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Sensitivity analysis of CO2 sequestration in saline aquifers

Sensitivity analysis of CO2 sequestration in saline aquifers 372 372 Pet.Sci.(2010)7:372-378 DOI 10.1007/s12182-010-0080-2 Sensitivity analysis of CO sequestration in saline aquifers Zhao Hongjun, Liao Xinwei , Chen Yanfang and Zhao Xiaoliang Key Laboratory of Petroleum Engineering, Ministry of Education, China University of Petroleum, Beijing 102249, China © China University of Petroleum (Beijing) and Springer-Verlag Berlin Heidelberg 2010 Abstract: Carbon capture and storage (CCS) technology has been considered as an important method for reducing greenhouse gas emissions and for mitigating global climate change. Three primary options are being considered for large-scale storage of CO in subsurface formations: oil and gas reservoirs, deep saline aquifers, and coal beds. There are very many large saline aquifers around the world, which could make a big contribution to mitigating global warming. However, we have much less understanding of saline aquifers than oil and gas reservoirs. Several mechanisms are involved in the storage of CO in deep saline aquifers, but the ultimate goal of injection of CO into the aquifers containing salt water is to dissolve the CO in the water. So it is important to study the solubility trapping and sensitivity factors of CO in saline aquifers. This paper presents results of modeling CO storage in a saline aquifer using 2 2 the commercial reservoir simulator ECLIPSE. The objective of this study was to better understand the CO /brine phase behavior (PVT properties) and quantitatively estimate the most important CO 2 2 storage mechanism in brine-solubility trapping. This would provide a tool by performing theoretical and numerical studies that help to understand the feasibility of CO geological storage. A 3-dimensional, 2-phase (water/gas) conceptional reservoir model used finite, homogenous and isothermal formations into which CO is injected at a constant rate. The effects of main parameters were studied, including the vertical to horizontal permeability ratio k /k , salinity, and residual phase saturations. The results show that v h the vertical to horizontal permeability ratio has a signifi cant effect on CO storage. Moreover, more CO 2 2 dissolves in the brine at lower k /k values. v h Key words: CO geologic sequestration, saline aquifer, solubility trapping, numerical simulation 2, Geological storage of anthropogenic CO as a greenhouse 1 Introduction gas mitigation option was first proposed in the 1970s, but The concentration of CO in the atmosphere has gradually 2 little research was done until the early 1990s, when the increased in the last 250 years due to human activities, leading idea gained credibility through the work of individuals and to measurable global warming. The Intergovernmental Panel research groups (Marchetti, 1977; Kaarstad, 1992; Koide et on Climate Change (IPCC) has projected that for a ‘business al, 1993; van der Meer, 1992; Gunter, 1993; Holloway and as usual’ energy scenario the atmospheric concentration of Savage, 1993; Bachu et al, 1994; Korbol and Kaddour, 1995). CO may double by the middle of the 21st century, and may 2 In 1996, the world’s first large-scale storage project was continue to rise at increasing rates beyond (Houghton, 1996). initiated by Statoil and its partners at the Sleipner Gas Field Climate modeling shows that a rise of 0.3-0.6 °C in the near- in the North Sea (IPCC, 2005). earth-surface temperature could result from the increased Three main alternatives have been considered for large- concentration of CO in the atmosphere during the last 150 2 scale storage of CO in subsurface formations (Orr et al, years (Ledley et al, 1999). Experts agree that a number of 2003): depleted oil and gas reservoirs, deep saline aquifers, actions should be taken soon in order to reduce the amount of and coal beds. Among these, saline aquifers can effectively CO entering the atmosphere. One of the important means is 2 contribute to CO sequestration because of their large to capture millions of tonnes of CO produced by industrial 2 capacity and broad distribution around the world. However, processes and sequester CO deep underground − this is 2 we know very little about saline aquifers when compared to known as CO capture and geological storage (CCS) (IEA, 2 our understanding of oil and gas reservoirs. In this study we 2007). use the ECLIPSE simulator to investigate the fl ow of CO in brine by considering the solubility effect and the sensitivity analysis of various parameters. It is very important to predict leakage risk and for the implementation of fi eld projects. *Corresponding author. email: xinwei@cup.edu.cn Received May 11, 2009 Pet.Sci.(2010)7:372-378 373 373 and 50 ºC, respectively. Table 1 summarizes the base case 2 Mechanisms of CO sequestration in saline input parameters including aquifer parameters and injection aquifers conditions. Pure CO is injected at a constant rate for 15 years. Our simulation domain is in one quarter of a fi ve spot pattern, Four principal mechanisms for sequestering CO in saline in which four production wells are located at the corners of a aquifers have been described in the literature. square and the injection well sits in the center. The distance Hydrodynamic trapping In a storage project, supercritical between the injection and production wells is 3,400 m. The CO will be injected as a single phase, but once in the production well is controlled by bottom hole pressure (BHP). geological formation it will partition into free-phase The main substances