CO2 In Aquifers Research Articles

Core and Pore Scale Characterization of Liujiagou Outcrop Sandstone, Ordos basin, China for CO2 Aquifer Storage

This paper describes various laboratory studies that have been performed on Liujiagou sandstone samples from the Ordos basin. The sample characterization includes multi-scale X-ray computed tomography (CT) scanning, and thin section petrographic analysis. Core scale and pore scale characterizations of the Liujiagou formation sandstone were obtained. Injection of liquid CO2 into a brine saturated Liujiagou sandstone core was performed until a steady state condition was observed within a CT scanner. The CO2 filled some of the pore space, moving quickly through the laminae and/or bedding planes of core that were open. Pore/grain scale analysis via thin section petrography classified the Liujiagou sandstone as an arkosic arenite with a quartz/feldspar/rock fragment ratio of 51/32/17 and a mean grain size of 0.35 mm. Primary pores are generally clean and account for 1% of the overall porosity, which was measured as 6% within the thin section analyzed. Understanding how these pore and core scale characteristics of Liujiagou sandstone affect fluid migration through this important Chinese resource will be instrumental in the planning and operation of future CCUS projects.

Reactive transport simulation study of geochemical CO2 trapping on the Tokyo Bay model – With focus on the behavior of dawsonite

A long-term (up to 10ka) geochemical change in saline aquifer CO2 storage was studied using the TOUGHREACT simulator, on a 2-dimensional, 2-layered model representing the underground geologic and hydrogeologic conditions of the Tokyo Bay area that is one of the areas of the largest CO2 emissions in the world. In the storage system characterized by low permeability of reservoir and cap rock, the dominant storage mechanism is found to be solubility trapping that includes the dissolution and dissociation of injected CO2 in the aqueous phase followed by geochemical reactions to dissolve minerals in the rocks. The CO2–water–rock interaction in the storage system (mainly in the reservoir) changes the properties of water in a mushroom-like CO2 plume, which eventually leads to convective mixing driven by gravitational instability. The geochemically evolved aqueous phase precipitates carbonates in the plume front due to a local rise in pH with mixing of unaffected reservoir water. The carbonate precipitation occurs extensively within the plume after the end of its enlargement, fixing injected CO2 in a long, geologic period.Dawsonite, a Na–Al carbonate, is initially formed throughout the plume from consumption of plagioclase in the reservoir rock, but is found to be a transient phase finally disappearing from most of the CO2-affected part of the system. The mineral is unstable relative to more common types of carbonates in the geochemical evolution of the CO2 storage system initially having formation water of relatively low salinity. The exception is the reservoir-cap rock boundary where CO2 saturation remains very high throughout the simulation period.

Geochemical modeling of CO2 sequestration in deep, saline, dolomitic-limestone aquifers: Critical evaluation of thermodynamic sub-models

Geochemical modeling is a common tool to estimate the potential for storing supercritical CO2 in deep saline aquifers, and to predict the effects thereof. Geochemical models necessarily rely on thermodynamic relationships or “sub-models” to estimate quantities such as chemical solubility, activity, and fugacity. In this paper, we compare three proposed models for the fugacity of supercritical CO2, four proposed models for the activity coefficient of dissolved (aqueous) CO2, and four proposed models for the solubility of CO2 in aquifer brine. We examine the conditions under which estimates from these different proposed thermodynamic sub-models agree or disagree. Also, we develop a geochemical model that predicts the effects of injecting CO2 into a deep, saline, dolomitic-limestone aquifer; specifically, we predict the change in brine pH, the mineral precipitation/dissolution, and the potential solubility trapping of injected CO2 in response to the CO2 injection. We test nine different versions of the model, utilizing different combinations of the thermodynamic sub-models listed above. This allows us to quantify how key geochemical predictions depend upon the selection of thermodynamic sub-models. We find that different combinations of thermodynamic sub-models yield similar estimates for equilibrium pH and for quantities of mineral precipitation/dissolution, but that agreement is worse when predicting the equilibrium CO2 concentration in brine and/or the solubility trapping of CO2. These results indicate that the predicted equilibrium pH and mineral precipitation/dissolution are not very sensitive to the underlying thermodynamic sub-models, whereas estimates for the CO2 concentration in brine and potential solubility trapping are. Overall, the geochemical predictions are least sensitive to the choice of CO2 activity coefficient sub-model, are moderately sensitive to the choice of CO2 solubility sub-model, and are most sensitive to the choice of CO2 fugacity coefficient sub-model.

