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Effect of Mineral Dissolution/Precipitation and CO2 Exsolution on CO2 transport in Geological Carbon Storage Published as part of the Accounts of Chemical Research special issue “Chemistry of Geologic Carbon Storage”. Ruina Xu, Rong Li, Jin Ma, Di He, and Peixue Jiang* Key Laboratory for CO2 Utilization and Reduction Technology of Beijing, Key Laboratory for Thermal Science and Power Engineering of Ministry of Education, Department of Thermal Engineering, Tsinghua University, Beijing 100084, China CONSPECTUS: Geological carbon sequestration (GCS) in deep saline aquifers is an effective means for storing carbon dioxide to address global climate change. As the time after injection increases, the safety of storage increases as the CO2 transforms from a separate phase to CO2(aq) and HCO3− by dissolution and then to carbonates by mineral dissolution. However, subsequent depressurization could lead to dissolved CO2(aq) escaping from the formation water and creating a new separate phase which may reduce the GCS system safety. The mineral dissolution and the CO2 exsolution and mineral precipitation during depressurization change the morphology, porosity, and permeability of the porous rock medium, which then affects the two-phase flow of the CO2 and formation water. A better understanding of these effects on the CO2−water two-phase flow will improve predictions of the long-term CO2 storage reliability, especially the impact of depressurization on the long-term stability. In this Account, we summarize our recent work on the effect of CO2 exsolution and mineral dissolution/precipitation on CO2 transport in GCS reservoirs. We place emphasis on understanding the behavior and transformation of the carbon components in the reservoir, including CO2(sc/g), CO2(aq), HCO3−, and carbonate minerals (calcite and dolomite), highlight their transport and mobility by coupled geochemical and two-phase flow processes, and consider the implications of these transport mechanisms on estimates of the long-term safety of GCS. We describe experimental and numerical pore- and core-scale methods used in our lab in conjunction with industrial and international partners to investigate these effects. Experimental results show how mineral dissolution affects permeability, capillary pressure, and relative permeability, which are important phenomena affecting the input parameters for reservoir flow modeling. The porosity and the absolute permeability increase when CO2 dissolved water is continuously injected through the core. The MRI results indicate dissolution of the carbonates during the experiments since the porosity has been increased after the core-flooding experiments. The mineral dissolution changes the pore structure by enlarging the throat diameters and decreasing the pore specific surface areas, resulting in lower CO2/water capillary pressures and changes in the relative permeability. When the reservoir pressure decreases, the CO2 exsolution occurs due to the reduction of solubility. The CO2 bubbles preferentially grow toward the larger pores instead of toward the throats or the finer pores during the depressurization. After exsolution, the exsolved CO2 phase shows low mobility due to the highly dispersed pore-scale morphology, and the well dispersed small bubbles tend to merge without interface contact driven by the Ostwald ripening mechanism. During depressurization, the dissolved carbonate could also precipitate as a result of increasing pH. There is increasing formation water flow resistance and low mobility of the CO2 in the presence of CO2 exsolution and carbonate precipitation. These effects produce a self-sealing mechanism that may reduce unfavorable CO2 migration even in the presence of sudden reservoir depressurization.
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INTRODUCTION Geological carbon sequestration (GCS) in deep saline aquifers is an effective means for storing carbon dioxide to address global climate change.1 The commercial scale projects, such as at Sleipner in the Norwegian part of the North Sea, In Salah in Algeria, and Snøhvit in offshore Norway, have proved the engineering feasibility of GCS in saline aquifers.2 In China, a CO2 geological sequestration demonstration project was developed by Shenhua Group in Ordos basin. A total of 0.3 million tons of CO2 have been injected into the target saline aquifer, and results © 2017 American Chemical Society
provided useful information on the reservoir behavior during injection period.3−7 However, the long-term safety is a concern to policy makers and the public. Comprehensive assessments of this problem depend on thorough scientific understanding of the complex processes of CO2−water−mineral interactions and their coupling effect on the CO2−water multiphase flow in subsurface reservoirs. Received: December 31, 2016 Published: August 16, 2017 2056
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Figure 1. Pore- to reservoir-scale schematics showing (A) CO2 and mineral dissolution without depressurization and (B) CO2 exsolution and mineral precipitation with depressurization.
