Energy Fuels 2010, 24, 3292–3298 Published on Web 05/04/2010
: DOI:10.1021/ef100073m
Analysis of the Leakage Possibility of Injected CO2 in a Saline Aquifer Youngsoo Lee,† Kihong Kim,† Wonmo Sung,† and Inhang Yoo*,‡ †
Department of Natural Resources and Environmental Engineering, Hanyang University, Seoul 133-791, Korea, and ‡ Research and Development Division, GeoScan, Anyang 430-011, Korea Received January 21, 2010. Revised Manuscript Received April 20, 2010
This paper presents the numerical modeling study to investigate the leakage possibility of CO2 in a deep saline aquifer where caprock is discontinuous or does not exist. As a result of simulations for 30 years of injection and 5000 years of monitoring, injected CO2 rises by buoyancy. However, it does not reach the surface, and the height of CO2 moving upward is not high from the effect of residual and solubility trap mechanisms. Meanwhile, when the vertical permeability is higher than the actual, CO2 moves highly upward and the phase of CO2 changes into a gas phase. However, it is shown that CO2 does not affect the surface during the monitoring period. When CO2 is injected into a deeper aquifer, it is more effective and stable for CO2 sequestration. Finally, CO2 may leak faster when there are flow networks composed of faults and porous mediums. For this reason, we should pay attention to the formation lies on the target aquifer to prevent the possible leakage of injected CO2.
they are capable of storing huge amounts of CO2, ranging from 400 gigatons to a maximum of 10 000 gigatons.8 Most research groups have focused on storage of CO2 in aquifers with an impermeable caprock, such as shale, to prevent vertical leakage and a thick sand body to safely store large amounts of CO2. In this system, the integrity of the caprock is very important. Also, the aquifer must have sufficient permeability and porosity to enable a suitable flow rate and sufficient volume of injected CO2. Although those structures can stably store CO2, not only is it difficult to find such seal and trapping structures, but also the potential capacity for CO2 storage in those formations is not large.1 Takahashi et al.15 presented that the storage potential of nontrap structures is 146 gigatons in Japan. They announced that a deep saline aquifer that does not have a caprock can be a possible alternative because CO2 can be trapped residually and can be soluble in formation water. The geologic system is usually characterized by seismic survey and well logging. However, it is hard to exactly define an underground structure because of the lack of geological information, errors of measurement tools, and misinterpretation of measured data. Besides, well logging does not give us whole information of an aquifer but around a few meters from the well. For these reasons, we can easily misunderstand the underground structure and sometimes may determine CO2 injection where a caprock does not exist. This leads to leakage of CO2 to the surface direction and even raises the shear failure of the formation. Also, when drilling a well, although a lot of efforts are made, fractures in the caprock may be generated along the well path.6
Introduction Because of the effect of the industrial revolution, the concentration of CO2 in the atmosphere has risen substantially from the pre-industrial-age level of approximately 280 to 388 ppm today.7,16 To mitigate emissions, large-scale storage of anthropogenic CO2 underground should be considered. CO2 sequestration is possible in depleted oil and gas fields, deep saline aquifers, and coal seams.9 Because these geologic structures have isolated hydrocarbon or water without leakage for a long time, it is possible to inject and store great amounts of CO2. Among these geologic options, the preferred location is deep saline aquifers, because they are widely distributed and the cost of transportation can be reduced by the accessibility between the CO2 emission source and storage sites. In addition, *To whom correspondence should be addressed. Telephone: 82-31596-6326. E-mail:
[email protected]. (1) Akaku, K. Numerical simulation of CO2 storage in aquifers without trapping structures. Proceedings of the International Petroleum Technology Conference of the Society of Petroleum Engineers (SPE), Kuala Lumpur, Malaysia, Dec 3-5, 2008; IPTC 12304. (2) Basbug, B.; Gumrah, F.; Oz, B. J. Can. Pet. Technol. 2007, 46, 30–38. (3) Bennion, B.; Bachu, S. Relative permeability characteristics for supercritical CO2 displacing water in a variety of potential sequestration zones in the western Canada sedimentary basin. Proceedings of the Annual Technical Conference and Exhibition of the Society of Petroleum Engineers (SPE), Dallas, TX, 2005; SPE 95547. (4) Bennion, B.; Bachu, S. SPE Reservoir Eval. Eng. 2008, 11, 487– 496. (5) Chang, K. W.; Minkoff, S. E.; Bryant, S. L. Modeling leakage through faults of CO2 stored in an aquifer. Proceedings of the Annual Technical Conference and Exhibition of the Society of Petroleum Engineers (SPE), Denver, CO, 2008; SPE 115929. (6) Cooper, J. Well bore integrity... Say what?? Proceedings of the 9th International Conference on Greenhouse Gas Control Technologies, Washington, D.C., Nov 16-20, 2008; pp 3617-3624. (7) Franklin, M. J. Pet. Technol. 2004, 56, 90–97. (8) International Energy Agency (IEA). Prospects for CO2 Capture and Storage; Organisation for Economic Co-operation and Development (OECD)/IEA: Paris, France, 2004. (9) Intergovernmental Panel on Climate Change (IPCC). IPCC Special Report on Carbon Dioxide Capture and Storage; Cambridge University Press: New York, 2005. r 2010 American Chemical Society
(10) Kumar, A.; Noh, M.; Pope, G. A.; Sepehrnoori, K.; Bryant, S.; Lake, L. W. Reservoir simulation of CO2 storage in deep saline aquifers. Proceedings of the 14th Society of Petroleum Engineers (SPE)/Department of Energy (DOE) Symposium on Improved Oil Recovery, Tulsa, OK, 2004; SPE 89343. (11) Lee, Y. S.; Park, Y. C.; Kwon, S. I.; Sung, W. J. Korean Soc. Geosyst. Eng. 2008, 45, 381–393. (12) Lee, Y. S.; Kim, K. H.; Lee, T. H.; Sung, W.; Park, Y. C.; Lee, J. H. Energy Sources 2010, 32, 83–99.
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Energy Fuels 2010, 24, 3292–3298
: DOI:10.1021/ef100073m
Lee et al.
Figure 1. Schematic diagram of the 2D cross-section system.
Figure 2. Relative permeability curves for the CO2-water system in the drainage process.
Thus, a feasibility study must be executed prior to the CO2 injection, because CO2 might cause a contamination of groundwater in the upper formation. Pasala et al.13 analyzed the effect of faults in sandstone, where CO2 geologic sequestration or enhanced oil recovery (EOR) is applied. They showed how fault conduits and barriers can restrict or enhance migration of CO2 through the aquifer as a consequence of bypassing or compartmentalization. Chang et al.5 stated that faults and the damaged zones may provide conduits for CO2 to escape through a caprock. They developed a qussi-1D single-phase flow model to examine CO2 flowing behaviors, which are upward migration from the storage aquifer along the fault, lateral movement from the fault into permeable layers, and a continued but attenuated CO2 flux. Akaku1 examined the flow of the injected CO2 in the dipping heterogeneous strata,
Table 1. Input Data for the Leakage Simulation aquifer properties length (m) width (m) thickness target aquifer (m) upper formation (m) depth at the top layer (m) temperature (°C) initial pressure (MPa) salinity (ppm) vertical/horizontal permeability ratio horizontal (vertical) permeability target aquifer (md) upper formation (md) porosity irreducible water saturation residual gas saturation maximum injection pressure (MPa) maximum allowable injection rate (m3/day)
(13) Pasala, S. M.; Forster, C. B.; Lim, S. J.; Deo, M. D. Simulating the impact of faults on CO2 sequestration and enhanced oil recovery in sandstone aquifers. Proceedings of the Annual Technical Conference and Exhibition of the Society of Petroleum Engineers (SPE), Denver, CO, 2003; SPE 84186.
value 10100 100 100 1000 1000 58 10 0 0.01 50 (0.5) 5 (0.05) 0.2 0.2 0.2 17 50000
which consists of mudstone and sandstone without trapping structures. He announced that the trapping of CO2 by a 3293
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: DOI:10.1021/ef100073m
Lee et al.
Figure 3. Distribution of CO2 saturation with time.