The impact of geologic variability on capacity and cost estimates for storing CO2 in deep-saline aquifers

While numerous studies find that deep-saline sandstone aquifers in the United States could store many decades worth of the nation's current annual CO2 emissions, the likely cost of this storage (i.e. the cost of storage only and not capture and transport costs) has been harder to constrain. We use publicly available data of key reservoir properties to produce geo-referenced rasters of estimated storage capacity and cost for regions within 15 deep-saline sandstone aquifers in the United States. The rasters reveal the reservoir quality of these aquifers to be so variable that the cost estimates for storage span three orders of magnitude and average>$100/tonne CO2. However, when the cost and corresponding capacity estimates in the rasters are assembled into a marginal abatement cost curve (MACC), we find that ~75% of the estimated storage capacity could be available for<$2/tonne. Furthermore, ~80% of the total estimated storage capacity in the rasters is concentrated within just two of the aquifers—the Frio Formation along the Texas Gulf Coast, and the Mt. Simon Formation in the Michigan Basin, which together make up only ~20% of the areas analyzed. While our assessment is not comprehensive, the results suggest there should be an abundance of low-cost storage for CO2 in deep-saline aquifers, but a majority of this storage is likely to be concentrated within specific regions of a smaller number of these aquifers.

A stratigraphic model to account for complexity in aeolian dune and interdune successions

AbstractWet aeolian systems, in which the water table or its capillary fringe are in contact with the accumulation surface, such that moisture influences sedimentation, are well‐known from modern aeolian systems and several ancient preserved successions are recognized from outcrop. One common mechanism by which accumulation of wet aeolian system deposits occurs is via a progressive rise in the relative water‐table level that is coincident with ongoing dune and interdune migration, the angle of dune climb being determined by the ratio between the rate of relative water‐table rise and the rate of downwind migration of the bedforms. Accumulations of wet aeolian system deposits tend to be characterized by units of climbing dune strata separated by units of damp or wet interdune strata. For simple geometric configurations, where the size of the dune and interdune units, the rate of bedform migration and the rate of aggradation all remain constant over space and time, the resulting accumulation has a simple architecture characterized by sets of uniform thickness inclined at a constant angle. However, the dynamic nature of most aeolian dune systems means that such simple configurations are unlikely in nature. The complexity inherent in these systems is accounted for here by a numerical model in which key controlling parameters, including dune and interdune wavelength and spacing, migration rate and aggradation rate, are allowed to vary systematically both spatially (from a dune‐field centre to its margin) and temporally (in response to changes in sediment availability or water‐table level). The range of synthetic stratigraphic architectures generated by the model accounts for all the best‐known examples of aeolian dune and interdune stratigraphic configurations documented from the stratigraphic record. Modelling results have enabled the erection of a scheme for the classification of dune system type whereby the many elaborate stratal architectures known to exist in nature can effectively be accounted for by only four parameters that are allowed to vary over space and time: dune and interdune wavelength and spacing, rate of bedform migration and rate of accumulation. Results have applied implications, including the modelling of reservoir heterogeneity and the prediction of fluid flow pathways of hydrocarbons, water, CO2 and contaminants in subsurface reservoirs and aquifers, in which low permeability interdune units might act as baffles or barriers.

