Evaluating the impact of caprock and reservoir properties on potential risk of CO2 leakage after injection

Numerical models are essential tools in fully understanding the fate of injected CO₂ for commercial-scale sequestration projects and should be included in the life cycle of a project. Common practice involves modeling the behavior of CO₂ during and after injection using site-specific reservoir and caprock properties. Little has been done to systematically evaluate and compare the effects of a broad but realistic range of reservoir and caprock properties on potential CO₂ leakage through caprocks. This effort requires sampling the physically measurable range of caprock and reservoir properties, and performing numerical simulations of CO₂ migration and leakage. In this study, factors affecting CO₂ leakage through intact caprocks are identified. Their physical ranges are determined from the literature from various field sites. A quasi-Monte Carlo sampling approach is used such that the full range of caprock and reservoir properties can be evaluated without bias and redundant simulations. For each set of sampled properties, the migration of injected CO₂ is simulated for up to 200 years using the water–salt–CO₂ operational mode of the STOMP simulator. Preliminary results show that critical factors determining CO₂ leakage rate through caprocks are, in decreasing order of significance, the caprock thickness, caprock permeability, reservoir permeability, caprock porosity, and reservoir porosity. This study provides a function for prediction of potential CO₂ leakage risk due to permeation of intact caprock and identifies a range of acceptable seal thicknesses and permeability for sequestration projects. The study includes an evaluation of the dependence of CO₂ injectivity on reservoir properties.     

Evolution of sealing efficiency for CO2 geological storage due to mineral alteration within a hydrogeologically heterogeneous caprock

In CO₂ geological storage (CGS) context, the evolution of the caprock sealing capacity has received increasing attention, particularly on a geological time span (thousands of years). At this time scale, geochemical reactions may enhance or weaken the caprock quality. It is widely recognized that, for the reservoir, geological heterogeneities affect the concentration and spatial distribution of CO₂, and then affect the extent of gas–water–rock interactions, which in turn alters the hydrogeological properties of the reservoir. However, much less attention of these effects has been paid to the caprock. In this study, we presented and applied a novel approach to evaluate the effects of permeability and porosity heterogeneities on the alteration of minerals, the associated evolution of the caprock sealing efficiency and the containment of supercritical CO₂ (scCO₂) within the caprock. Even though this is a generic study, several conditions and parameters such as pressure, permeability, and mineral composition, were extracted from a caprock layer of the Shiqianfeng Formation in the Ordos Basin demonstration site in China. For the sake of simplification, a 2-dimensional model was designed to represent the caprock domain. We firstly generated an appropriate heterogeneous random field of permeability with the average permeability taken from the uppermost mudstone layer of the Shiqianfeng Formation, and then the heterogeneity in porosity was incorporated using a joint normal distribution method based on the available data. Homogeneous mineral compositions of the reservoir and caprock were used in all simulations. Simulations of three cases were performed, including a homogeneous case, a case with only permeability heterogeneity and a case with both permeability and porosity heterogeneities. The results demonstrate dramatic influences of permeability and porosity heterogeneities on the migration of scCO₂ within the caprock, the alteration of minerals, and therefore the evolution of the caprock sealing quality. Specific to the data used in this study, hydrogeological heterogeneities facilitated the overall penetration of scCO₂ within the caprock and promoted the alteration of minerals, thereby weakening the caprock sealing efficiency over the simulation time.     

Role of Geomechanics in Assessing the Feasibility of CO2 Sequestration in Depleted Hydrocarbon Sandstone Reservoirs