Figure 5. Mass of sequestrated CO2 with time.
goes by and, accordingly, the groundwater in which its density is increased sinks to a lower part of the structure. In this research, we presented the possibility of CO2 leakage in a deep saline aquifer where a caprock does not exist or is regionally discontinuous, with an assumption that the upper formation is not impermeable. In addition, we executed a simulation study to examine the effect of the residual and solubility trap when CO2 vertically migrates up and how they prevent
Figure 4. CO2 density as a function of the pressure and temperature.
residual trap and solubility trap reduces the upward migration and, therefore, the long-term CO2 geological storage without a caprock is technically feasible. Lee et al.11 performed a feasibility study to sequestrate CO2 for the aquifer that is located in the east South Sea. They concluded that the volume of dissolved CO2 in the formation water is becoming higher as time 3294
Energy Fuels 2010, 24, 3292–3298
: DOI:10.1021/ef100073m
Lee et al.
Figure 6. Distribution of CO2 saturation with time for kv/kh = 0.1.
CO2 leakage to the surface. In this study, we did not include geochemical reactions because of its strong dependency upon mineralogy of rock materials and uncertainty for long periods of time. This study is very important because the deep saline aquifers that do not have any seal or trapping structures are distributed world wide and are likely to sequestrate great amounts of CO2.
is about the observation of the leakage behavior because of the phase change of CO2. For this reason, the injection depth is set as 1000 m depth. The initial pressure and temperature of the target aquifer are 10 MPa and 55 °C according to the pressure gradient of 10.5 MPa/km and geothermal gradient of 30 °C/km. The formation water is assumed as pure water, and the porosity of the whole layer is 16%. Generally, groundwater in an aquifer has salinity, but the purpose of this study is the evaluation of the leakage possibility. For this reason, the effect of salinity is assumed negligible. Also, residual gas saturation has a value from 0.05 to 0.5 in a typical aquifer.10 In this study, residual gas saturation is assumed to be 0.2. The horizontal permeability in the target aquifer is 50 md and 5 md for the upper formation, and the vertical permeability is supposed as 0.01 times that of the horizontal permeability by the rule of thumb. Here, the general permeability of the consolidated fresh sandstone is known as 1-100 md, and hence, the permeability of the target aquifer is assumed as 50 md. Meanwhile, because the upper formation consisted of different strata that contain some impermeable layers, its permeability is assumed as 5 md, which is lower than the permeability of the target aquifer. The relative permeability is a very important factor to determine the CO2 and water flow through pores. Many researchers presented relative permeability curves for a wide variety of rocks.3,4,12 A relative permeability curve can only be obtained by experiments using a small size of core samples and can be easily affected by the
Aquifer System A schematic diagram of the aquifer system used in this study and the rock properties are shown in Figure 1 and Table 1, respectively. We assumed that the target aquifer for CO2 storage is located at a 1000 m depth, and the possibility of leakage of the injected CO2 from the aquifer without a caprock was examined. The strata above the target aquifer, which will be referred as the upper formation, is porous and permeable. Because, in general, the underground strata is stratigraphically deposited by a wide variety of rocks, each stratum has different rock properties, such as porosity and permeability. However, the objective of our research is an evaluation of the leakage possibility of the aquifer where a caprock does not exist. Accordingly, it is assumed that the upper formation has uniform porosity and permeability. The thickness of the target aquifer is 100 m, and the thickness of the upper formation is 1000 m. Here, the injecting depth is somewhat lower than the actual. However, one of the main objectives of this study 3295
Energy Fuels 2010, 24, 3292–3298
: DOI:10.1021/ef100073m
Lee et al.
Figure 7. Flow rate of CO2 in the vertical direction for kv/kh = 0.1.
The drainage process occurs simultaneously with an injection of CO2.10,14 In this study, after the injection period, the drainage process ends and the relative permeability follows the imbibition curve as water is introduced to the pore filled with CO2. The system is composed of a total of 11 110 grids, 101 grids in the x axis and 110 grids in the z axis. The size of each grid is 100 m in the x axis and 10 m in the z axis, with the width of 100 m, and the system is a 2D cross-sectional model. The injection well was completed at the center position of the x axis and between the 100th and 109th grids of the z axis. The lateral boundary blocks are assigned a constant pressure boundary condition, which is equal to the initial pressure to assume a very large aquifer volume, and the upper boundary is maintained in surface pressure during simulation. In addition, the injection rate is set up as 50 000 m3/day, which is determined by a preliminary test, and the maximum bottomhole pressure allowed is 17 MPa, to maintain the mechanical stability of the strata. This total injected amount of CO2 is about 25% of the entire target aquifer volume. In this system, the movement of the injected CO2 is monitored for 5000 years after the injection. To analyze the flow behavior between the formation water and CO2 during the sequestration process and to study the leakage possibility, a generalized equation-of-state model (GEM) manufactured by the Computer Modeling Group (CMG) was used.
