Influence of CO2–Brine Co-injection on CO2 Storage Capacity

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Influence of CO2−Brine Co-injection on CO2 Storage Capacity Enhancement in Deep Saline Aquifers: An Experimental Study on Hawkesbury Sandstone Formation T. D. Rathnaweera, P. G. Ranjith,* M. S. A. Perera, and A. Haque Department of Civil Engineering, Monash University, Building 60, Melbourne, Victoria 3800, Australia ABSTRACT: This study was conducted to identify a potential CO2-storage-capacity-enhancement technique: enhancement of CO2 storage through co-injection or the simultaneous injection of CO2 and brine into saline aquifers. A series of triaxial permeability tests on brine-saturated sandstone samples for a range of injection pressures (4−10 MPa) under different confining pressures (20−35 MPa) was performed at 35 °C constant temperature. To clearly identify the sequestration-enhancement capability of the proposed novel method, conventional CO2 injection (injection of only CO2 into brine-saturated rock) was also carried out under the same test conditions. Both tests were subjected to comprehensive chemical analyses to evaluate the alteration of CO2 solubility in brine caused by the proposed method. CO2 flow behavior under conventional CO2 injection may convert from two- to single-phase flow over time around the injection point, as a result of forced brine migration. This may create a suddenly increased advective flux sometime after injection, which negatively affects the carbonation efficiency and eventually the mineral trapping process. Such issues can be eliminated by the proposed CO2−brine co-injection technique, because it offers significantly slower flow rates under the continuously available two-phase condition in the system. According to the results, the resulting slower flow rates under the co-injection process further enhance the mineral trapping process, allowing for additional time to activate the dissolution reaction compared to the conventional injection process. This will enable field projects to reduce the extensive time required for CO2 solubility in brine. Importantly, the solubility enhancement resulting from the proposed co-injection is much greater for supercritical CO2. This demonstrates the better performance expected of the proposed novel co-injection process under field conditions, because CO2 generally exists in its supercritical state in deep saline aquifers. In addition, the results show that the resulting H+ ion concentration increases with an increasing confining pressure, confirming the positive influence of aquifer depth on solubility under any injection conditions. Interestingly, this depth effect on solubility enhancement appears to be greater for co-injection than conventional injection. The proposed co-injection technique is also favorable for the long-term safety of the process, because the associated reduced CO2 relative permeability in saline aquifers also offers more opportunity for hydrodynamic trapping mechanisms.

1. INTRODUCTION CO 2 geo-sequestration is an effective atmospheric CO 2 mitigation method,1 and the injection of CO2 at the largest possible rates using the smallest number of wells has recently been identified as an economically feasible option for CO2 sequestration in deep saline aquifers.2 However, the solubility of CO2 in brine and the associated unpredictable brine and CO2 relative permeability variations in the aquifer lead to the creation of unpredictable CO2 injection and storage rates during the sequestration process. Precise knowledge of the multiphase flow behavior of brine and CO2 in reservoir rock is therefore required to achieve prospective storage targets and to make appropriate operational decisions on CO2 sequestration in deep saline aquifers. With respect to brine−CO2 multiphase flow behavior in deep saline aquifers during CO2 sequestration, the concept of relative permeability plays an important role, because it offers quantitative measurement of the spatial and temporal distribution and migration of CO2 in the aquifer. Understanding the behavior of CO2 in the subsurface structure during the injection stage is also required to maintain the CO2 leakage risk at a minimal level, which is one of the critical concerns in any sequestration project in terms of long-term stability. According to Juanes et al.,3 brine−CO2 multiphase flow behavior in the reservoir has a critical influence on its capillary/residual trapping © XXXX American Chemical Society

mechanisms, which, in turn, affect the effectiveness of the other sequestration mechanisms. Furthermore, brine−CO2 relative permeability measurements are also important in estimating and optimizing the reservoir storage capacity, because they govern the solubility trapping process. To date, although the importance of multiphase flow measurements for reservoir performance in oil recovery has been well-documented, very few laboratory studies have been conducted on CO2−brine systems for saline aquifers.4−12 Apart from experimental relative permeability studies, many numerical modeling studies have been reported, most of which show the important role played by multiphase flow behavior in CO2 sequestration.3,13−18 All of these experimental and numerical studies show the importance of precise identification of multiphase flow behavior on CO2 sequestration in deep geological formations, including saline aquifers. However, the CO2 storage process in saline aquifers occurs at quite a slow rate as a result of the associated slow interaction among brine−CO2 and rock minerals, and the slow solubility of injected CO2 in brine is one of the major Received: January 21, 2016 Revised: April 10, 2016