to be taken into account when (immiscible) CO and a CO -rich brine. The flow of the 2 2 describing flow and transport during CO sequestration free-phase CO is dependent on the dip of the sealing horizon 2 are CO , formation water, and salinity (salt), of course, the and the flow velocity and direction of the in situ formation 2 rock matrix that forms the porous medium. Water and CO water. Saline aquifers generally have very low fl ow velocities, 2 are defined as two components. Salts are not considered of the order of tens of cm/year. This slow fl ow velocity leads as an independent component, but considered a corrected to residence times of millions of years. This geological time- coeffi cient in the equation of state (EOS). Therefore, a two- scale trapping of CO in deep regional aquifers is called phase two-component model was chosen (which refers to the hydrodynamic trapping (Finley et al, 2005). In the short water-rich phase as a liquid and the CO -rich phase as a gas) term, this is likely to be the most important mechanism for 2 for the following study. sequestration (Pruess, 2004). Solubility trapping When CO is injected into a reservoir, Table 1 Summary of the aquifer properties and injection conditions a portion of the injected CO will dissolve in the formation water in the aquifer and the dissolution of CO per unit volume of water is a function of pressure, temperature, and Reservoir size (m×m×m) 2500×2500×50 salinity of the aqueous phase (Holtz, 2002). The aqueous (length, width and thickness) phase will retain the dissolved CO regardless of being x 100 stationary or transported to another location as long as the Permeability y 100 physical conditions are undisturbed. CO -saturated formation mD water is denser than water not containing CO . The difference z 10 in density of CO -saturated aquifer water and virgin formation Porosity, % 0.18 water triggers convection currents in the aquifer beneath the CO plume, and accelerate the efficiency of dissolution 2 Top depth, m 1000 (Ennis-King and Paterson, 2005). Number of grids 50×50×5 Residual trapping Most of the CO injected into a saline -1 -6 Rock compressibility, psi 0.55×10 aquifer migrates upward as a separate CO -rich phase. During this upward migration two different displacement processes Temperature, ºC 50 are active; namely, gravity drainage and imbibition. At the tail Residual water saturation 0.3 of the migrating CO plume, formation water invades the CO 2 2 plume. Due to relative permeability and capillary hysteresis a Residual CO saturation 0.1 fraction of the non-wetting phase is trapped in the imbibition Salinity, mol/kg 0-4 process. When the concentration of CO falls below a certain level CO becomes trapped by capillary pressures and ceases CO injection rate, Mscf/day 10000 to flow. This process is commonly referred to as residual Boundary condition No-fl ow trapping (Felett et al, 2004; Kumar et al, 2005). Injection time, Years 15 Mineral trapping CO can react with minerals and organic matter in geological formations to form precipitates Simulation time, Years 30 (Pruess et al, 2003). This trapping will create stable Injection interval Block (1, 1, 5) repositories of CO that decreases mobile hazards such as leakage to the surface (Nghiem et al, 2004). Initial pressure, psi 1500 Initial Water saturation S 1.0 3 Simulation model descriptions conditions co X 0 3.1 Model conditions 3. 2 Phase properties of CO -brine systems The purpose of this study was to illustrate the processes CO has a high solubility in the aqueous phase in saline occurring during CO injection and investigate the effects of aquifers due to high pressures. The dissolution of CO in reservoir parameters. The simulations assume an isotropic and formation water occurs through mass transfer from the homogenous aquifer with a horizontal permeability of 100 CO phase to the aqueous phase whenever the phases are in mD, porosity of 0.18, and 50 m of thickness. The impermeable contact. The excess CO phase and the aqueous phase are top layer of the aquifer is located at a depth of 1,000 m thereby assumed to be in thermodynamic equilibrium in the with a corresponding pressure and temperature of 1,500 psi 374 Pet.Sci.(2010)7:372-378 model. The Peng-Robinson equations of state were modifi ed dissolves in the formation brine as the horizontal permeability following the suggestions of Søreide and Whitson (1992) to increases, but the effect of horizontal permeability is very obtain accurate gas solubility in the aqueous phase (Eclipse small. During the injection period CO migrates mostly as a Technical Manual, 2005). gas phase and only about 5%-10% of the CO dissolves in Both gas and water density values were obtained from brine. The total injection gas (Field Gas in Place Total, FGIT) the equation of state. Brine density, which is a function of and the gas dissolved in liquid (Field gas in place liquid, temperature and pressure as well as the contributions of FGIPL) for different horizontal permeability reservoirs are salinity and dissolved CO , was described as the sum of pure shown in Fig. 1. water density and additional density caused by salinity and 6E+7 dissolved CO . Brine viscosity is a strong function of temperature. It also 5E+7 depends on salinity, pressure, and dissolved CO , the Lorentz- Bray-Clark method was used to calculate the brine viscosity. 