The regional pressure impact of CO2 storage: a showcase study from the North German Basin

A regional scale, showcase saline aquifer CO2 storage model from the North German Basin is presented, predicting the regional pressure impact of a small industrial scale CO2 storage operation on its surroundings. The intention of the model is to bridge the gap between generic and site-specific, studying the role of fluid flow boundary conditions and petrophysical parameters typically found in the North German Basin. The numerical simulation has been carried out using two different numerical simulators, whose results matched well. The most important system parameters proved to be the model’s hydrological boundary conditions, rock compressibility, and permeability. In open boundary aquifers, injection-induced overpressures dissipate back to hydrostatic level within a few years. If a geological flow barrier is present on at least one side of the aquifer, pressure dissipation is seriously retarded. In fully closed compartments, overpressures can never fully dissipate, but equilibrate to a compartment-wide remnant overpressure. At greater distances to the injection well, maximum fluid pressures are in the range of a few bar only, and reached several years to decades after the end of the actual injection period. This is important in terms of long-term safety and monitoring considerations. Regional pressure increase impacts the storage capacities of neighbouring sites within hydraulically connected units. It can be concluded that storage capacities may be seriously over- or underestimated when the focus is on a single individual storage site. It is thus necessary to assess the joint storage capacities and pressure limitations of potential sites within the same hydraulic unit.

Assessment of CO2 storage capacity in oil reservoirs associated with large lateral/underlying aquifers: Case studies from China

CO2 injection into oil and gas reservoirs associated with large aquifers takes advantages of lower geological leakage risk associated with oil and gas traps, and large storage capacity of their connected aquifers. The storage capacity in such combined reservoirs can be assessed by a material balance method which considers different trapping states of CO2 in oil reservoirs and aquifers. Case studies of five oil reservoirs selected from Shengli and Jiangsu oilfields in China are conducted and the results show that CO2 storage capacity can be greatly increased if the lateral and underlying aquifers are included. Oil and water displacement and CO2 dissolution in remaining oil are the main forms of CO2 trapping in oil reservoirs, while CO2 gas trapping and dissolution in saline water are the main mechanisms for CO2 storage in associated aquifers. CO2 injection into combined reservoirs can be a favorable option for the oil industry in the near future, and the potentials of CO2 EOR and storage deserve further detailed studies.

Multiwell injectivity for storage of CO2 in aquifers

Abstract Geological storage of CO2 in deep saline aquifers has been suggested as a potential methodology for reducing CO2 e missions over short to medium terms. A number of projects are in operation and a larger number are being designed. However, not all aquifers are equally suitable for CO2 storage. Virtually all publications that present the criteria for selection of suitable sites for geological storage of CO2 in aquifers, consider injectivity to be among the top three criteria, with capacity and containment being the other two. Among parameters that affect injectivity, permeability can vary by the largest degree. Unfortunately, selection of storage sites with sufficient permeability that would enable injection of the desired volumes, using only one injection well–such as that achieved in Sleipner–is not always possible. When this is not possible, injectivity needs to be improved for example by increasing the contact area with the formation (e.g. through application of hydraulic fracturing or horizontal wells) and/or employing more than one injector. Recent studies indicate that multiwell injectivity does not increase linearly with the number of injectors. Instead, progressively more number of wells is required to achieve an equal increment in injection rate. It is well known, that because of the small compressibility of the water, it takes a short time for the pressure pulse from the different injectors to cause significant interference. We use this observation and suggest a well pattern that would minimize such interference effects in an open and homogeneous aquifer. Next, we develop an analytical solution, for the injectivity of multiwell systems as a function of (i) number of wells, (ii) distance between wells, and (iii) injectivity of one wel.. The analytical solution obtained for single-phase flow is applied to cases of CO2 injection in aquifers. Numerical experimentation over a wide range of parameters demonstrates the applicability of the analytical solution for two-phase flow problems. This relation is developed for homogeneous aquifers; suggesting that such a relationship may be used for scoping and screening studies early on when data us scarce, and the effect of the number of wells and/or their distance on overall injectivity is being studied. Furthermore, such a relationship allows examining the economic balance between increasing the number of wells or the distance among wells.