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DOI: 10.1021/acs.energyfuels.6b00113 Energy Fuels XXXX, XXX, XXX−XXX

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Figure 1. Results of CT scanning along the sample length: (a) top surface, (b) middle section, and (c) bottom surface. then cored into 38 mm diameter and 76 mm high samples, and finally, the sample ends were ground. The prepared samples were first ovendried at 35 °C for 48 h (this low-temperature condition was selected to avoid microstructural damage). A total of 28 prepared samples were then placed in brine-filled (salinity: 15% NaCl by weight) desiccators and subjected to brine saturation for 2 weeks under vacuum to ensure maximum saturation, and the weights of the samples were measured regularly to ensure the steady-state full saturation condition until a constant mass was reached. The specimens were removed from the desiccators just before the tests. Later, the same NaCl concentration was used for the brine injection processes under single- and two-phase conditions. 2.2. Relative Permeability Tests. A series of steady-state permeability tests was conducted using the high-pressure triaxial setup available in the Deep Earth Energy Laboratory at Monash University under drained conditions.20 The newly developed high-pressure triaxial setup used in this study21 and its schematic diagram are shown in Figure 2. After the sample is placed in the pressure cell (details of the procedure can be found in ref 20), the cell was filled with oil and the required confining pressure was applied using a syringe pump (see Figure 2). The cell temperature was then adjusted to 35 °C (a typical reservoir temperature condition) using the temperature control unit and maintained for 24 h to ensure temperature equilibrium. Finally, CO2 and brine co-injection was initiated. The injection unit consists of two pumps connected with a set of needle valves and pressure gauges. As shown in Figure 3, a compressed air-based Haskel MS-36 liquid pump was used to inject brine and a syringe pump (Teledyne Isco, model 260D) was used to inject CO2. This configuration provides continuous fluid delivery, and the refilling and delivery of each pump are automatically controlled by two controllers attached to each pump. Before entering the sample, the injecting CO2 and brine were brought to the experimental temperature condition of 35 °C using the attached heating system inside the individual units, and this 35 °C temperature condition was maintained during the whole injection period (see Figure 4). The injection was performed by simultaneously injecting CO2 and brine into the sample under controlled pressure conditions (see Figures 2 and 3). The CO2 pressure was first set to the required injection pressure, and the same injection pressure was then assigned to the brine. After individually obtaining the required injection pressures, the CO2 (N/V 1) and brine (N/V 2) inlet valves (see Figure 3) were opened and kept open to achieve pressure equilibrium before the main upstream valve was opened (N/V 3), to allow for CO2−brine to move toward the sample. Downstream CO2 and brine flow rates were recorded until the steady-state condition was reached. The flushed-out brine was collected using a Dreshel bottle to separate CO2 and brine in the effluent, and the corresponding effluent brine weight over time was recorded using a precision balance [an EHB + 3000 g × 0.01 g (non-trade)]. The results were then used to calculate the brine release rates. Similarly, the separate CO2 flow rate was also measured using a digital flow meter (a digital gas

