Peng-Robinson equation of state has been well documented in the literature. The model reproduced the dew point locus of Clark et al. (2002) to within 2.5%.
1.4 Calculation Results
The conditions of the calculations were chosen to encompass those normally found in acid gas injection compression: pressures from 150 kPa to 10 MPa, and temperatures above the hydrate formation curve from 0° to 100°C. Three different nominal acid gas compositions were considered: 20/80, 50/50, and 80 mole% H2S/20 mole% CO2. Hydrocarbon components studied included: benzene, toluene, ethyl benzene and dimethyl benzenes (xylenes).
The model was used to generate the phase envelope for each of the three nominal acid gas compositions. The influence of associated water on the location of the bubble and dew-point loci was not considered in this work. A typical injection profile was generated for each nominal composition using a starting pressure of 150 kPa and constant compression ratio. Temperatures in the compression process were restricted to remain under 150°C. Cooling temperature was set to 50°C. The final pressure was selected to be under 10 MPa but above the mixture critical point.
Initial calculations indicated that the phase behavior of the acid gas mixtures in the presence of each of the three xylene isomers was similar. For simplicity only o-xylene was considered in this study.
To establish a reasonable range of BTEX compositions, a sensitivity study was undertaken using pure H2S. The model was used to determine the L1 dew point temperature at 4000 kPa using various compositions of benzene and o-xylene ranging from 0 to 5000 ppmv. The results are shown in Figure 1.1 Below concentrations of 100 ppmv, the aromatic compounds increase the dew point temperature by less than 1°C. Hegarty and Hawthorne (1999) reported BTEX content of up to 2500 ppmv in the acid gas of an operating MDEA plant. Using this as a guideline, non-aqueous liquid (L1) dew points were calculated for each of the three nominal acid gas compositions with 500-, 2000- and 5000 ppmv of each of the four aromatic compounds.
Clearly this range of calculated points generated a significant amount of data. The results for the 2000 ppmv cases are presented in Figures 2 through 4 and provide an adequate representation of the general trends that were observed. Note that curves labeled as organic compounds represent the dew point loci for the acid gas mixture with 2000 ppmv of only that organic compound.
Using data from McIntyre et al. (2001) for BTEX component distribution in the acid gas from an MDEA plant as a guideline, flash calculations were performed at 50°C for the mixture given in Table 2. Identical calculations were performed for a mixture containing 80 mol% H2S and 20 mol% CO2. The results are shown in Table 3.
Table 2. Composition of mixture used for condensation study.
| Component |
Composition, mol % |
| Hydrogen Sulphide |
79.82 |
| Carbon Dioxide |
19.955 |
| Benzene |
1000 ppmv |
| Toluene |
750 ppmv |
| Ethyl Benzene |
250 ppmv |
| o-Xylene |
250 ppmv |
Table 3. Condensation study results at 50°C.
| Pressure, kPa |
Volume% L1, BTEX Mixture |
Volume % L1, 80/20 H2S/CO2 |
| 3268.3 |
Dew point P |
|
| 3400 |
0.009 |
0 |
| 3600 |
0.031 |
0 |
| 3800 |
0.074 |
0 |
| 4000 |
0.169 |
0 |
| 4200 |
0.420 |
0 |
| 4400 |
1.29 |
0 |
| 4466.6 |
|
Dew point P |
| 4600 |
3.90 |
2.46 |
| 4800 |
8.55 |
7.29 |
| 5000 |
15.6 |
14.2 |
| 5200 |
26.6 |
24.8 |
| 5400 |
45.4 |
42.5 |
| 5600 |
82.8 |
77.2 |
| 5654.1 |
Bubble point P |
|
| 5674.5 |
|
Bubble point P |
1.5 Discussion
In the absence of experimental data for dew point conditions in acid gases with contaminants, there can be no absolute conclusions drawn on the accuracy of the predictions. This exploratory study clearly emphasizes the importance of experimental research to provide fundamental information for process design and advanced model development. The results in Figures 2 through 4 illustrate that with conservative cooling temperatures and with BTEX contaminant levels in the range of those already measured in an operating MDEA plant, it is possible to enter the three-phase region in the higher pressure interstage coolers and separators in acid gas injection facilities. More aggressive cooling escalates the potential for three-phase conditions.