Carbon dioxide microbubble injection–Enhanced dissolution in geological sequestration

Abstract CO2 microbubble injection is a novel technology for geological sequestration. Currently most of CO2 geological sequestration projects are focused on large-scale emission sources, while there is a practical need to inject CO2 from small- to middle- scale emission sources. CO2 microbubble injection is available for storing CO2 in aquifers with non-anticline (monotonic) structure in a low-cost concept. In this study CO2 microbubbles were generated by injecting CO2 through micro porous filters and the behaviors of CO2 microbubbles were recorded by a high speed video camera system. Our results suggest that more microbubbles generated by filters with smaller pore and CO2 dissolution enhanced by CO2 microbubbles. CO2 microbubble injection provides an option of considering monoclinic structures exist widely in Japan, as useful sites. We are working on quantifying the CO2 microbubbles size and the volume of dissolved CO2 in saline aquifers.

SENSITIVITY STUDY ON STORAGE OF CO2 IN SALINE AQUIFER FORMATION WITH FRACTURE USING REACTIVE TRANSPORT RESERVOIR SIMULATOR RCB

Storage of CO2 in aquifers is the only full scale proven method for storage of CO2. The initial structure of a given reservoir changes dynamically with injection of CO2 due to mineral reactions, changes in pore, and possible consequences on geomechanical stability. We present in this paper a new reactive transport simulator with implicit geomechanical analysis for aquifer storage of CO2, code RetrasoCodeBright (RCB). The original software package has been extended to a capacity of analyzing dynamically coupled flow, geochemical reactions and geomechanical reservoir stability as consequence of CO2 injection in a given formation. A 2D hydro-geochemical-geomechanical problem with a fracture is set up to illustrate the modified RCB code. A limited sensitivity study on this model has been used to show the impact of key variables on important geochemical and geomechanical features. Some future extensions of the code are also briefly discussed. Work on some of these extensions is already in progress

Pressure Build-up and Decay in Acid Gas Injection Operations in Reefs in the Zama Field, Canada, and Implications for CO2Storage

The objective of this paper is to examinereasons for pressure rise in the Zama X2X pool in northwestern Alberta, Canada, that was used foracid gas disposal, and whether subsequent pressure decay was a result of pressure dissipation into a larger aquifer. The Zama X2X pool, approximately 1 km2 in size, is connected to four other nearby poolsthrough a common underlying aquifer. Pressure analysis for all the pools indicates that they are in goodhydraulic communication. Initial pressure in the Zama X2X pool was approximately 15 MPa. Pressuredeclined first during oil production, stabilizing at around 10 MPa in the early 1970s, after which started toincrease such that it reached 26 MPa in 1986. Subsequently, pressure declined reaching 22 MPa by 1995just prior to starting injection of acid gas (80% CO2 and 20% H2 S). The operator injected acid gas at lowerrates and wellhead pressures than those licensed by the regulatory agency. Despite significant production ofwater and hydrocarbons, the pressure in the Zama X2X pool continued to be higher than the initial reservoirpressure by more than 5 MPa, such that disposal operations were suspended in late 1998. Oil productioncontinued all this time until 2002. Numerical simulations using CMG-IMEXTM and corresponding sensitivity studies reported in this papershow that disposal of more than 1 million m3 of water between 1970 and 1988 and again in 1992-1993 inthe adjacent Zama YY pool, which is in good hydrodynamic communication with the Zama X2X poolthrough the aquifer below the oil column, is the main reason for the high pressures observed in the ZamaX2X pool. Sensitivity studies indicate that pressure decay in the X2X pool was due to fluid production.The study indicates that while pressure rise has been caused by hydraulic communication between theX2X and YY pools through the common aquifer, the aquifer was not of large volume to allow dissipationof the pressure. In addition to the case study, the implications of pressure communication to geological storage of CO2 in aquifers are briefly discussed.