the corresponding effects on the two-phase flow transport of CO2 in the reservoir. Further understanding will improve predictions of CO2 migration in reservoirs and clarify the impacts of depressurization on the long-term safety of GCS reservoirs. In this Account, we provide an overview of the effect of CO2 exsolution and mineral dissolution/precipitation on CO2 transport in GCS reservoirs. We place emphasis on understanding the behavior and transformation of the carbon components in the reservoir, including CO2(sc/g), CO2(aq), HCO3−, and carbonate minerals (calcite and dolomite), and highlight their transport and mobility by the coupled geochemical and two-phase flow processes, and the implications for the long-term safety of GCS.
Saline aquifers can typically be assumed to have geochemical equilibrium between rock-forming minerals and the formation water. CO2 injection into a saline aquifer not only induces twophase flow of the CO2 and the formation water (or brine) but also disturbs the geochemical equilibrium. When CO2 contacts brine, part of the CO2 dissolves in the brine as CO2(aq), which is referred to as solution trapping as shown in Figure 1. The rest of the CO2, the CO2 rich phase (CO2(sc/g)), exists as a separate phase that can migrate through the porous medium as CO2 saturated with water and is then trapped by caprock having a high capillary entrance pressure (structural trapping) or is trapped in the pore spaces by capillary forces (residual trapping).1,8 The dissolved CO2(aq) may induce mineral dissolution and form ionic species such as HCO3− and CO32−, which will change the reservoir porosity and permeability.9,10 Changes in the injection parameters, such as the pressure, temperature, and mass flow rate, may also cause a range of coupled hydrodynamics and chemical changes. During long-term CO2 storage, the pressure is the main parameter that can change due to leakage or other abnormal processes, such as stopping the injection or brine withdrawal for reservoir pressure balance.11−14 As pressure decreases, the volume of the CO2 rich phase (CO2(sc/g)) will expand and dissolved CO2(aq) will exsolve. As CO2 exsolves from the aqueous phase, the original chemical equilibrium between CO2(aq), H2CO3, and HCO3− can be re-established. As a result, pH increases and minerals begin to precipitate. These geochemical reactions, including CO2 and mineral dissolution, CO2 exsolution, and mineral precipitation during depressurization, change the morphology, porosity, permeability, and wettability of the pre-existing rock and affect the two-phase flow of the CO2 and formation water.15−18 The transport of the injected CO2 influences the CO2 dissolution and exsolution in the formation water, which further affects the geochemical reactions. Generally, geochemical reactions cause the transfer of the CO2 from the separate CO2 rich phase to the aqueous phase as the time after injection increases, which improves the GCS safety over the long-term. However, depressurization leads to the dissolved CO2 escaping from the formation water and creating a new separate phase, which may present risks to the GCS. A better understanding of mineral dissolution and the CO2 behavior during depressurization is needed for a better understanding of
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RESEARCH STRATEGY AND METHODS Each of the coupled processes has its own characteristic length scale. The CO2 exsolution, mineral dissolution, and precipitation processes occur in the pore, which in turn affects the CO2−water two-phase flow in the porous media. The important parameters that describe the CO2−water two-phase flow, such as the capillary pressure and relative permeability, are average parameters obtained in cores and then used in field scale models. These coupled processes are not only a combination of physical and chemical processes but also involve the challenge of multiscale problems.8 Our research group in Tsinghua University has built experimental systems and numerical methods and cooperated with industrial and international partners to investigate these coupled processes at various scales. The overall strategy involves the following: (i) Pore-scale behavior, capturing the two-phase flow behavior in the porous media to provide evidence of secondary phases and their effects on the transport at site-specific locations19,21,22 (ii) Core-scale behavior, linking the pore-scale and reservoir scale models through the basic physical parameters, such as the porosity, permeability, capillary pressure, and relative permeability. Analysis combining core- and pore-scale investigations provides understanding on why these parameters change as the conditions change.24−26,45 (iii) Reservoir-scale behavior, large scale simulation and demonstration injection in the real site validate the feasibility of CO2 storage in saline aquifers.3,27 Lessons learned through demonstration CO2 storage projects also raise new questions that need to be 2057
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Figure 2. (A) Micromodel experimental system. (B) Micromodel sample: (1) schematic of the integrated micromodel design; (2) physical picture of the fabricated sample. Adapted from ref 19. Copyright 2017 Elsevier.