The formation of a second liquid phase in the compression interstage cooling system, in itself is not a problem, provided that the phase behavior phenomenon is understood at design time. The L1 phase is less dense than water, contains up to 20 mol% BTEX and, if formed, will accumulate in the interstage separators. As pointed out by Hegarty and Hawthorne (1999), it is extremely important to obtain an accurate inlet gas composition, including an extended analysis of the C6+ fraction to determine the aromatic content. Once the BTEX content, if any, is identified it can be accounted for in any process design, modeling, or operational troubleshooting of downstream processes such as acid gas injection.
In spite of the purely predictive nature of the calculated results, the following general observations can be made by analyzing Figures 2 through 4. The same behavior is observed in the 500 ppmv and 5000 ppmv calculated results.
- At a given pressure, the presence of BTEX compounds in acid gas widens the phase envelope, with this effect being more pronounced in acid gases with higher CO2 content.
- At a given pressure, the presence of BTEX compounds in acid gas increases the L1 dew point temperature, with this effect being more pronounced in acid gases with higher H2S content. This is, in part, a result of the shift of the acid gas phase envelope to higher temperatures in high H2S mixtures.
- At equal concentration in the acid gas and at equal pressure, BTEX compounds increase the L1 dew point temperature in the order: benzene, toluene, ethyl benzene and o-xylene with o-xylene having the most pronounced effect.
- In all cases, the possibility of non-aqueous L1 formation is highest in the separator before the final stage of compression.
- If compressed acid gas is cooled to lower temperatures (e.g. 30°C) in the compressor facility, this increases the possibility of L1 formation.
- If BTEX compounds are present in the acid gas at levels less than 100 ppmv, the acid gas dew point locus is relatively unaffected.
The dew point loci shown in Figures 2 through 4 indicate where the first droplet of L1 forms. Table 3 contains an example of the condensation behavior inside the phase envelope at constant temperature. Note that the condensation behavior of the BTEX mixture is similar to the BTEX-free system except for the deep depression of the dew point pressure. Lines of constant liquid volume % are widely spaced in this region of the phase envelope. This behavior is similar to the condensation behavior of rich gas systems. The location of the bubble point is relatively unaffected by the organic compounds.
References
Bullin, Jerry A. and William G. Brown, “Hydrocarbons and BTEX Pickup and Control from Amine Systems”, Proceedings of the 83rd Gas Processors Association Annual Convention, New Orleans, March 14–17, 2004.
Clark, M.A., W.Y. Svrcek, W.D. Monnery, A.K.M. Jamaluddin and E. Wichert, “Acid Gas Water Content and Physical properties: Previously Unavailable Experimental Data for the Design of Cost Effective Acid gas Disposal Facilities, and Emission Free Alternative to Sulfur Recovery Plants”, Hycal Energy Research Laboratories, 2002.
Hegarty, Mike and Dean Hawthorne, “Application of BTEX/Amine VLE Data at Hanlan Robb Gas Plant”, Proceedings of the 78th Gas Processors Association Annual Convention, Nashville, March 1–3, 1999.
Jou, Fang-Yuan and Alan E. Mather, “Liquid-Liquid Equilibria for Binary Mixtures of Water+Benzene, Water+Toluene and Water+p-Xylene from 273K to 458K”, J. Chem. Eng. Data, 48, 750–752 (2003)
McIntyre, G.D., V.N. Hernandez-Valencia and K.M. Lunsford, “Recent GPA Data Improves BTEX Predictions for Amine Sweetening Facilities”, Proceedings of the 80th Gas Processors Association Annual Convention, San Antonio, March 12–14, 2001.
Miller, David J. and Steven B. Hawthorne, “Solubility of Liquid Organics of Environmental Interest in Subcritical (Hot/Liquid) Water from 298K to 473K”, J. Chem. Eng. Data, 45, 78–81 (2000).