Have We Overestimated Saline Aquifer CO2Storage Capacities?

During future, large scale CO2 geological storage in saline aquifers, fluid pressure is expected to rise as a consequence of CO2 injection, but the pressure build up will have to stay below specified values to ensure a safe and long term containment of the CO2 in the storage site. The pressure build up is the result of two different effects. The first effect is a local overpressure around the injectors, which is due to the high CO2 velocities around the injectors, and which can be mitigated by adding CO2 injectors. The second effect is a regional scale pressure build up that will take place if the storage aquifer is closed or if the formation water that flows away from the pressurised area is not large enough to compensate volumetrically the CO2 injection. This second effect cannot be mitigated by adding additional injectors. In the first section of this paper, we review some major global and regional assessments of CO2 storage capacities in deep saline aquifers, in term of mass and storage efficiency. These storage capacities are primarily based on a volumetric approach: storage capacity is the volumetric sum of the CO2 that can be stored through various trapping mechanisms. We then discuss in Section 2 storage efficiencies derived from a pressure build up approach, as stated in the CO2STORE final report (Chadwick A. et al. (eds) (2008) Best Practice for the Storage of CO2 in Saline Aquifers, Observations and Guidelines from the SACS and CO2STORE Projects, Keyworth, Nottingham, BGS Occasional Publication No. 14) and detailed by Van der Meer and Egberts (van der Meer L.G.H., Egberts P.J.P. (2008) A General Method for Calculating Subsurface CO2 Storage Capacity, OTC Paper 19309, presented at the OTC Conference held in Houston, Texas, USA, 5-8 May). A quantitative range of such storage efficiency is presented, based on a review of orders of magnitudes of pore and water compressibilities and allowable pressure increase. To illustrate the relevance of this approach, it is applied to the Utsira aquifer in the North Sea. In Sections 3 and 4, we discuss possible effects that may lead to higher or lower CO2 storage efficiencies. Water production appears to be an attractive strategy in order to address regional scale pressure build up and, consequently, to increase the storage capacity.Following these quantitative applications, we recommend to evaluate the CO2 storage capacities of an aquifer, during a screening study for ranking purposes, using a pressure and compressibility formula rather than a volumetric approach, in order to avoid large overestimation of the aquifer storage capacity. Further studies are naturally required to validate the storage capacities at a qualification stage.

Impact of porous medium desiccation during anhydrous CO2 injection in deep saline aquifers: Up scaling from experimental results at laboratory scale to near-well region

Injection of CO2 in geological reservoirs or deep aquifers is nowadays studied to regulate the global warming by limiting the amount of greenhouse gases emitted by human activity into the atmosphere. CO2 is captured from exhaust gas in power plants or industrial units and then stored in underground geological reservoirs. The experience available in the oil industry concerning CO2 injection clearly shows that injectivity problems can occur due to several mechanisms like mineral dissolution but also physical alteration due to complete water desaturation of near wellbore through drying. This study presents experimental evaluations of drying of brine in sandstone samples and numerical modelling of the saturation profile evolution with two phase flow model integrating thermal effects. An up scaling/extrapolation of experimental results at laboratory scale to near-well zone is proposed highlighting the key role of injection flow rate and capillary properties on the desiccation mechanisms.