Figure 3. Core flooding experimental system using the online NMR/MRI equipment. Adapted from ref 24. Copyright 2015 American Geophysical Union.
addressed with pore- or core-scale research. In this Account, we focus on the results of our pore- and core-scale research work, which was obtained by the following experimental systems and numerical methods.
and VOF based computational fluid dynamic models.22 This numerical scheme can be used to investigate the absolute permeability, relative permeability, and pore-scale fluid distribution for various pore geometries and surface wettabilities.23
At Pore Scale
At Core Scale
We present a lab-on-a-chip method to investigate pore-scale behavior of exsolved CO2 phase during the depressurization process in GCS. A micromodel experimental system has been built in our lab (Figure 2A).19 The system can accommodate 12 MPa and 60 °C, which covers the supercritical and subcritical state of CO2 and allows enough pressure variation for changing the pressure rapidly. The micromodel sample (Figure 2B), which provides a target physical model, is loaded into a specially designed high-pressure chamber with a visual cell and dynamically visualized with an inverted microscope (Ti-E Nikon series, 1.83 μm/pixel resolution) with a fluorescence module. The long-working-distance 5× objective lens and the high-resolution CCD camera (Nikon Digital Sight DS-Ri1) are used to capture images. The images show the nucleation and growth of exsolved CO2 bubbles and even the surface property changes in the pores. Pore-scale numerical models were then developed using the pseudopotential lattice Boltzmann model21
We used a core-flooding associated with nuclear magnetic resonance (NMR) and magnetic resonance imaging (MRI) to investigate the mineral dissolution and the depressurization process effects on two-phase flow properties of the target rocks. A core-flooding visualization experimental system, which can accommodate 12 MPa and 60 °C, with online NMR and MRI has been built in our lab (Figure 3).24−26,45 A core sample with 1 in. diameter is placed horizontally in a holder inside the NMR/ MRI system (Niumag, MesoMR23-060H-I, 21.3 MHz, 0.5 ± 0.05 T). The NMR measurements are sensitive to the hydrogen nuclei in the pore water in the sample; therefore, the average core saturation and pore-water distribution can be measured by conducting a CPMG (Carr−Purcell−Meiboom−Gill)28 pulse sequence. The aqueous phase fluid distribution in the cores is then visualized with MR images. Combining these properties with the flow rate and pressure drop measurements, the capillary pressure and relative permeability curves as functions of the CO2 2058
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Figure 4. (A) Experiments: (1) the core sample; (2) the core-flooding experimental program. (B) XRD measurement from two parts of the core after these experiments: (1) close to the inlet of the core; (2) close to the outlet of the core (mQ, detrital monocrystalline quartz; Kfs, K-feldspar; Pl, Plagioclase; Lithic, quartzose lithic fragment; Q1, authigenic quartz; Mus, muscovite). (C) (1) Difference of magnetic resonance image signal between the core before and after the experiments; (2) porosity and absolute permeability; (3) capillary pressure (left. entire saturation range; right, zoom; solid lines represent general trends estimated with Brooks and Corey curves); (4) Relative permeability. Adapted from ref 24. Copyright 2015 American Geophysical Union.