Figure 8. Mass of sequestrated CO2 with time for kv/kh = 0.1.
pore size, wettability conditions, and capillary effect. Therefore, intensive care is needed during the experiment. The CO2 phase is changed from the supercritical to gas phase by the geological pressure and thermal gradient around the 800 m depth.2 For this reason, different relative permeability curves were applied according to the depth. The relative permeability curve between supercritical CO2 and water is shown in Figure 2a, which was measured by the steady-state flow method in the CO2-water system under the in situ condition of 8.27 MPa and 45 °C.12 For the depth below 800 m, as shown in Figure 2b, the data from the gas-phase CO2 in the water-CO2 system during the drainage process was applied. The reason that we used experimental data is that it is hard to apply an empirical correlation to gas- and supercritical-phase CO2 separately, which exhibits both gas and liquid-like properties in the same rock. In addition, core properties, such as porosity and permeability, are similar in this study. Another important aspect is that the gas saturation in each grid changes as CO2 moves by the buoyancy and a pressure gradient during CO2 sequestration. Therefore, the relative permeability curve shifts because of drainage and imbibition processes.
Results and Discussion The leakage evaluation of CO2 for the aquifer without a caprock was conducted. The formation above the aquifer is porous and permeable without a caprock. First, as shown in (14) Speteri, E. J; Juanes, R.; Blunt, M. J.; Orr, F. M. A new model of trapping and relative permeability hysteresis for all wettability characteristics. Proceedings of the Annual Technical Conference and Exhibition of the Society of Petroleum Engineers (SPE), Dallas, TX, 2008; SPE 96448. (15) Takahashi, T.; Ohsumi, T.; Nakayama, K.; Koide, K.; Miida, H. Energy Procedia 2009, 1, 2631–2638. (16) Current atmospheric CO2 concentration, http://co2unting.com.
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: DOI:10.1021/ef100073m
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Figure 9. CO2 saturation for the aquifer system when the injection interval is 2000-2100 m.
Figure 3, the CO2 saturation distribution shows that CO2 moved up to 960 m after the injection finished. After the injection, CO2 rises up to a depth of 860 m from a total depth of 1100 m at both 1000 and 5000 years, and there is no possibility of leakage in this system. Moreover, we estimated that the remaining CO2 stays in the supercritical state because it hardly moves up to the 800 m depth, where the CO2 phase change occurs under normal pressure and thermal gradient conditions. The estimation was verified by checking the temperature and pressure, as shown in Figure 4, in the depth at 860 m, which are 8.28 MPa and 52.6 °C, respectively, at 5000 years. In this system, the phase of all of CO2 is supercritical. The sequestration volume change for each trap mechanism with time is described in Figure 5. The volume sequestrated by the structural trap started decreasing rapidly from 30 years when the injection was finished, while the volume sequestrated by the residual and solubility trap increased. After 500 years, the injected CO2 is stably sequestrated by the residual and solubility trap and the sequestrated volume was not changed. This result indicates that, even if the upper formation is porous and permeable without a sealing structure, injected CO2 can be stably sequestrated by solubility and residual trap and the leakage into the surface does not occur. If the vertical permeability of the upper formation is high, however, CO2 can be moved upward more easily and the leakage possibility may be high. Therefore, we attempted to examine the leakage for the aforementioned system when vertical permeability is higher than the actual case by increasing the vertical-horizontal permeability ratio of the upper formation as 0.1. Thus, the vertical permeability was set up as 0.5 md. The saturation distribution and flow rate of CO2 are shown in Figures 6 and 7, respectively. Figure 6 shows that CO2 has risen maximally to 410 m from the bottom of the target aquifer, at the depth of 690 m, after 100 years. The CO2 density at this point is 186.5 kg/m3, which means it stays in the gas phase, and the flow rate is 7.12 m3/day, which is higher than that of the supercritical CO2. This is because the velocity is increased as the phase changes. After 1000 years, it was shown that CO2 was moved to the depth of 500 m among the total depth of 1100 m after 1000 years. However, the height of CO2 moving was decreased as even more time passed to 5000 years. This is because CO2 is dissolved in water and sinks to the lower part of the formation. For this reason, the density and flow rate of CO2 are 180 kg/m3 and 0, respectively, as shown in Figure 7. It indicates that, if vertical permeability is higher than the actual,
Figure 10. Mass change of sequestrated CO2 when the injection interval is 2000-2100 m.