drawbacks. Research studies have therefore been initiated to determine possible reaction-enhancement techniques, including that by Juanes et al.3 These researchers showed how the performance of the CO2 sequestration process can be improved by injecting alternating slugs of water and CO2 into the aquifer. According to their results, the injection of water slugs alternating with CO2 injection has the ability to enhance sequestration, because the injecting water force causes the breaking up of large connected CO2 plumes. This enhances the CO2 trapping process by spreading out accumulated CO2 at the top of the aquifer. However, according to Eke et al.,19 the use of brine for pure water has the ability to reduce the buoyancy force, the driving force for CO2 back migration toward the surface, because CO2 dissolved in saline water or brine creates much denser carbonic liquid formation compared to pure water. In addition, as stated by Eke et al.,19 a major drawback with CO2−water co-injection is that it requires the injection of significant volumes of water into the formation, and unfortunately, that requires significant amounts of energy and money. More importantly, injecting the world’s most precious resource “water” into deep saline formations is not a good option. This makes CO2−brine co-injection a promising option for the enhancement of deep saline sequestration. Therefore, this novel approach was tested in the present study, by simultaneously injecting CO2 and brine into reservoir rock samples under in situ stress conditions. Such CO2−brine injection creates multiphase flow behavior inside the rock mass. The aim of this study is therefore to identify the potential CO2-storage-capacity-enhancement mechanism in saline aquifers by applying current knowledge of CO2−brine multiphase flow behavior in aquifers.

2. EXPERIMENTAL SECTION 2.1. Sample Preparation. Hawkesbury sandstone blocks, belonging to the Triassic geological age, were obtained from the Sydney basin, New South Wales, Australia. The mineralogy of the testing material was obtained by conducting X-ray diffraction (XRD) analysis. According to the analysis, the mineralogical structure of the tested sandstone is around 90% quartz, 6% calcite, 2% kaolinite, 1% muscovite, and 31.8 °C, the critical temperature of CO2. Therefore, the observed trends relate to the phase transition of CO2 from sub- to supercritical. This indicates the importance of examining the influence of the CO2 phase on the shape of the relative permeability curve, particularly in light of the current lack of knowledge of the subject as a result of the limited studies available. 3.6.1. Influence of the CO2 Phase Change on the Relative Permeability Behavior in Saline Aquifers. It is important to know whether supercritical CO2 has a different wetting behavior with reservoir rock compared to subcritical CO2 in deep saline aquifer CO2 sequestration or whether the unique physical properties of supercritical CO2, including its greater density, affect its relative permeability behavior in these formations. As mentioned earlier, preferable saline aquifers for CO2 sequestration are located at great depths, at which the pressure and temperature conditions normally exceed the critical values of CO2 (critical pressure of 7.38 MPa and temperature of 31 °C). Therefore, CO2 mostly exists in its supercritical state in deep saline aquifers. However, the influence of the CO2 phase on its relative permeability characteristics is to date poorly understood. When CO2 reaches its critical conditions, it becomes more and more dense with increasing pressure35 and may exceed the brine density under certain pressure and temperature conditions.36 The mixing of brine in supercritical CO2 is therefore much easier than in gas CO2,36,37 the phase condition. This has a clear influence on CO2 solubility in brine and, therefore, the storage process. In addition, the CO2 phase change also influences wetting and non-wetting behavior in the aquifer, because, if CO2 is in its gas state, the brine phase acts as the wetting phase and injected CO2 behaves as the non-wetting phase, which will change for supercritical CO2. This is because supercritical CO2 may exhibit a weak wetting behavior compared to gaseous CO2 (non-wetting behavior),38 and this wettability behavior is one of the facts governing the relative permeability characteristics of reservoir rocks.39 The different wettability behaviors of supercritical and gaseous CO2 have been shown by Chalbaud et al.38 based on wetting angle measurements. According to these researchers, supercritical CO2 has much greater wetting angles in the two-phase system compared to gaseous CO2. This means that a CO2 film spread on brine-wetted pores can stabilize over a larger range of capillary pressures and eventually enhance CO2