Ng, Heng-Joo, John J. Carroll and James Maddocks, “Impact of Thermophysical Properties Research on Acid Gas Injection Process Design”, Proceedings of the 78th Gas Processors Annual Convention, Nashville, March 1–3, 1999.
Satyro, Marco A. and James van der Lee, “The Performance of State of the Art Industrial Thermodynamic Models for the Correlation and Prediction of Acid Gas Solubility in Water”, Proceedings of the First International Acid Gas Injection Symposium, Calgary, Alberta, Canada, October 5–6, 2009.
Valtz, A., P. Guilbot and D. Richon, “Amine BTEX Solubility”, Gas Processors Association Research Report RR-180, 2002.
Chapter 2
Phase Behavior of China Reservoir Oil at Different CO2 Injected Concentrations
Fengguang Li Xin Yang Changyu Sun Guangjin Chen
State Key Laboratory of Heavy Oil Processing, China University of Petroleum Beijing, People’s Republic of China
Abstract
The phase behavior of China reservoir oil at different CO2 injected concentrations has been studied at the temperature of 339.2 K using a high-pressure PVT unit. Seven groups of reservoir fluids with CO2 molar contents of 0, 10.0, 34.1, 44.7, 48.9, 57.8, and 65.0 mol% have been prepared. Saturation pressure of reservoir fluids at seven CO2 injected contents were measured. The reservoir oil density and viscosity at different pressures under reservoir temperature were also obtained. The influence of CO2 molar contents on the interfacial tension of CO2 injected reservoir oil under stratum conditions was determined using a pendant drop method. The experimental data indicated that when CO2 content is lower than 45 mol%, the increase of bubble point pressure is slow. After that, the bubble point pressure value increases more sharply with the increase of CO2 molar concentrations. The reservoir viscosities decrease sharply with the increase of CO2 concentration when the system pressure is above the bubble point for different injection contents. The experimental results of interfacial tension for CO2 injected crude oil/stratum water show that it decreases with the increase of CO2 injected concentrations. The pressure has a slight effect on the interfacial tension value. These phase behavior data will be helpful for evaluating the effect of CO2 injected method to enhance oil recovery.
2.1 Introduction
The fluid phase behavior study is used as an important basis for miscible-slug process and predominant displacement mechanism, which is of critical importance during the miscible displacement process (1). The conventional fluid phase behavior test is usually conducted using PVT (Pressure-Volume-Temperature) unit. It is of great concern in many high-pressure technologies, such as fluid extraction process, exploration of near-critical gas condensate/volatile oil reservoir, and gas-injected enhanced oil recovery processes. CO2 displacement technology is recognized as a significant and well-established means for oil and gas enhanced recovery both at home and abroad. Miscible gas injection could minimize the trapping effect of capillary forces and is recognized as an economic enhanced oil recovery process.
Although some PVT fluid phase behavior data are available in the published papers, they are still insufficient because of the complexity of multi-component reservoir fluid. In this work, the phase behavior of China reservoir fluids collected from Jilin oil field were analyzed at different CO2 injected concentrations and pressures using a high-pressure PVT device. The density, bubble point pressure, viscosity, and interfacial tension properties of reservoir fluid at different CO2 injected mole percents and pressures under the stratum temperature were systematically measured.
2.2 Preparation of Reservoir Fluid
The reservoir fluid sample was collected from China Jilin oil field at reservoir conditions. The stratum temperature was 339.2K. The reservoir fluid arriving from the well was separated and flashed to standard condition. The molar composition of reservoir fluids was then obtained from analysis of the gas and oil samples. The gas phase was analyzed by HP6890 gas chromatograph. The liquid phase was analyzed by simulating distillation process using HP5890A. Afterwards, the reservoir fluid composition was obtained by combining the gas and liquid phase compositions using the gas–oil ratio (GOR). The measured composition for reservoir fluid was shown in Table 1. Molecular weights of the oil phase were determined by vapor pressure osmometer (VPO) and the determined molecular weight was 420 g/mol.
Table 1. The composition of reservoir fluid.