4E+7 FGIT The viscosity for each phase is given by: FGIPL_k =100 mD FGIPL_k =200 mD 3E+7 FGIPL_k =500 mD 1/ 4 FGIPL_k =1000 mD 01 i h 2E+7 ªº () PP˜[  0.001 ab ir ¬¼ i 1 1E+7 where μ is the brine viscosity; μ is the fresh water viscosity; 0E+7 a and b are coeffi cients. i r 0 2000 4000 6000 8000 10000 12000 μ and ξ are functions of composition x (CO and brine), i 2 Time, Days the molecular weight of composition x , critical pressure, and critical temperature. Fig. 1 Amount of CO dissolved in the liquid phase in saline aquifers of different k values Many relative permeability curves were proposed h for CO -water-rock systems, the relative permeability 4.1.2 Effect of vertical to horizontal permeability ratio curves of Corey type with exponents determined from Fig. 2 shows the effect of vertical to horizontal laboratory measurements were used. This study considered permeability ratio k /k on the volume of gas dissolved in v h predominantly solubility trapping, so the capillary pressure formation water (the horizontal permeability is 200 mD). curve was not considered. It should be pointed out that the amount of dissolved gas Corey-type model (Brooks and Corey, 1964): increases as the k /k decreases. The difference is signifi cantly v h related to the upward migration as mentioned above. The lower vertical permeability (i.e. low k /k value) prevents CO kS v h 2 rw w from migrating up to the cap rock. This is particularly evident SS  in Fig. 4 where for the lower k /k cases cross fl ow is observed * wwir v h in the horizontal direction in injection intervals. As mentioned 1 S wir above, convection may strongly enhance the dissolution of CO and in fact be the most important mechanism for gas §· §· 2 kS 11S ¨¸ rg w ¨¸ w dissolution. ©¹ ©¹ SS wwir 5E+6 FGIPL_k /k =0.001 V h 1SS wir gr FGIPL_k /k =0.01 V h FGIPL_k /k =0.1 4E+6 V h FGIPL_k /k =1 V h where S is the water saturation; S is the irreducible water w wir 3E+6 saturation; S is the residual gas saturation; exponent values gr used are γ =4 and γ=0.5. 2E+6 4 Sensitivity analysis 1E+6 The properties of reservoir and fluid strongly influence CO distribution underground and control the destiny of 0E+0 CO . In this section we investigated the effects of several 0 2000 4000 6000 8000 10000 12000 parameters on CO distribution and storage effi ciency. Time, Days Fig. 2 Effect of k /k on time development of dissolved gas v h 4.1 Reservoir properties 4.1.1 Effect of horizontal permeability Figs. 3 and 4 show the changes of CO saturation profi le The effect of horizontal permeability k on CO storage with time (1, 5, 15, 30 years) for the cases with different h 2 capacity in a saline aquifer with a constant k /k of 0.1 is vertical to horizontal permeability ratios. The horizontal v h shown in Fig. 1. Simulation results show that more gas permeability is kept constant at 200 mD. FGIPL, Mscf FGIT or FGIPL, Mscf Pet.Sci.(2010)7:372-378 375 Injection well 1 year Injection well 1 year Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24993 0.49986 0.74979 0.99972 0.00000 0.24888 0.49776 0.74664 0.99552 Injection well 5 years Production well Injection well 5 years Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24993 0.49986 0.74979 0.99972 0.00000 0.24888 0.49776 0.74664 0.99552 Injection well 15 years Injection well 15 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24993 0.49986 0.74979 0.99972 0.00000 0.24888 0.49776 0.74664 0.99552 Injection well 30 years Injection well 30 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24993 0.49986 0.74979 0.99972 0.00000 0.24888 0.49776 0.74664 0.99552 (b) k /k = 0.1 (a) k /k = 1 v h v h Fig. 3 Cross-section of the distribution of free CO plume for k /k = 1 and 0.1, respectively 2 v h Simulation results show that the vertical to horizontal trapped as residual gas as the critical gas saturation increases, permeability ratio has a strong effect on CO flow which reduces dissolution of CO in the aquifer brine. 2 2 distribution. Figs. 3 and 4 show that at very low k /k values, 4.2.2 Effect of irreducible water saturation v h CO tends to migrate laterally in injection intervals, which Many studies show that the irreducible water saturation would increase the dissolution of CO . Whereas an increase in S infl uences the dissolution of CO in the aquifer brine (Mo 2 wir 2 the permeability ratio enhances the vertical migration and CO and Akervoll, 2005). As well known, the irreducible water spreads out laterally underneath the cap rock. saturation reduces the pore volume. Typical results (Fig. 6) show that an increase in the irreducible water saturation is 4.2 Phase properties of CO -brine 2 benefi cial in terms of dissolution trapping of more CO , we can also see from Fig. 7 that CO tends to migrate upward 4.2.1 Effect of critical gas saturation with increasing irreducible water saturation. In all cases, the critical gas saturation is kept at 0.1. In the simulation we do not consider the hysteresis effect, but some gas may become trapped. This is achieved by 4.3 Fluid properties setting the critical gas saturation S > 0. In these cases only gc The properties of brine differ signifi cantly from pure water the critical gas saturation value is changed and the irreducible due to its high salinity. The salt content strongly influences water saturation is kept at 0.3. Fig. 5 shows the volume of the solubility of CO , as mentioned above. The salinity (S) is dissolved gas (FGIPL) for the cases of different critical gas not treated as a third component but as a parameter that can saturations. The dissolution of gas increases as the critical vary in EOS. gas saturation decreases. This is due to the fact that during The density and viscosity of the aqueous phase are the injection period CO mostly migrates as a gas phase, functions of pressure, temperature, salinity of the aqueous which increases the contact between CO and brine and thus phase, and concentration of CO in the aqueous phase. enhances the dissolution of CO . The effect of increasing The concentration of CO is also a function of pressure, critical gas saturation is that the gas can be more effectively 376 Pet.Sci.