which implies that the pore changes created by confining and injection pressures in the samples. If the injection pressure effect is considered, the high advective flux created by greater injection pressures enhances the brine drainage process, which reduces the brine trapping mechanism in the aquifer. On the other hand, an increased confining pressure enhances the rock mass tortuosity for CO2 movement, which reduces the CO2 flow-induced advective flux in saturated brine, resulting in lower brine drainage and greater trapping possibility, including solubility trapping in the system. In addition to the influence of depth, the influence of the aquifer temperature is also worth investigation as a result of the expected high-temperature conditions in deep saline aquifers compared to the ground level. High temperatures are expected to have a negative influence on the solubility reaction, because CO2 solubility in brine decreases with increasing temperature.33 However, this was beyond the scope of the present study. It is also expected that the phase change of CO2 from sub- to supercritical also positively influences the solubility reaction in sequestration environments as a result of the greater reactivity and greater availability of the free energy of supercritical CO2 molecules.34 Figure 14 gives ample evidence for this, where sudden pH reduction and H+ ion concentration increment can be seen at the point where the injection pressure changes from 6 to 8 MPa. According to Figure 14, supercritical injection under co-injection displays a significantly greater influence on solubility than conventional injection. For example, when the injection pressure changes from 6 MPa (subcritical) to 8 MPa (supercritical) under 20 MPa confining pressure, the H+ ion concentration increases by around 75% with co-injection compared to only around 18% with conventional injection. This confirms that the CO2 phase change does not have much influence on the solubility reaction in conventional injection compared to co-injection. This shows the greater applicability of co-injection under field conditions, which further demonstrates its value as a CO2-storage-capacity-enhancement technique. 3.6. Alteration of the Relative Permeability Behavior in Saline Aquifers through Co-injection and Its Influence on the Long-Term Stability of CO2 Sequestration. The relative permeability variations observed for co-injection against injection and confining pressures are shown in Figure 16. According to the general rule of two-phase flow,22 when the relative permeability of one phase increases, the relative permeability of the other phase should decrease. This argument is consistent with the results of the present study for co-injection, where, when the relative permeability of the CO2 phase increased, the relative permeability of the brine phase began to decrease (see Figure 12). For instance, at 20 MPa confining pressure, when the fluid injection pressure increases from 4 to 6 MPa, the relative permeability K

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Figure 16. Relative permeability variations in CO2 and brine phases with respect to different injection and confining pressures.

movement through the film drainage process, resulting in enhanced relative permeability characteristics compared to subcritical CO2.40 This enhanced wettability behavior of supercritical CO2 compared to subcritical CO2 is a strong reason for the observed greater relative CO2 permeability for supercritical CO2 beyond the critical point and the increasing relative permeability with the further increase of the injection pressure (see Figure 16). The former gas or subcritical CO2 relative permeability reduction trend with an increasing injection pressure may relate to the Klinkenberg slip flow effect, where gas slippage at the pore wall as a result of the highly compressible nature of gas CO2 creates lower permeability values under gasphase CO2. This slip flow effect increases with an increasing pore pressure or injection pressure, with the possible reduction of CO2 permeability with an increasing injection pressure.35 The combined influence of the variation of wettability characteristics and the slip flow effect may create the gas CO2 relative permeability trend (Figure 16) with the co-injection process. 3.6.2. Influence of Other Influencing Factors on the Flow Behavior in Saline Aquifers. The effect of interfacial tension (IFT) on wettability in a two-phase system is also critical and cannot be ignored.37 According to Hebach et al. and Yang and Gu,41,42 IFT between CO2 and brine strongly depends upon the injection pressure and decreases with an increasing injection pressure, creating enhanced relative flow characteristics. This is because IFT creates a negative effect or barrier for CO2 migration through the rock pore space. Importantly, this IFT varies significantly around the critical point of CO2, and even a small variation in the pressure or temperature around this point may