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EFFECT OF MINERAL DISSOLUTION ON CO2 TRANSPORT Once the injected CO2(sc/g) has swept through the reservoir, the local CO2(aq) concentration, xCO2,aq, quickly approaches the solubility limit. The denser aqueous phase with the CO2(aq) overlies the less dense fresh brine, and gravity driven fingering flows occur that accelerate the mass transfer of CO2(aq) in the aqueous zone through convection into the brine.29−33 The resulting brine acidification then leads to dissolution of some of the rock-forming minerals, especially the carbonates. Kaszuba et al. reviewed fluid−mineral and fluid−rock interactions that take place in water at a range of scales, from the microscale to the core scale.34 Previous experimental studies have shown that mineral
saturation can be deduced for use in reservoir models. A multislice spin echo imaging sequence (MSE) impulse sequence has been applied to image local aqueous phase content, which is proportional to the intensity of the 1H NMR signal. The image of the aqueous phase saturation distribution can be obtained by dividing the intensity value of the unsaturated image with the intensity value of the 100% saturated image at each pixel. The images were taken of a 24.6 mm height and 50.0 mm length area, and the slice thickness excited selectively by the NMR impulse was 5.0 mm. The spatial resolution of the NMR images is 0.44 mm (horizontal direction) × 0.47 mm (vertical direction) per pixel. 2059
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Figure 5. Two-phase flow distribution when (A) S (specific surface area) = 0.133 and Sw (wetting phase saturation) = (1) 0.32, (2) 0.61, or (3) 0.85 and (B) S = 0.200 and Sw = (1) 0.32, (2) 0.61, or (3) 0.91. (C) Relative permeability curves for specific surface areas corresponding to cases A and B. Adapted from ref 21. Copyright 2015 Emerald Group Publishing Limited.
two MR images, taken before experiment 1 and after experiment 8 with the rock sample fully saturated with pure water, shows the difference of magnetic resonance image signal intensity, which is related to the quantity of water in the pores (Figure 4C(1)). It indicates that the porous volume is higher than before the experiments and the porosity increase occurs mostly at the core inlet. The measured porosity and the absolute permeability also increase when CO2 dissolved water is continuously injected through the core (Figure 4C(2)). The porosity increased by 6% while the permeability increased by 80%. The measured absolute permeability after dissolution is 20% higher than the estimated value based on the Kozeny−Carman porosity (φ)−permeability (k) correlation, k ∝ φ3/(1 − φ).38 This indicates the sensitivity of the absolute permeability to the dissolution induced porosity change, which is consistent with the observation of LamyChappuis et al.39 The dissolution of the carbonates in the rock enlarges the pore throats, which opens up new flow channels and greatly increases the pore connectivity and absolute permeability. Longer dissolution times led to much lower capillary pressures in expt 7 compared to the capillary pressures measured before significant dissolution in expts 1 and 2 which indicates that the mineral dissolution induced a capillary pressure decrease (Figure 4C(3)). The CO2 relative permeability increased significantly, while the relative permeability of water was slightly reduced by the mineral dissolution (Figure 4C(4)). In general, the changes in the two-phase flow properties are related to the changes in the intrinsic properties of the rock. The mineral dissolution changes the pore structure by enlarging the throat diameters and decreasing the pore specific surface areas, resulting in lower CO2/water capillary pressures and higher nonwetting phase relative permeability (Figure 4C(4)). We investigated the effect of specific surface area on the relative permeability curves using a lattice Boltzmann model.21 The specific surface area is calculated via dividing the surface area of the circular solid “particle”, Aparticle, by the total volume of the entire porous zone, Vtotal.