(2010)7:372-378 Injection well 1 year Injection well 1 year Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24940 0.49880 0.74820 0.99761 0.00000 0.24935 0.49870 0.74805 0.99740 Injection well 5 years Injection well 5 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24935 0.49870 0.74805 0.99740 0.00000 0.24940 0.49880 0.74820 0.99761 Injection well 15 years Injection well 15 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24935 0.49870 0.74805 0.99740 0.00000 0.24940 0.49880 0.74820 0.99761 Injection well 30 years Injection well 30 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24935 0.49870 0.74805 0.99740 0.00000 0.24940 0.49880 0.74820 0.99761 (a) k /k =0.01 (b) k /k = 0.001 v h v h Cross-section of the distribution of free CO plume for k /k = 0.01 and 0.001, respectively Fig. 4 2 v h 3E+6 brines with different NaCl concentrations. The amount of free gas in fresh water is less than that in 4 mol/kg NaCl solution. This is due to smaller buoyancy force acting on the CO FGIPL_S =0.1 gc FGIPL_S =0.2 gc 2E+6 bubbles in fresh water, which results in a higher dissolution FGIPL_S =0.3 gc rate in fresh water aquifer. 1E+6 3E+6 FGIPL_S =0.3 wir FGIPL_S =0.1 0E+0 wir 0 2000 4000 6000 8000 10000 12000 2E+6 Time, Days Fig. 5 Effect of critical gas saturation on CO dissolution with time 1E+6 temperature, and salinity of the aqueous phase. The solubility of CO decreases as the salinity increases, and the effi ciency of solubility trapping decreases. Fig. 8 shows the 0E+0 concentration of CO in the aqueous phase varying with time. 0 2000 4000 6000 8000 10000 12000 We can clearly see that the volume of CO dissolved in the Time, Days aquifer brine is less than that in the fresh water. Fig. 9 depicts Fig. 6 Effect of irreducible water saturation on CO dissolution in brine the CO plume migration for 1, 15 and 30 years in formation FGIPL, Mscf PGIPL, Mscf Pet.Sci.(2010)7:372-378 377 Injection well 1 year Production well Injection well 1 year Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.21207 0.42413 0.63620 0.84827 0.00000 0.24929 0.49858 0.74787 0.99717 Injection well 15 years Injection well 15 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.21207 0.42413 0.63620 0.84827 0.00000 0.24929 0.49858 0.74787 0.99717 Injection well 30 years Injection well 30 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24929 0.49858 0.74787 0.99717 0.00000 0.21207 0.42413 0.63620 0.84827 (a) S =0.1 (b) S = 0.3 wir wir Cross-section of the distribution of free CO plume for diffevent times (1, 15, 30 years) Fig. 7 and for two cases of irreducible wafer saturations 6E+7 laterally in the injection intervals, thus increasing the dissolution of CO ; whereas an increase in the permeability 5E+7 ratio enhances the vertical migration and the gas-phase CO FGIT 4E+7 spreads out quickly underneath the cap rock laterally. FGIPL_Fresh water FGIPL_2 mol/kg NaCl 3) Residual phase saturations. The amount of dissolved 3E+7 FGIPL_4 mol/kg NaCl gas in the brine increases as the critical gas saturation decrease. This is due to that fact during the injection period 2E+7 CO mostly migrates as a gas phase, which increases the 1E+7 contact between CO and brine, and thus enhances the dissolution of CO . 0E+0 0 2000 4000 6000 8000 10000 12000 Meanwhile, hysteresis and mineral trapping are important, and should be investigated further. In the model we proposed, Time, Days we assume that the aquifers are isotropic and homogenous, Fig. 8 Effect of salinity on the concentration of CO in the aqueous phase so it is important for CO geological storage to consider the effect of temperature and heterogeneity. 5 Conclusions Acknowledgments The dissolution of CO in aquifer water is the dominant mechanism of CO storage in saline aquifers. During the The authors are grateful for financial support from the injection phase the most CO migrates in the gas phase and National Basic Research Program of China (973 Project, only about 5%-10% CO dissolves in the brine. After the 2006CB705801) and the Program for New Century Excellent termination of injection, CO continues to dissolve mainly Talents in University (2007). due to the contact of gas with brine. Moreover, the effi ciency of dissolution depends on many factors, we can draw from References this study that the solubility trapping is strongly dependent on Bac hu S, Gunter W D and Perkins E H. Aquifer disposal of CO : the following factors: Hydrodynamic and mineral trapping. Energy Conversion and 1) The brine salinity. The dissolution of CO decreases as Management.1994. 35(4): 269-279 the salinity increases, and thus the effectiveness of solubility Bro oks A N and Corey A T. Hydraulic Properties of Porous Media. In: trapping decreases. Hydrology Papers No. 3. 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Schlumberger, USA FGIT or FGIPL, Mscf 378 378 Pet.Sci.(2010)7:372-378 Injection well 1 year Injection well 1 year Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24936 0.49872 0.74808 0.99744 0.00000 0.24919 0.49837 0.74756 0.99675 Injection well 15 years Injection well 15 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24936 0.49872 0.74808 0.99744 0.00000 0.24919 0.49837 0.74756 0.99675 Injection well 30 years Injection well 30 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24936 0.49872 0.74808 0.99744 0.00000 0.24919 0.49837 0.74756 0.99675 (a) Fresh water (b) Aquifer brine (4 mol/kg NaCl) Fig. 9 Cross-section of the distribution of free CO plume in fresh water and aquifer brine at different times Enn is-King J and Paterson L. Role of convective mixing in the long- Kor bol R and Kaddour A. 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Sensitivity analysis of CO2 sequestration in saline aquifers