lead to significant variation in IFT between CO2 and brine.43 Because of this strong influence of IFT on wettability, it also has a strong influence on relative permeability and saturation in reservoir rock formations.8 Viscosity governs the IFT characteristics for the two phases, and fluid movement through the pore space becomes much easier with enhanced viscosity contrast between CO2 and brine as a result of reduced IFT.44 Figure 17 shows the observed variation in viscosity ratios between CO2 and brine against different injection pressures. As the figure shows, the viscosity ratio significantly increases when the subcritical CO2 injection phase changes to the supercritical phase. For example, at 35 °C, the viscosity ratio increases from 9.67 × 10−10 to 1.19 × 10−9 when the subcritical pressure of 6 MPa changes to the supercritical pressure of 8 MPa. This enhanced viscosity contrast between CO2 and brine in the supercritical state also causes the observed enhanced CO2 relative permeability characteristics in the rock samples. The decreasing effective stress with increasing injection pressure may also have a significant influence on CO2 permeability enhancement with increasing injection pressure. To distinguish the effects of influencing factors (IFT, wettability, slip flow, and effective stress) on individual CO2 behavior, the effective permeability values for co-injection, conventional injection, and single-phase injection were compared. Figure 18 shows the effective CO2 permeability variations for each condition under two different confining pressure conditions (20 and 30 MPa). According to Figure 18, the single-phase CO2 permeability values are far higher for both conventional and co-injection values. For example, under 4 MPa injection and 20 MPa confining pressure conditions, the single-phase permeability in L

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Figure 17. Behavior of the viscosity ratio between CO2 and brine under sub- and supercritical conditions.

Figure 18. Effective CO2 permeability variation with injection pressure for three different conditions: (a) 20 MPa and (b) 30 MPa confining pressure.

pore space. This eventually reduces rock mass tortuosity for CO2 movement, resulting in enhanced reservoir permeability. Although this happens in dry samples, the slip flow effect may be dominant at that stage. Interestingly, co-injection displayed a unique effective CO2 permeability variation compared to the other two conditions. In addition, the lowest permeability values were obtained for co-injection cases, probably as a result of the influence of the IFT, capillary, and wettability effects of brine and CO2 phases compared to the conventional and single-phase conditions. In contrast, the slip flow effect significantly influences the single-phase flow behavior compared to other factors, and conventional injection is predominantly affected more by the effective stress effect than the slip flow, IFT, and wettability effects. However, co-injection displays more influence of the IFT and wettability effects, which is confirmed by the lowest permeability values compared to the conventional case. According to Ketzer et al.,34 if a reservoir has a higher permeability value, the efficiency of hydrodynamic trapping decreases, facilitating the easy escape of injected CO2 from the reservoir, which is not favorable for sequestration. Therefore, the lower permeability behavior observed under co-injection has the capability to enhance the hydrodynamic trapping mechanism compared to conventional injection, which is beneficial for long-term sequestration. 3.7. Comparison of the Co-injection Process to Other Innovative Concepts. A similar study conducted by Eke et al.19 to identify innovative concepts that can cope with the uncertainties associated with the underground geological formations

dry samples displays a value of 365.73 mD, which is significantly higher than that for conventional injection (99.47 mD) and co-injection (6.68 mD). This is probably as a result of the saturation effect, because brine saturation obstructs the free flow paths for CO2 movement, resulting in reduced effective permeability conditions compared to the dry condition. As Figure 18 shows CO2 permeability in dry reservoir rock samples decreases with an increasing injection pressure, and a similar trend was observed by Rathnaweera et al.20 In contrast, the increasing effective CO2 permeability with an increased injection pressure can be seen for conventional injection, whereas co-injection initially displayed a decreasing trend under the subcritical pressure range (4−7 MPa) and then displayed an increasing trend with a further increase of the injection pressure from 7 to 10 MPa. The decreasing permeability trend of CO2 in a single-phase condition is related to the Klinkenberg effect,45 and a comprehensive description of the Klinkenberg effect on dry permeability variation can be found in the study by Rathnaweera et al.20 If the permeability of conventional injection and co-injection are considered, as a result of brine saturation, the slip flow effect between the solid wall and mean gas molecules is decreased as a result of the friction between brine and gas phases, resulting in a minor Klinkenberg effect for conventional and co-injection cases (both wet conditions). The observed increasing trend of effective CO2 under conventional injection with increasing injection pressure is probably due to the effective stress influence, where the effective stress effect decreases with an increasing injection pressure and its reduction causes the rock mass to expand by increasing its M