dissolution affects the porosity and absolute permeability and also changes the rock surface wettability.35−37 However, the effects of the capillary pressure and relative permeability changes due to the mineral dissolution have not been well studied, especially in quantitative experiments. The material property changes and the two-phase flow characteristics of CO2/water systems affected by mineral dissolution were studied in a series of core-flooding experiments using a Chaunoy sandstone core sample (Triassic sandstone, Paris Basin), which is quartz rich (69% ± 6.9%) with mostly dolomite cement (11% ± −3.3% as average value for the entire core).24 Using the NMR based core-scale setup mentioned in the previous section, experiments were performed in sequence (Figure 4A(2)) with two capillary pressure measurements (nos. 1 and 2), two relative permeability measurements (nos. 3 and 4), two residual trapping measurements (nos. 5 and 6), and then one capillary pressure measurement (no. 7) and one relative permeability measurement (no. 8) to evaluate how these parameters changed after the CO2 flooding tests.24 Both capillary pressure and relative permeability were measured using the steady-states method. The measurement of residual trapping can also be obtained from the result of relative permeability measurement through a drainage−imbibition cycle. As a result, during each two-phase flow experiment, a large amount of CO2(l) or CO2(aq) (at least 50 pore volumes) was injected through the core with different fractional flow under 25 °C and 9 MPa. Each experiment was run in several hours, and the entire contact history of the core with CO2(aq) lasted for 48 days. To characterize the influence of mineral dissolution on the pore structure, before each two-phase flow measurement, the porosity and absolute permeability of the core were remeasured. After the entire experimental procedure, the composition of two slices of the core (one close to the inlet (8 mm) and one close to the outlet (8 mm)) has been assessed based on XRD measurement. The carbonate content has decreased more at the core inlet (from 11% ± 3.3% to 3% ± 1.2%) than at the core outlet (from 11% ± 3.3% to 6% ± 1.8%), while the other minerals have remained constant (Figure 4B). The subtraction of 2060
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Figure 6. Nucleation and growth of exsolved CO2 during depressurization. (A) Schematic diagram of mechanism. (B) Pore-scale experiments: (1) Etching pattern of the porous zone in the sample; (2) SEM scanned cross section of the etched zone. (C) Shot images of micromodel sample at various depleted pressures. (D) Core-scale experiments: (1, 2) MR images of measured local aqueous phase saturation at depleted pressures of 4 and 2 MPa; (3) T2 distribution of the remaining H2O NMR signal at various depleted pressures. Panels A and C adapted from ref 19. Copyright 2017 Elsevier. Panel B adapted from ref 20. Copyright 2017 American Chemical Society. Panel D adapted from ref 25. Copyright 2015 American Chemical Society.
S = A particle /Vtotal = 2πR /[πR2/(1 − ε)] = 2(1 − ε)/R
precipitate from the supersaturated aqueous phase in case their reduced solubility is lower than the concentration of pre-existing CO2(aq) and carbonate minerals.40 However, there is little research related to the depressurization effect on the solubility trapping and mineral trapping.19,25,41−45 We obtained experimental observations on depressurization induced exsolution and precipitation behavior of CO2(aq, sat) and saturated carbonate from the aqueous phase.
(1)
where ε and R represent the porosity and the radius of the porous media. Our pore-scale modeling results indicate that the specific surface area significantly affects the nonwetting phase relative permeability but has minor impact on the wetting phase relative permeability (Figure 5). The modeled pore-scale fluid morphology indicates that the better connectivity of the nonwetting phase increases the relative permeability when the specific surface area is reduced by the mineral dissolution, which is consistent with our core-scale measurements.