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Springer Journals
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Copyright © 2010 by China University of Petroleum (Beijing) and Springer-Verlag Berlin Heidelberg
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Earth Sciences; Mineral Resources; Industrial Chemistry/Chemical Engineering; Industrial and Production Engineering; Energy Economics
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Abstract

372 372 Pet.Sci.(2010)7:372-378 DOI 10.1007/s12182-010-0080-2 Sensitivity analysis of CO sequestration in saline aquifers Zhao Hongjun, Liao Xinwei , Chen Yanfang and Zhao Xiaoliang Key Laboratory of Petroleum Engineering, Ministry of Education, China University of Petroleum, Beijing 102249, China © China University of Petroleum (Beijing) and Springer-Verlag Berlin Heidelberg 2010 Abstract: Carbon capture and storage (CCS) technology has been considered as an important method for reducing greenhouse gas emissions and for mitigating global climate change. Three primary options are being considered for large-scale storage of CO in subsurface formations: oil and gas reservoirs, deep saline aquifers, and coal beds. There are very many large saline aquifers around the world, which could make a big contribution to mitigating global warming. However, we have much less understanding of saline aquifers than oil and gas reservoirs. Several mechanisms are involved in the storage of CO in deep saline aquifers, but the ultimate goal of injection of CO into the aquifers containing salt water is to dissolve the CO in the water. So it is important to study the solubility trapping and sensitivity factors of CO in saline aquifers. This paper presents results of modeling CO storage in a saline aquifer using 2 2 the commercial reservoir simulator ECLIPSE. The objective of this study was to better understand the CO /brine phase behavior (PVT properties) and quantitatively estimate the most important CO 2 2 storage mechanism in brine-solubility trapping. This would provide a tool by performing theoretical and numerical studies that help to understand the feasibility of CO geological storage. A 3-dimensional, 2-phase (water/gas) conceptional reservoir model used finite, homogenous and isothermal formations into which CO is injected at a constant rate. The effects of main parameters were studied, including the vertical to horizontal permeability ratio k /k , salinity, and residual phase saturations. The results show that v h the vertical to horizontal permeability ratio has a signifi cant effect on CO storage. Moreover, more CO 2 2 dissolves in the brine at lower k /k values. v h Key words: CO geologic sequestration, saline aquifer, solubility trapping, numerical simulation 2, Geological storage of anthropogenic CO as a greenhouse 1 Introduction gas mitigation option was first proposed in the 1970s, but The concentration of CO in the atmosphere has gradually 2 little research was done until the early 1990s, when the increased in the last 250 years due to human activities, leading idea gained credibility through the work of individuals and to measurable global warming. The Intergovernmental Panel research groups (Marchetti, 1977; Kaarstad, 1992; Koide et on Climate Change (IPCC) has projected that for a ‘business al, 1993; van der Meer, 1992; Gunter, 1993; Holloway and as usual’ energy scenario the atmospheric concentration of Savage, 1993; Bachu et al, 1994; Korbol and Kaddour, 1995). CO may double by the middle of the 21st century, and may 2 In 1996, the world’s first large-scale storage project was continue to rise at increasing rates beyond (Houghton, 1996). initiated by Statoil and its partners at the Sleipner Gas Field Climate modeling shows that a rise of 0.3-0.6 °C in the near- in the North Sea (IPCC, 2005). earth-surface temperature could result from the increased Three main alternatives have been considered for large- concentration of CO in the atmosphere during the last 150 2 scale storage of CO in subsurface formations (Orr et al, years (Ledley et al, 1999). Experts agree that a number of 2003): depleted oil and gas reservoirs, deep saline aquifers, actions should be taken soon in order to reduce the amount of and coal beds. Among these, saline aquifers can effectively CO entering the atmosphere. One of the important means is 2 contribute to CO sequestration because of their large to capture millions of tonnes of CO produced by industrial 2 capacity and broad distribution around the world. However, processes and sequester CO deep underground − this is 2 we know very little about saline aquifers when compared to known as CO capture and geological storage (CCS) (IEA, 2 our understanding of oil and gas reservoirs. In this study we 2007). use the ECLIPSE simulator to investigate the fl ow of CO in brine by considering the solubility effect and the sensitivity analysis of various parameters. It is very important to predict leakage risk and for the implementation of fi eld projects. *Corresponding author. email: xinwei@cup.edu.cn Received May 11, 2009 Pet.Sci.