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CO2 relative permeability in saline aquifers, and the associated improved hydrodynamic trapping mechanism confirms that it is a safer CO2 storage process in saline aquifers, with minimal risk of potential CO2 leakage from the aquifer to surrounding freshwater aquifers. (6) The extensive time required for the CO2 solubility process in brine is one of the major disadvantages of CO2 sequestration in saline aquifers. Therefore, the ability to address this issue using the novel co-injection concept is a ground-breaking finding for CO2 sequestration in saline aquifers.

and enhance CO2 storage in the formation found that the CO2/brine surface mixing strategy has more advantages compared to the co-injection proposed in this present study. These researchers investigated four injection strategies, including conventional CO2 injection, CO2/brine surface mixing and injection, CO2/water surface mixing and injection, and CO2/ brine co-injection. According to them, with respect to conventional CO2 injection and CO2/water surface mixing and injection, CO2/brine surface mixing and CO2/brine co-injection methods have more advantages. Among the disadvantages of CO2/water surface mixing and injection, a major limitation is that it requires the injection of significant volumes of water into the formation. If conventional injection is considered, it mainly relies on the presence of a good sealing (caprock). In addition, it requires a sufficient capillary entry pressure to hold injected CO2. Finally, the researchers concluded that CO2/brine surface mixing and injection is the best of the four injection scenarios considered in their study. With respect to the CO2/brine co-injection strategy, CO2/brine surface dissolution in the mixing vessel proves to be the primary advantage of the CO2/brine surface mixing and injection strategy, because it speeds up the solubility reaction, thereby reducing time required to achieve immobilization in the subsurface formation. However, according to the results of the present study, CO2 can also dissolve in brine before release to the reservoir under co-injection, which also helps to speed up CO2 immobilization. Furthermore, the design of a mixing vessel for surface mixing needs extra capital, because it requires more power and additional operational costs to maintain the desirable design variables, including the operating temperature and pressure of the mixing vessel.19 These limitations are well-explained by Eke et al.19 Therefore, although CO2/brine surface mixing enhances CO2 immobilization, the operational costs involved in the process may reduce its feasibility compared to co-injection. However, it is necessary to conduct in-depth comparative research on these two processes, considering various aspects, including the injection/extraction process, pipeline, surface equipment, and energy costs, before coming to a conclusion.

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AUTHOR INFORMATION

Corresponding Author

*Telephone/Fax: 61-3-9905 4982. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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NOMENCLATURE Kb = single-phase permeability of brine KCO2 = single-phase permeability of CO2 krCO2 = relative permeability of CO2 krb = relative permeability of brine kCO2 = effective CO2 permeability QCO2 = CO2 flow rate Qb = brine flow rate μCO2 = viscosity of CO2 μb = viscosity of brine Pin = inlet (injection) pressure Patm = atmospheric pressure A = sample area L = sample length b = Klinkenberg correction factor REFERENCES

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4. CONCLUSION This study was conducted to identify a novel CO2-storagecapacity-enhancement practice for saline aquifers, the coinjection of CO2 and brine into saline aquifers. On the basis of the experimental results, the following major conclusions can be drawn: (1) Conventional CO2 injection causes a sudden increase in advective flux after some time of injection. This reduces the carbonation efficiency and eventually the mineral trapping mechanism of injecting CO2 in the reservoir and, therefore, negatively affects the CO2 sequestration process. Such issues can be eliminated by the proposed CO2−brine co-injection technique. (2) The proposed CO2−brine co-injection also enhances the solubility trapping process. This is confirmed by the greater pH reductions and H+ accumulations observed in the effluents produced in co-injection compared to conventional injection. (3) Importantly, this enhancement of CO2 solubility trapping by the proposed co-injection technique is aquifer-typedependent, and its effectiveness increases with increasing aquifer depth. Therefore, the proposed technique is preferable for deeper aquifers. (4) Furthermore, supercritical injection under co-injection has a significantly greater influence on solubility than conventional injection, which is particularly important for field CO2 sequestration projects, in which CO2 is in its supercritical state in the aquifer. (5) CO2−brine co-injection creates reduced N

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DOI: 10.1021/acs.energyfuels.6b00113 Energy Fuels XXXX, XXX, XXX−XXX