Monitoring CO2 migration in an injection well: Evidence from MovECBM

Carbon dioxide (CO2) geological storage relies on safe, long-term injection of large quantities of CO2 in underground porous rocks. Wells, whether they are the conduit of the pumped fluid or are exposed to CO2 in the storage reservoir (observation and old wells) are man-made disturbances to the geological storage complex, and are thus viewed by some as a possible risk factor to the containment of the injected CO 2. Wells are composite structures, with an inner steel pipe separated from the borehole rock wall by a thin cement sheath (∼2 cm) that prevents vertical fluid migration. Both carbon steel and cement react in the presence of CO2, although evidence from production of CO2-rich fluids in the oil and gas industry and from lab experiments suggests that competent, defect-free cement offers an effective barrier to CO2 migration and leaks. However, reactivity of cement and steel may result in CO2 migration pathways degrading over time, thus in the leakage risk increasing during the life of the storage project. The issue then becomes how to best integrate preventive verification of zonal isolation/well integrity in the storage site monitoring plan. An analysis of the order of magnitude of possible CO2 leaks, and of their path to potable aquifers or the atmosphere, is also necessary to optimize the assurance (mitigation) monitoring of the storage site. Evidence gathered during the MovECBM project indicates that migration of small quantities of CO2 happened during injection in a coal seam in Southwest Poland. The evidence, gathered from casing and cement logging as well as soil gas monitoring over a 3-year period, was coupled with laboratory testing and extensive modeling of the chemo-mechanical behavior of cement and steel to determine if CO2 migration might have been responsible of the observed behavior. The three lines of evidence were: the detection of very small CO2 fluxes, coupled with less controversial helium concentration in soil; the occurrence of a thin pathway at the interface between cement and casing; and the change in mechanical properties of cement, suggestive of partial carbonation. Whereas the observations suggest that limited CO2 migration might have happened in the well, they are by no means proof that the migration did happen. Nonetheless, the integration of measurement and modeling yields important lessons for wellbore monitoring. First, it puts a probable ceiling on the order of magnitude of expected leaks from reasonably well-cemented wells at around 100 metric tons per year (less than 0.05% of the injected mass in a well like Sleipner or In Salah). It also suggests that cement may be a very effective leak detector: exposure to CO2 modifies its mechanical properties, which in turn can be detected using cement evaluation logs. Finally, coupling with dispersion modeling suggests the precision and accuracy required from soil gas and atmospheric monitoring, as well as the placement of sampling points; it also suggest that hysteresis, due to the accumulation in CO2 in surface aquifers and to the time required for it to be transported to the survey points, may delay initial detection; the same hysteresis may at the same time prolong the occurrence of CO2 shows long after the leak has stopped. © 2010 Elsevier Ltd. © 2011 Published by Elsevier Ltd.

ＣＯ２海底下ハイドレート貯留を模擬した砂層中ハイドレート生成の室内実験とその数値シミュレーション

CO2 capture and storage (CCS) is one of the most effective countermeasures against the global warming. Although CO2 aquifer storage is considered a main stream as CCS technology, there is a possibility that the capacity of the aquifer storage is limited and may not sufficient to meet the target reduction of CO2 emission. Therefore, it is good to have other CCS options. In this study, we focus on CO2 storage in the form of gas hydrate. In this method, CO2 is injected into the sub-seabed sand sediments at the condition of low temperature and high pressure, under which CO2 hydrate can stably form. A large amount of CO2 is sequestered as hydrate in the sediments by the reaction with pore water. However, hydrate formation has a great risk to reduce permeability and this may lead to the blockage of gas flow. In order to ensure large sequestration space, it is important that gas front expands over a wide area with avoiding such large permeability reduction. In this study, at first, we conducted experiments, in which CO2 was injected into sand sediment and CO2 hydrate formed in the sediment, to understand the blockage phenomena. Next, based on the experiments, we modelled the gas-water two-phase flow with hydrate formation in the sand sediment and developed a one-dimensional numerical simulator. Finally, we simulated the two-phase flow under the experimental conditions and revealed the blockage mechanism due to hydrate formation.