(2010)7:372-378 373 373 and 50 ºC, respectively. Table 1 summarizes the base case 2 Mechanisms of CO sequestration in saline input parameters including aquifer parameters and injection aquifers conditions. Pure CO is injected at a constant rate for 15 years. Our simulation domain is in one quarter of a fi ve spot pattern, Four principal mechanisms for sequestering CO in saline in which four production wells are located at the corners of a aquifers have been described in the literature. square and the injection well sits in the center. The distance Hydrodynamic trapping In a storage project, supercritical between the injection and production wells is 3,400 m. The CO will be injected as a single phase, but once in the production well is controlled by bottom hole pressure (BHP). geological formation it will partition into free-phase The main substances to be taken into account when (immiscible) CO and a CO -rich brine. The flow of the 2 2 describing flow and transport during CO sequestration free-phase CO is dependent on the dip of the sealing horizon 2 are CO , formation water, and salinity (salt), of course, the and the flow velocity and direction of the in situ formation 2 rock matrix that forms the porous medium. Water and CO water. Saline aquifers generally have very low fl ow velocities, 2 are defined as two components. Salts are not considered of the order of tens of cm/year. This slow fl ow velocity leads as an independent component, but considered a corrected to residence times of millions of years. This geological time- coeffi cient in the equation of state (EOS). Therefore, a two- scale trapping of CO in deep regional aquifers is called phase two-component model was chosen (which refers to the hydrodynamic trapping (Finley et al, 2005). In the short water-rich phase as a liquid and the CO -rich phase as a gas) term, this is likely to be the most important mechanism for 2 for the following study. sequestration (Pruess, 2004). Solubility trapping When CO is injected into a reservoir, Table 1 Summary of the aquifer properties and injection conditions a portion of the injected CO will dissolve in the formation water in the aquifer and the dissolution of CO per unit volume of water is a function of pressure, temperature, and Reservoir size (m×m×m) 2500×2500×50 salinity of the aqueous phase (Holtz, 2002). The aqueous (length, width and thickness) phase will retain the dissolved CO regardless of being x 100 stationary or transported to another location as long as the Permeability y 100 physical conditions are undisturbed. CO -saturated formation mD water is denser than water not containing CO . The difference z 10 in density of CO -saturated aquifer water and virgin formation Porosity, % 0.18 water triggers convection currents in the aquifer beneath the CO plume, and accelerate the efficiency of dissolution 2 Top depth, m 1000 (Ennis-King and Paterson, 2005). Number of grids 50×50×5 Residual trapping Most of the CO injected into a saline -1 -6 Rock compressibility, psi 0.55×10 aquifer migrates upward as a separate CO -rich phase. During this upward migration two different displacement processes Temperature, ºC 50 are active; namely, gravity drainage and imbibition. At the tail Residual water saturation 0.3 of the migrating CO plume, formation water invades the CO 2 2 plume. Due to relative permeability and capillary hysteresis a Residual CO saturation 0.1 fraction of the non-wetting phase is trapped in the imbibition Salinity, mol/kg 0-4 process. When the concentration of CO falls below a certain level CO becomes trapped by capillary pressures and ceases CO injection rate, Mscf/day 10000 to flow. This process is commonly referred to as residual Boundary condition No-fl ow trapping (Felett et al, 2004; Kumar et al, 2005). Injection time, Years 15 Mineral trapping CO can react with minerals and organic matter in geological formations to form precipitates Simulation time, Years 30 (Pruess et al, 2003). This trapping will create stable Injection interval Block (1, 1, 5) repositories of CO that decreases mobile hazards such as leakage to the surface (Nghiem et al, 2004). Initial pressure, psi 1500 Initial Water saturation S 1.0 3 Simulation model descriptions conditions co X 0 3.1 Model conditions 3. 2 Phase properties of CO -brine systems The purpose of this study was to illustrate the processes CO has a high solubility in the aqueous phase in saline occurring during CO injection and investigate the effects of aquifers due to high pressures. The dissolution of CO in reservoir parameters. The simulations assume an isotropic and formation water occurs through mass transfer from the homogenous aquifer with a horizontal permeability of 100 CO phase to the aqueous phase whenever the phases are in mD, porosity of 0.18, and 50 m of thickness. The impermeable contact. The excess CO phase and the aqueous phase are top layer of the aquifer is located at a depth of 1,000 m thereby assumed to be in thermodynamic equilibrium in the with a corresponding pressure and temperature of 1,500 psi 374 Pet.Sci.(2010)7:372-378 model. The Peng-Robinson equations of state were modifi ed dissolves in the formation brine as the horizontal permeability following the suggestions of Søreide and Whitson (1992) to increases, but the effect of horizontal permeability is very obtain accurate gas solubility in the aqueous phase (Eclipse small. During the injection period CO migrates mostly as a Technical Manual, 2005). gas phase and only about 5%-10% of the CO dissolves in Both gas and water density values were obtained from brine. The total injection gas (Field Gas in Place Total, FGIT) the equation of state. Brine density, which is a function of and the gas dissolved in liquid (Field gas in place liquid, temperature and pressure as well as the contributions of FGIPL) for different horizontal permeability reservoirs are salinity and dissolved CO , was described as the sum of pure shown in Fig. 1. water density and additional density caused by salinity and 6E+7 dissolved CO . Brine viscosity is a strong function of temperature. It also 5E+7 depends on salinity, pressure, and dissolved CO , the Lorentz- Bray-Clark method was used to calculate the brine viscosity. 