Seven groups of CO2 injected concentration (including 0% CO2) were chosen to study the reservoir fluid behavior under gas injection process. The CO2 injected crude oil was prepared using RUSKA PVT device.
2.3 PVT Phase Behavior for the CO2 Injected Crude Oil
Phase behavior of China reservoir oil was systematically investigated using a RUSKA high-pressure PVT system which was described in our previous papers (2,3). The PVT data at different CO2 injected molar components was measured to build the relationship between the volume and pressure of reservoir oil. The bubble point pressure and density of reservoir fluid at different pressures could then be determined according to the measured PVT data, which is useful to calculate the phase behavior properties such as the relatively volume, solubility of injected CO2 in oil, and so on.
The density of the CO2 injected reservoir fluid at different pressure under the strata temperature was plotted in Figure 1. From Figure 1, it can be found that there exists an inflexion for the curve of reservoir fluid density and pressure, showing the process of phase transition. When the CO2 concentration achieves 65.0 mol%, there is no significant difference between the gas phase and liquid phase, showing that there may exhibit first contact miscibility condition when the CO2 injected contents is 65.0 mol%.
The bubble point pressure at seven CO2 molar compositions determined from PVT measurement was shown in Figure 2. According to Figure 2, it shows that bubble point pressure increases with the increase of CO2 injected concentrations. When CO2 content is lower than 45 mol%, the increase of bubble point pressure is slow. However, when CO2 content is higher than 45 mol%, the bubble point pressure value increases more sharply with the increase of CO2 molar concentrations. The bubble point pressure data is also used to choose the suitable CO2 injected concentration.
2.4 Viscosity of the CO2 Injected Crude Oil
Viscosity is an important transport property in petroleum production and processing. RUSKA falling ball viscometer connected with RUSKA high-pressure PVT device was used in this work to investigate the viscosity of China Jilin oil samples after different CO2 content was injected under stratum conditions.
The basic principle of falling ball viscometer is based on Stokes law. The fluid viscosity could be exactly calculated by Stokes law according to the time of the ball travels through internal pipe from the top to the bottom. If the falling ball behaves to be laminar flow, the following equation was used:
(1) 
where ρB and ρF are the density of the ball and fluid, respectively. t is the travel time. k is a constant value related to the diameter of the falling ball and the angel of the apparatus. Before the experiment, a falling ball was selected to measure the constant value k in Eqn. (1) using standard silicon oil for the viscometer. Thereafter, the reservoir crude oil viscosities were systematically measured with the same calibrated ball at different CO2 injected molar concentrations and pressures. The reservoir fluid viscosity was tested from higher pressure under single phase conditions until close to the saturation pressure. After the pressure was lower than the bubble point pressure, a gas exhaust valve was open to slowly reduce to the experimental pressure and the stable time was prolonged to 4–5 h. The measured viscosity for CO2 injected crude oil at different CO2 mole percents and pressures were plotted in Figure 3.
As shown in Figure 3, the viscosity for CO2 injected crude oil decreased apparently with increasing of CO2 content. When the CO2 injected amount changed from 0 to 65.0 mol%, the reservoir oil viscosity value decreased greatly. At about 30 MPa, the viscosity value can decrease from 10.6 cP to 1.1 cP when 65 mol% CO2 was injected. It can be found that when the experimental pressure is higher than the saturated value, the reservoir oil viscosity increases with the increase of pressure; When it is lower than the saturated pressure, the reservoir oil viscosity increases with the decrease of pressure. With the decrease of pressure, more CO2 was released from the reservoir oil and induced the increase of viscosity of the residual oil.
From Figure 3, it can be concluded that CO2 injecting is significant in favor of the decrease of viscosity of Jilin reservoir crude oil. However, after CO2 content was higher than 44.7 mol%, the reservoir oil viscosity at single phase condition does not decrease significantly with the further increase of CO2 injecting concentration. Meanwhile, During the CO2 injecting concentration increases from 0 to 44.7 mol%, the bubble point pressure only increases from 11.28 MPa to 14.14 MPa. However, when the CO2 injected concentration increases from 44.7 mol% to 65.0 mol%, the bubble point pressure increases from 14.14 MPa to 25.0 MPa. Therefore, from the view of decrease of viscosity and bubble point pressure, there exists a suitable CO2 injecting concentration and high CO2 concentration is not needed.