there is no possibility of CO2 leakage by the effect of the residual and solubility trap. Also, as shown in Figure 8, the stabilization time, in which the volume changes for each trap mechanism do not occur, is much shorter than the previous case. The reason is that the contact area between CO2 and formation water increases and movable CO2 is diminished quickly. As mentioned above, CO2 can be sequestrated more stably when it stays in the supercritical phase; therefore, it should be in the stable condition when the supercritical phase area is thick. Because this shows that a deep saline aquifer is more effective for CO2 sequestration, we chose 2100 m for the aquifer depth to perform analyzing simulation for stability. As shown in Figure 9, at 1000 years, CO2 stays in the supercritical phase and the height of CO2 rising up is 320 m from the bottom, at a 1780 m depth. It is lower than the results of the former. Moreover, from Figure 10, the sequestrated volume ratio by solubility and residual trap is 52.8 and 46.7%, respectively, after 1000 years. This means that there is only 0.5% movable CO2 in this system. Therefore, we concluded that CO2 is more stably sequestrated by solubility and residual trap when CO2 is injected into a deeper aquifer. As shown above, CO2 does not leak by the effect of the residual and solubility trap. CO2 may move to the surface, however, where there are faults or fractures connected with the porous medium. These faults and fractures act like a conduit to transport CO2. Thus, on the basis of the schematic of Chang et al.,5 we made simple flow networks consisting of 3297
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: DOI:10.1021/ef100073m
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Figure 11. Leakage network system consisting of faults and porous medium.
Figure 12. CO2 saturation after 1000 years in the leakage network system.
faults and porous medium to examine how fast injected CO2 moves to the surface, as shown in Figure 11. Here, the permeability of faults is assumed as 1 darcy, and the local grid refinement (LGR) method is applied to describe the small aperture size of faults. Figure 12 shows that CO2 does not reach the surface after 1000 years. However, it rose up to 50 m under the surface. Also, when CO2 enters the fault, it moves very quickly within the fault and flows into the porous medium. After that time, it takes hundreds of years to meet another faults, and as the CO2 phase is changed to gas around a 800 m depth, the velocity of CO2 increases. This means that the leakage possibility increases. Therefore, we should not only pay attention to the target aquifer but also to the upper formation lies on the target aquifer.
vertical permeability of deep strata was set much higher than the actual. The result shows that CO2 rises 500 m at 1000 years and 460 m at 5000 years. This has arisen from the dissolving of CO2 in the formation water, and CO2 dissolved eventually sank as time passed. (3) Moreover, because more stable sequestration will be possible when the CO2 phase is supercritical, we performed the simulation at the depth of 2100 m. As a result, at the depth of 1100 m, where CO2 stays in the gas phase, it rose 500 m for 1000 years, while it moved up to 320 m at 2100 m, where it stays in the supercritical phase. Therefore, we conclude that the deeper saline aquifer is more effective and stable for CO2 sequestration. (4) CO2 may leak faster when there are leakage networks consisting of faults that act like a conduit and porous mediums. In this system, the leakage possibility increases. Therefore, we should pay attention to the formation lies on the target aquifer to prevent the possible leakage of injected CO2.
Conclusions This study performed the simulation to predict the possibility of CO2 leakage in a deep saline aquifer that does not have a sealing structure. The results are as follows: (1) The possibility of CO2 leakage was estimated through the porous and permeable upper formation. The result shows that the injected CO2 rises 240 m up to a 860 m depth and does not leak and affect either the upper formation or the surface. (2) The
Acknowledgment. The authors express appreciation to the Korean Energy Management Cooperation for providing the financial support to this research. The study conducted by the Energy Management Corporation in 2008-2009, one of “Development of FracNetFlow Reservoir Simulator”, was conducted as part of the project. 3298