二酸化炭素地中貯留実験によって生じた地下温度の上昇

地下浅部の帯水層を対象としたCO2圧入実験を実施して, CO2ガスの圧入に伴う地下熱環境の変化を把握した. ガス注入井に認められた一時的な地下温度の低下を除き, CO2ガス圧入による帯水層内の温度上昇が認められた. 地下温度の上昇は, CO2ガスを圧入した帯水層の上面付近で最も大きかった. このことは, 圧入したCO2ガスが帯水層上面に沿って広がったことを示唆している. また, 地下水水質の時系列変化から, CO2ガスの溶解に伴うpHの低下と酸化還元電位の上昇が認められており, 帯水層内の鉱物の酸化に伴う発熱が地下温度上昇の要因となった可能性が考えられた. 地下温度の上昇は時間の経過とともに縮小したが, 圧入終了後35日を経過しても確認された. 本実験により, 深度約50mという地下浅部であっても, CO2ガスの圧入に伴う地下熱環境の変化が長期にわたって継続することが示唆された.

Parallel Numerical Reservoir Simulations of Nonisothermal Compositional Flow and Chemistry

Summary This paper describes an efficient numerical scheme for nonisothermal compositional flow coupled to chemistry. An iterative implicit-pressure/explicit-composition (IMPEC) method is applied to solve the flow problem using a volume-balance-convergence criterion. A backward-Euler mixed finite-element method (FEM) with lowest-order RT0 elements is applied to solve the pressure equation, and a component local mass-preserving explicit scheme is used to update concentrations. Chemical reactions are solved using explicit Runge-Kutta (RK) ordinary-differential-equation (ODE) integration schemes. A higher-order Godunov method and a backward-Euler mixed FEM are applied for thermal advection and conduction, respectively, in a time-split scheme. One of the major applications of the method is in the modeling of field-scale carbon dioxide (CO2) sequestration as an enhanced-oil-recovery (EOR) process or for containment in deep saline aquifers where chemical reactions and temperature variations may have an effect on the flow and transport of CO2. Leakage patterns when CO2 is injected near leaky abandoned wells, the displacement of methane from depleted gas reservoirs, and accurate modeling of geochemical reactions involving injected CO2 are other applications of interest. Results of a benchmark problem in multiphase flow with several hydrocarbon components in formations with highly heterogeneous permeability on very fine grids, as well as a large-scale parallel implementation of modeling CO2 sequestration, are presented to justify the practical use of the model. A parallel efficiency of approximately 80% was observed on up to 512 cores in the benchmark study. Results from a problem simulating injection of CO2 in deep aquifers including nonisothermal and chemical effects are also presented. The results indicate a good agreement of the solutions with published data, where available. Numerical modeling and simulation of CO2 sequestration plays a major role in future site selections and in designing storage facilities for effective CO2 containment. The main contribution of this paper lies in providing a parallel and efficient method of simulating challenging compositional flow problems, such as in the study of CO2 sequestration, as well as flow coupled to thermal and geochemical effects.