2.5 Interfacial Tension for CO2 Injected Crude Oil/Strata Water
A great amount of reservoir water exists in the stratum after water displacement process of oil field. There is a special need for accurate interfacial tension estimation because the movement of reservoir fluids is influenced to a great extent by capillary forces. The CO2 injected concentration also plays an important role on the interfacial phenomena. In this work, the influence of CO2 molar contents on the interfacial tension of injected crude oil/water was systematically investigated using the JEFRI pendant drop high-pressure interfacial tension apparatus manufactured by D.B. Robinson (Canada), which the maximum working pressure is 34.5 MPa (5,000 psi) and the operating temperature range is 253–473 K. The experimental apparatus and procedures were detailed described in our previous papers (4,5). The interfacial tension measurement is based on the following principle:
If the drop is in equilibrium with its surroundings gas, the interfacial tension (γ) values can be calculated directly from an analysis of the stresses in the static, pendant drop, using the following equations developed by Andreas et al. (6):
(2) 
(3) 
where Δρ is the density difference between the two phases, De is the unmagnified equatorial diameter of the drop, g is the gravitational constant, ds is the diameter of the drop at a selected horizontal plane at height equal to the maximum diameter de. Andreas et al. have prepared a detailed table of 1/H as a function (ds/de).
The difference in density between reservoir oil and water could be calculated from the measured density data. The interfacial tension of CO2 injected crude oil/reservoir water were all measured under single-phase conditions at the stratum temperature. The measured interfacial tension data for CO2 injected reservoir oil/water at different CO2 injected molar concentrations and pressures are plotted in Figure 4.
As shown in Figure 4, the interfacial tension for CO2 injected oil/reservoir water decreased apparently with the increase of CO2 injected molar concentration when CO2 content varies from 0 to 65.0 mol%. The dissolvability of CO2 in oil has a significant influence on the interfacial tension value. The interfacial tension decreased by about one-third as the CO2 injected amount changed from 0 to 65.0 mol%. It also shows that the interfacial tension of the CO2 injected crude oil/water increased with increasing pressure. During the experiment process, the experimental pressure was always higher than the bubble point pressure at the corresponding CO2 injected condition. Compared with the effect of CO2 injected amounts, the pressure has only a slightly effect. When the CO2 composition was 65.0 mol%, the CO2 injected oil system approached complete miscibility and the interfacial tension data of CO2 injected crude oil/reservoir water changed a little with an increase in pressure.
2.6 Conclusions
The phase behavior of reservoir oil collected from China Jilin oil field was systematically investigated by using a high-pressure RUSKA PVT device at different CO2 injected concentrations and pressures under strata temperature. Seven groups of CO2 injected concentrations varying from 0 to 65.0 mol% were prepared. The bubble point pressure increases from 11.28 MPa to 25.0 MPa when CO2 content increases from 0 to 65.0 mol%. When the CO2 concentration achieves 65.0 mol%, there is no significant difference between the gas phase and liquid phase, showing that there may exhibit first contact miscibility condition under the corresponding CO2 injected content. The viscosity for CO2 injected crude oil decreased apparently with increasing of CO2 content. CO2 injecting is significant in favor of the decrease of viscosity of Jilin reservoir crude oil. However, after CO2 content was higher than 44.7 mol%, the reservoir oil viscosity under single phase condition does not decrease significantly with the further increase of CO2 injecting concentration. The interfacial tension for CO2 injected oil/reservoir water decreased apparently with the increase of CO2 injected molar concentration when CO2 content varies from 0 to 65.0 mol%. When the CO2 composition was 65.0 mol%, the CO2 injected oil system approached complete miscibility and the interfacial tension data of CO2 injected crude oil/reservoir water changed a little with an increase in pressure.
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