4E+7 FGIT The viscosity for each phase is given by: FGIPL_k =100 mD FGIPL_k =200 mD 3E+7 FGIPL_k =500 mD 1/ 4 FGIPL_k =1000 mD 01 i h 2E+7 ªº () PP˜[  0.001 ab ir ¬¼ i 1 1E+7 where μ is the brine viscosity; μ is the fresh water viscosity; 0E+7 a and b are coeffi cients. i r 0 2000 4000 6000 8000 10000 12000 μ and ξ are functions of composition x (CO and brine), i 2 Time, Days the molecular weight of composition x , critical pressure, and critical temperature. Fig. 1 Amount of CO dissolved in the liquid phase in saline aquifers of different k values Many relative permeability curves were proposed h for CO -water-rock systems, the relative permeability 4.1.2 Effect of vertical to horizontal permeability ratio curves of Corey type with exponents determined from Fig. 2 shows the effect of vertical to horizontal laboratory measurements were used. This study considered permeability ratio k /k on the volume of gas dissolved in v h predominantly solubility trapping, so the capillary pressure formation water (the horizontal permeability is 200 mD). curve was not considered. It should be pointed out that the amount of dissolved gas Corey-type model (Brooks and Corey, 1964): increases as the k /k decreases. The difference is signifi cantly v h related to the upward migration as mentioned above. The lower vertical permeability (i.e. low k /k value) prevents CO kS v h 2 rw w from migrating up to the cap rock. This is particularly evident SS  in Fig. 4 where for the lower k /k cases cross fl ow is observed * wwir v h in the horizontal direction in injection intervals. As mentioned 1 S wir above, convection may strongly enhance the dissolution of CO and in fact be the most important mechanism for gas §· §· 2 kS 11S ¨¸ rg w ¨¸ w dissolution. ©¹ ©¹ SS wwir 5E+6 FGIPL_k /k =0.001 V h 1SS wir gr FGIPL_k /k =0.01 V h FGIPL_k /k =0.1 4E+6 V h FGIPL_k /k =1 V h where S is the water saturation; S is the irreducible water w wir 3E+6 saturation; S is the residual gas saturation; exponent values gr used are γ =4 and γ=0.5. 2E+6 4 Sensitivity analysis 1E+6 The properties of reservoir and fluid strongly influence CO distribution underground and control the destiny of 0E+0 CO . In this section we investigated the effects of several 0 2000 4000 6000 8000 10000 12000 parameters on CO distribution and storage effi ciency. Time, Days Fig. 2 Effect of k /k on time development of dissolved gas v h 4.1 Reservoir properties 4.1.1 Effect of horizontal permeability Figs. 3 and 4 show the changes of CO saturation profi le The effect of horizontal permeability k on CO storage with time (1, 5, 15, 30 years) for the cases with different h 2 capacity in a saline aquifer with a constant k /k of 0.1 is vertical to horizontal permeability ratios. The horizontal v h shown in Fig. 1. Simulation results show that more gas permeability is kept constant at 200 mD. FGIPL, Mscf FGIT or FGIPL, Mscf Pet.Sci.(2010)7:372-378 375 Injection well 1 year Injection well 1 year Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24993 0.49986 0.74979 0.99972 0.00000 0.24888 0.49776 0.74664 0.99552 Injection well 5 years Production well Injection well 5 years Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24993 0.49986 0.74979 0.99972 0.00000 0.24888 0.49776 0.74664 0.99552 Injection well 15 years Injection well 15 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24993 0.49986 0.74979 0.99972 0.00000 0.24888 0.49776 0.74664 0.99552 Injection well 30 years Injection well 30 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24993 0.49986 0.74979 0.99972 0.00000 0.24888 0.49776 0.74664 0.99552 (b) k /k = 0.1 (a) k /k = 1 v h v h Fig. 3 Cross-section of the distribution of free CO plume for k /k = 1 and 0.1, respectively 2 v h Simulation results show that the vertical to horizontal trapped as residual gas as the critical gas saturation increases, permeability ratio has a strong effect on CO flow which reduces dissolution of CO in the aquifer brine. 2 2 distribution. Figs. 3 and 4 show that at very low k /k values, 4.2.2 Effect of irreducible water saturation v h CO tends to migrate laterally in injection intervals, which Many studies show that the irreducible water saturation would increase the dissolution of CO . Whereas an increase in S infl uences the dissolution of CO in the aquifer brine (Mo 2 wir 2 the permeability ratio enhances the vertical migration and CO and Akervoll, 2005). As well known, the irreducible water spreads out laterally underneath the cap rock. saturation reduces the pore volume. Typical results (Fig. 6) show that an increase in the irreducible water saturation is 4.2 Phase properties of CO -brine 2 benefi cial in terms of dissolution trapping of more CO , we can also see from Fig. 7 that CO tends to migrate upward 4.2.1 Effect of critical gas saturation with increasing irreducible water saturation. In all cases, the critical gas saturation is kept at 0.1. In the simulation we do not consider the hysteresis effect, but some gas may become trapped. This is achieved by 4.3 Fluid properties setting the critical gas saturation S > 0. In these cases only gc The properties of brine differ signifi cantly from pure water the critical gas saturation value is changed and the irreducible due to its high salinity. The salt content strongly influences water saturation is kept at 0.3. Fig. 5 shows the volume of the solubility of CO , as mentioned above. The salinity (S) is dissolved gas (FGIPL) for the cases of different critical gas not treated as a third component but as a parameter that can saturations. The dissolution of gas increases as the critical vary in EOS. gas saturation decreases. This is due to the fact that during The density and viscosity of the aqueous phase are the injection period CO mostly migrates as a gas phase, functions of pressure, temperature, salinity of the aqueous which increases the contact between CO and brine and thus phase, and concentration of CO in the aqueous phase. enhances the dissolution of CO . The effect of increasing The concentration of CO is also a function of pressure, critical gas saturation is that the gas can be more effectively 376 Pet.Sci.