Aquatic Macroinvertebrates of a Spring-Fed Ecosystem in Hays County, Texas, USA

The San Marcos River is fed by the second largest spring system in the state of Texas and is home to multiple endemic and federally listed endangered and threatened plant and animal species. Due to a dam originally created to facilitate a gristmill in 1849, the spring orifices are inundated by up to 12 m of water. The area upstream of the dam is referred to as Spring Lake. Directly below the dam, the river is clear and rapidly moving, ranging from about 5 m to 15 m wide, flowing over a predominantly firm gravel bottom with many shallow riffles alternating with deep pools (Lemke, 1989). The historic mean spring flow for this system is 4.5 m3/sec (Ogden et al., 1986). The headwater stretch of the San Marcos River (the upper 7.2 km) stays at a relatively constant temperature at around 22°C (Hannan and Dorris, 1970). The conductivity ranges from ~600 – 700 µS/cm for the majority of this upper portion of the river, but then increases to a range of ~625 - 850 µS/cm downstream of the San Marcos Wastewater Treat ment Plant (Groeger et al., 1997), which is located about 5 km downstream of the springs. The pH in the artesian well located near the headwaters on Texas State University property and Spring Lake is lower (range = 6.3 – 7.4) than sites down stream (range = 6.6 – 7.8), which indicates that aquifer CO 2 concentrations are higher than those in equilibrium with the atmosphere (Groeger et al., 1997). Human-induced impacts to the Edwards Aquifer which feeds the springs (e.g. water pumping) as well as to the river itself (e.g. urbanization) may have negative effects on the aquatic macroinvertebrate community in the San Marcos River. There have been few peer-reviewed manuscripts on the aquatic macroinvertebrate community of the San Marcos River (Edwards and Arnold, 1961; Bowles et al., 2007). Given the described concerns and the hydrologic consistency of the upper San Marcos River (Fries and Bowles, 2002) there is a need for detailed information on macroinvertebrate community composition in the river. The purpose of this study is to create a baseline species list to evaluate future changes in San Marcos River macroinvertebrate community composition. We collected aquatic macroinvertebrates from multiple locations throughout Spring Lake and the San Marcos River in a wide variety of microhabitats in an attempt to compile a macroinvertebrate taxa list that was as complete as currently possible (Fig. 1). We set 0.25 m2 quadrats in 188 locations along the river bottom and 147 locations within the lake. We placed a 0.5 m x 0.5 m modified dip net (500-µm mesh) downstream of each quadrat. We agitated the substrate inside

Creep of simulated reservoir sands and coupled chemical‐mechanical effects of CO2 injection

Geological storage of CO2 in clastic reservoirs and aquifers is expected to have a variety of coupled chemical‐mechanical effects. To investigate the effects of CO2 injection on creep phenomena, we performed uniaxial compaction experiments on granular aggregates of quartz and feldspar under both wet and dry control conditions. The experiments were performed in constant stress mode. Grain size, temperature, CO2 partial pressure, and effective stress were varied in order to determine their individual effect. Pore fluid pH was varied by the injection of CO2 and by addition of acidic and alkaline additives. Pore fluid salinity was increased by the addition of NaCl. Wet samples showed instantaneous compaction upon load application, followed by time‐dependent creep. From the mechanical data and microstructures, the main compaction mechanism was inferred to be chemically enhanced microcracking in both quartz and feldspar, with subcritical crack growth, i.e., stress corrosion cracking, controlling deformation in the creep stage. The injection of CO2 and the concomitant acidification of the pore fluid inhibited microcracking in both the quartz and feldspar samples in line with known effects of pH on stress corrosion cracking. We infer that the injection of CO2 into quartz‐ and plagioclase‐bearing sandstones will inhibit grain scale microcracking process and that related geomechanical effects, such as reservoir compaction and surface subsidence, will be negligible compared with the poroelastic response.

Analytical and Numerical Modeling of CO2 Sequestration in Deep Saline Aquifers

The analytical and numerical modeling of CO2 sequestration in deep saline aquifers having different rock and fluid properties was studied under diffusion and convection mechanisms. In a diffusion dominated system, an aquifer with 100 m thickness was saturated with CO2 after 10,000,000 years. It was much earlier in a convective dominant system. In the diffusion process, the dissolution of CO2 in aquifer increased with porosity increase; however, in a convection dominant process dissolution of CO2 in aquifer decreased with porosity increase. The increase in permeability accelerated the dissolution of CO2 in aquifer significantly, which was due to increasing velocity. The dissolution process in the aquifer was realized faster for the aquifers with lower dispersivity. The results of convective dominant mechanism in aquifers with 1 md and 10 md permeability values were close to that of the diffusion dominated system. For the aquifer having permeability higher than 10 md, the convection mechanism began to dominate gradually and it became a fully convection dominated system for 50 md and higher permeability values. These results were also verified with calculated Rayleigh numbers.