CO2 Bubble Nuclei Growth and Ostwald Ripening
When the pore space is fully occupied by CO2(aq,sat) at initially high pressure, the CO2(g) nucleates from the aqueous phase during depressurization. The combination of CO2 solubility decreasing, CO2 density decreasing, and concentration gradient driven mass transfer leads to the growth of CO2 bubbles (Figure 6A). The pore-scale observation on the depressurization of CO2(aq,sat) was obtained using the micromodel system, and the pore geometry of the micromodel sample is shown in Figure
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CO2 EXSOLUTION AND MINERAL PRECIPITATION DURING DEPRESSURIZATION During depressurization, CO2(aq) may exsolve from the supersaturated aqueous phase and dissolved carbonate minerals 2061
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Figure 7. Ostwald ripening of exsolved CO2(g) bubbles. (A) Schematic diagram of mechanism. (B) Shot image of micromodel sample: (1) after depressurization; then (2) after 4 h constant pressure period. Adapted from ref 19. Copyright 2017 Elsevier.
where σ represents the interfacial tension and R represents the interface radius of curvature. Smaller CO2 bubbles then have higher pressures than larger bubbles. Since the CO2 concentration in the aqueous phase is equal to the local equilibrium pressure at the CO 2 /aqueous phase interface, the CO 2 concentration near a smaller bubble is higher than the concentration near a larger bubble. This concentration difference creates a driving force for the CO2 mass transfer from the smaller bubble to the larger bubble.
6B.19,20 The pressure decreased from 9.85 to 3.95 MPa with depressurization rate 5.13 MPa/h at 40 °C, and the behavior of CO2 bubbles was recorded.19 The CO2 bubbles preferentially grow toward the larger pores instead of toward the throats or the finer pores due to the lower capillary entrance pressure (Figure 6C). Once an exsolved CO2 bubble occupies an entire pore body, the bubble begins to enter the throats for further growth. This observation is consistent with the results obtained in the corescale exsolution experiments using sandstone as the core sample in our lab.25 After the exsolution process at the depleted pressure, 4 and 2 MPa, MR images of local aqueous phase saturation distribution show that the CO2 phase nucleated and grew uniformly in the nucleation sites homogeneously distributed along the core (Figure 6D). NMR relaxation (T2 relaxation time) of hydrogen nuclei was assessed in the experiments. According to the theory of NMR, longer T2 relaxation time corresponds to larger surface volume ratio and thus larger pore. The H2O NMR signal intensity corresponding to the T2 relaxation time indicates that the exsolved CO2 phase preferentially occupies the larger pores and gradually invades the finer pores as the depleted pressure decreases (Figure 6-D).25 Both pore- and core-scale experimental results show the dispersed phase consisting of a large number of small CO2 bubbles is immobile during the depressurization. When the exsolved CO2 bubbles are well dispersed, the large interfacial area leads to a higher surface free energy, which is thermodynamically unstable. The highly dispersed CO2 bubbles will tend to merge without direct interface fusion. Bubble growth by a diffusive mass transfer mechanism, the Ostwald ripening process (Figure 7-A), was first captured in our pore-scale visualizations.19 As shown in the marked zone in Figure 7B, the smaller CO2 bubble shrank or even disappeared while the larger adjacent bubble swelled a little. The exsolved CO2 phase with different bubble sizes results in different CO2/aqueous phase interface curvatures. The local pressure in each dispersed CO2 bubble, PCO2, can be predicted by the Young−Laplace equation as
PCO2 = Paqu + 2σ /R
CO2 Mobility and Trapping after Exsolution
The forced imbibition was followed with depressurization induced exsolution to investigate the residual trapping and mobility of exsolved CO2(g) using core-scale experiments (Figure 8A).25 The residual trapping is usually created by applying a secondary imbibition following by continuous drainage. The highly interconnected nonwetting phase can be converted to isolated ganglia due to the occurrence of snap-off events, with the nonwetting phase then immobilized and trapped by capillary force.18,20 In general, for the fluid pair CO2 (nonwetting phase)/water (wetting phase) in sandstone for typical reservoir conditions, the residual trapping ratio (the ratio between the residual CO2 saturation and the initial CO2 saturation, SCO2,r/SCO2,i) is in the range 40−60%.46,47 However, the residual trapping ratio of the exsolved CO2 after the forced imbibition in our experiments was generally higher than 80% (Figure 8C). This high CO2 residual trapping ratio indicates the low mobility of exsolved CO2(g). We also found that the exsolved CO2(g) had low mobility even after repressurization and forced imbibition. Thus, the exsolved CO2 cannot be easily mobilized during the forced imbibition, which implies a certain degree of self-sealing during reservoir depressurization. Effect of the Initial State of the CO2 Phase
The CO2 inside the reservoir can initially exist in the aqueous phase as saturated CO2 (series C), a highly interconnected CO2 rich phase (series D), or the isolated CO2 phase ganglia (series E) (Figure 9). The pre-existing CO2 not only swells during depressurization but also influences the CO2(aq) concentration distribution and, consequently, the behavior of the nucleated and
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Figure 8. (A) Procedure and experimental results of (1) series A, Imbibition after exsolution, and (2) series B, repressurization after exsolution. (B) Residual trapping of the exsolved CO2 phase. (C) Effective aqueous phase permeability at the end of imbibition process. Adapted from ref 25. Copyright 2015 American Chemical Society.