(2010)7:372-378 Injection well 1 year Injection well 1 year Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24940 0.49880 0.74820 0.99761 0.00000 0.24935 0.49870 0.74805 0.99740 Injection well 5 years Injection well 5 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24935 0.49870 0.74805 0.99740 0.00000 0.24940 0.49880 0.74820 0.99761 Injection well 15 years Injection well 15 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24935 0.49870 0.74805 0.99740 0.00000 0.24940 0.49880 0.74820 0.99761 Injection well 30 years Injection well 30 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24935 0.49870 0.74805 0.99740 0.00000 0.24940 0.49880 0.74820 0.99761 (a) k /k =0.01 (b) k /k = 0.001 v h v h Cross-section of the distribution of free CO plume for k /k = 0.01 and 0.001, respectively Fig. 4 2 v h 3E+6 brines with different NaCl concentrations. The amount of free gas in fresh water is less than that in 4 mol/kg NaCl solution. This is due to smaller buoyancy force acting on the CO FGIPL_S =0.1 gc FGIPL_S =0.2 gc 2E+6 bubbles in fresh water, which results in a higher dissolution FGIPL_S =0.3 gc rate in fresh water aquifer. 1E+6 3E+6 FGIPL_S =0.3 wir FGIPL_S =0.1 0E+0 wir 0 2000 4000 6000 8000 10000 12000 2E+6 Time, Days Fig. 5 Effect of critical gas saturation on CO dissolution with time 1E+6 temperature, and salinity of the aqueous phase. The solubility of CO decreases as the salinity increases, and the effi ciency of solubility trapping decreases. Fig. 8 shows the 0E+0 concentration of CO in the aqueous phase varying with time. 0 2000 4000 6000 8000 10000 12000 We can clearly see that the volume of CO dissolved in the Time, Days aquifer brine is less than that in the fresh water. Fig. 9 depicts Fig. 6 Effect of irreducible water saturation on CO dissolution in brine the CO plume migration for 1, 15 and 30 years in formation FGIPL, Mscf PGIPL, Mscf Pet.Sci.(2010)7:372-378 377 Injection well 1 year Production well Injection well 1 year Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.21207 0.42413 0.63620 0.84827 0.00000 0.24929 0.49858 0.74787 0.99717 Injection well 15 years Injection well 15 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.21207 0.42413 0.63620 0.84827 0.00000 0.24929 0.49858 0.74787 0.99717 Injection well 30 years Injection well 30 years Production well Production well y-axis y-axis z-axis z-axis Gas saturation Gas saturation 0.00000 0.24929 0.49858 0.74787 0.99717 0.00000 0.21207 0.42413 0.63620 0.84827 (a) S =0.1 (b) S = 0.3 wir wir Cross-section of the distribution of free CO plume for diffevent times (1, 15, 30 years) Fig. 7 and for two cases of irreducible wafer saturations 6E+7 laterally in the injection intervals, thus increasing the dissolution of CO ; whereas an increase in the permeability 5E+7 ratio enhances the vertical migration and the gas-phase CO FGIT 4E+7 spreads out quickly underneath the cap rock laterally. FGIPL_Fresh water FGIPL_2 mol/kg NaCl 3) Residual phase saturations. The amount of dissolved 3E+7 FGIPL_4 mol/kg NaCl gas in the brine increases as the critical gas saturation decrease. This is due to that fact during the injection period 2E+7 CO mostly migrates as a gas phase, which increases the 1E+7 contact between CO and brine, and thus enhances the dissolution of CO . 0E+0 0 2000 4000 6000 8000 10000 12000 Meanwhile, hysteresis and mineral trapping are important, and should be investigated further. In the model we proposed, Time, Days we assume that the aquifers are isotropic and homogenous, Fig. 8 Effect of salinity on the concentration of CO in the aqueous phase so it is important for CO geological storage to consider the effect of temperature and heterogeneity. 5 Conclusions Acknowledgments The dissolution of CO in aquifer water is the dominant mechanism of CO storage in saline aquifers. During the The authors are grateful for financial support from the injection phase the most CO migrates in the gas phase and National Basic Research Program of China (973 Project, only about 5%-10% CO dissolves in the brine. After the 2006CB705801) and the Program for New Century Excellent termination of injection, CO continues to dissolve mainly Talents in University (2007). due to the contact of gas with brine. Moreover, the effi ciency of dissolution depends on many factors, we can draw from References this study that the solubility trapping is strongly dependent on Bac hu S, Gunter W D and Perkins E H. Aquifer disposal of CO : the following factors: Hydrodynamic and mineral trapping. Energy Conversion and 1) The brine salinity. The dissolution of CO decreases as Management.1994. 35(4): 269-279 the salinity increases, and thus the effectiveness of solubility Bro oks A N and Corey A T. Hydraulic Properties of Porous Media. In: trapping decreases. Hydrology Papers No. 3. 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