Figure 9. Depressurization behavior of the cores with different initial states of CO2 phase. (a) Core-scale experimental results. (b) Pore-scale schematic diagram of CO2 depressurization process. Adapted from ref 45. Copyright 2017 American Chemical Society.
initial states.45 When the pre-existing state of the CO2 rich phase is the highly interconnected large ganglia, the expansion of the
grown CO 2 bubbles. Using core-scale experiments, we investigated CO2 depressurization behavior under these three 2063
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Accounts of Chemical Research CO2 has little effect on the saturation since the highly interconnected morphology of the CO2(g) ganglia provides an easier pathway to move and escape to the outer boundary of the core sample. The CO2 could displace the adjacent aqueous phase occupying the finer pores, which would then increase the CO2(g) saturation, but this is not likely because the bubbles need to overcome the higher capillary entrance pressure. When the CO2 rich phase initially exists as isolated small ganglia, the CO2(g) saturation will increase significantly due to expansion when the saturation is less than a critical value. The aqueous phase surrounding the isolated ganglia needs to first be displaced as the ganglia swell during depressurization, so that the CO2(g) can become interconnected and, thus, mobile. In summary, reservoir depressurization can convert the solubility trapped phase into a residually trapped phase and convert the residually trapped CO2 into mobile CO2.
observed on the exit surface of the upstream low permeability sandstone (Figure 10A). One explanation is that the sharp increase of pore space from the upstream disk to the core leads to a significant CO2 exsolution from the supersaturated solution and consequently causes calcium carbonate precipitation. During the experiment, the flow rate decreased continuously due to the gradual clogging of the upstream low permeability disk. This indicates that low permeability rocks are more sensitive to mineral precipitation. In actual GCS reservoirs, if the formation water is saturated with calcium carbonate, the secondary phase may precipitate and block the pores, thus reducing the permeability of the original cap layer during depressurization. This calcite precipitation could then self-seal any paths from the caprock to the surface, which would reduce the risk of pressure variations in GCS reservoirs.
Mineral Precipitation during Depressurization
CONCLUSIONS AND PROSPECTS In this Account, we have summarized our recent work on the behavior and transformation of the carbon components that would exist in a GCS reservoir using pore- and core-scale experiments and modeling. Experimental results show how mineral dissolution affects capillary pressure and relative permeability, which are important phenomena affecting the input parameters for reservoir flow modeling. When reservoir pressure decreases, there is increasing formation water flow resistance and low mobility of CO2 due to CO2 exsolution and carbonate precipitation. Depressurization therefore produces self-sealing effects that may reduce unfavorable CO2 migration even in the presence of sudden reservoir depressurization. CO2−water two-phase flow and chemical interaction between formation water and mineral are strongly coupled. The pore structure and wettability that dominate the multiphase flow in porous media, change when the minerals dissolve and precipitate. Considerable effort has been made to characterize the changes of pore structure and wettability. However, due to the extremely diverse and complex reservoir fluid components, mineral compositions, and pore geometries, further research is needed to develop a comprehensive understanding of CO2 behavior in natural subsurface reservoirs.
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Through a collaborative exchange program with B. Yardley at University of Leeds, the mineral precipitation behavior due to depressurization was investigated experimentally.48,49 Water was saturated with CO2 at 4 MPa, 25 °C, and subsequently this solution was equilibrated with an excess of calcite. The solution was then injected into an experimental section (1.5 in. in diameter) that consisted of two parts: a thin disk of Hopeman sandstone with a low permeability of 1−6 μD and a core sample of Lochaline sandstone (99.5% quartz) with a high permeability of 1.21 D. The disk was placed at the inlet of the core sample and built up a pressure drop of 3 MPa at a flow rate of 0.2 mL/min. After the aqueous phase had been injected for 1 L, precipitated calcium carbonate was found by using scanning electron microscope−secondary electron (SEM-SE) in both the disk and the core sample in various forms (Figure 10). However, the precipitated calcium carbonate did not significantly change porosity or permeability of the downstream high permeability core, due to the small amount of precipitation compared to the original pore volume and the possible escape of the precipitates from the core. A large number of calcium carbonate clusters were
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. ORCID
Ruina Xu: 0000-0001-8561-560X Peixue Jiang: 0000-0002-9777-8075 Notes
The authors declare no competing financial interest. Biographies Ruina Xu received her B.E. and Ph.D. from Tsinghua University of China. In 2010, she was promoted to associate professor in the Department of Thermal Engineering, Tsinghua University. Her research interests include the heat and mass transfer in porous media, supercritical fluid heat and mass transfer, and CO2 geological sequestration and utilization.
Figure 10. Calcium carbonate precipitation experiment diagram with SEM-SE images of precipitates in different parts of the assembly. (A) Carbonates present at the outlet of the Hopeman sandstone disc: (1) magnification 5000×; (2) magnification 30000×. The proliferation of these carbonate assemblages on quartz grains could be an indicator of fast and homogeneous carbonate nucleation during the experiment in this area. (B) Carbonates present (1) at the inlet, (2) in the middle, and (3,4) at the outlet of the Lochaline sandstone core. Adapted from ref 48. Copyright 2013 Tsinghua University.
Rong Li received his B.E. in Thermal Engineering from Huazhong University of Science & Technology, China, in 2012. He is currently a Ph.D. candidate at Tsinghua University. 2064
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Accounts of Chemical Research
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Jin Ma received her B.E. and M.E from Tsinghua University of China in 2011 and 2014, respectively. Di He received his B.E. in Thermal Power Engineering from Chongqing University of China in 2015. He is currently a Ph.D. candidate at Tsinghua University. Peixue Jiang received his B.E. from Tsinghua University, China, and Ph.D. from Moscow Power Engineering Institute. He has held positions as a Professor in the Department of Thermal Engineering, Tsinghua University, since 1993. His research interests include CO2 geological sequestration and utilization, heat and mass transfer in porous media, supercritical fluid heat and mass transfer, and advanced cooling technology for aircraft.
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ACKNOWLEDGMENTS This work was supported by the National Key Research and Development Plan of China (No. 2016YFB0600805), National Natural Science Foundation of China (No. 51536004), Science Fund for Creative Research Groups (No.51621062), NSFCEPSRC Collaborative UK-China Research Projects in Carbon Capture and Storage Technologies (EPSRC Grant EP/I010971/ 1, NSFC Grant No. 51061130537), University of Leeds, BRGM, and Tsinghua University. The authors thank Prof. B. Yardley and Dr. B. Lamy-Chappuis for their kind help at University of Leeds and for the numerous scientific discussions.
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DOI: 10.1021/acs.accounts.6b00651 Acc. Chem. Res. 2017, 50, 2056−2066
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DOI: 10.1021/acs.accounts.6b00651 Acc. Chem. Res. 2017, 50, 2056−2066