Carbon dioxide (CO₂) sequestration in depleted sandstone hydrocarbon reservoirs could be complicated by a number of geomechanical problems associated with well drilling, completions, and CO₂ injection. The initial production of hydrocarbons (gas or oil) and the resulting pressure depletion as well as associated reduction in horizontal stresses (e.g., fracture gradient) narrow the operational drilling mud weight window, which could exacerbate wellbore instabilities while infill drilling. Well completions (casing, liners, etc.) may experience solids flowback to the injector wells when injection is interrupted due to CO₂ supply or during required system maintenance. CO₂ injection alters the pressure and temperature in the near wellbore region, which could cause fault reactivation or thermal fracturing. In addition, the injection pressure may exceed the maximum sustainable storage pressure, and cause fracturing and fault reactivation within the reservoirs or bounding formations. A systematic approach has been developed for geomechanical assessments for CO₂ storage in depleted reservoirs. The approach requires a robust field geomechanical model with its components derived from drilling and production data as well as from wireline logs of historical wells. This approach is described in detail in this paper together with a recent study on a depleted gas field in the North Sea considered for CO₂ sequestration. The particular case study shows that there is a limitation on maximum allowable well inclinations, 45° if aligning with the maximum horizontal stress direction and 65° if aligning with the minimum horizontal stress direction, beyond which wellbore failure would become critical while drilling. Evaluation of sanding risks indicates no sand control installations would be needed for injector wells. Fracturing and faulting assessments confirm that the fracturing pressure of caprock is significantly higher than the planned CO₂ injection and storage pressures for an ideal case, in which the total field horizontal stresses increase with the reservoir re-pressurization in a manner opposite to their reduction with the reservoir depletion. However, as the most pessimistic case of assuming the total horizontal stresses staying the same over the CO₂ injection, faulting could be reactivated on a fault with the least favorable geometry once the reservoir pressure reaches approximately 7.7 MPa. In addition, the initial CO₂ injection could lead to a high risk that a fault with a cohesion of less than 5.1 MPa could be activated due to the significant effect of reduced temperature on the field stresses around the injection site.     

Development of a long-term wellbore sealing concept based on numerical simulations and in situ-testing in the Altmark natural gas field

This paper presents an innovative well abandonment concept developed for the long-term containment of CO₂ in depleted Rotliegend gas reservoirs. The new concept aims at amending the conventional standard well abandonment procedure, taking advantage of the natural creeping ability of the thick, homogeneous Zechstein rock salt formation located around 3,000?m in depth (Altmark area) and consists of four main sealing units: (1) a standard sealing element with cement from the reservoir to the impermeable caprock, (2) a salt plug created in the formerly reamed section of casing within the plastic Zechstein (Upper Permian) rock salt formation, (3) two bridge plugs at the bottom and top of the salt plug and (4) a standard sealing element with cement from the top bridge plug until the ground surface. This site-specific study mainly lays emphasis on the development and field testing of the naturally created salt plug, as a key component of the long-term wellbore sealing concept. Comprehensive numerical simulations conducted prior to and during the field test in 2010 and 2011 successfully predicted the evolution of convergence using downhole measurement data. Preliminary results comprise (1) proven convergence of the rock salt formation, (2) a successful coring and (3) restored integrity of Zechstein salt formation, as proven by the formation integrity test. Based on these results, the new long-term sealing concept has been successfully tested at the Altmark natural gas field and successful application of the concept on other sites with similar geological conditions is foreseen to be likely.     

Experimental investigation into the sealing capability of naturally fractured shale caprocks to supercritical carbon dioxide flow

Geological storage of CO₂ is considered a solution for reducing the excess CO₂ released into the atmosphere. Low permeability caprocks physically trap CO₂ injected into underlying porous reservoirs. Injection leads to increasing pore pressure and reduced effective stress, increasing the likelihood of exceeding the capillary entry pressure of the caprocks and of caprock fracturing. Assessing on how the different phases of CO₂ flow through caprock matrix and fractures is important for assessing CO₂ storage security. Fractures are considered to represent preferential flow paths in the caprock for the escape of CO₂. Here we present a new experimental rig which allows 38 mm diameter fractured caprock samples recovered from depths of up to 4 km to be exposed to supercritical CO₂ (scCO₂) under in situ conditions of pressure, temperature and geochemistry. In contrast to expectations, the results indicate that scCO₂ will not flow through tight natural caprock fractures, even with a differential pressure across the fractured sample in excess of 51 MPa. However, below the critical point where CO₂ enters its gas phase, the CO₂ flows readily through the caprock fractures. This indicates the possibility of a critical threshold of fracture aperture size which controls CO₂ flow along the fracture.     

Seal integrity and feasibility of CO<Subscript>2</Subscript> sequestration in the Teapot Dome EOR pilot: geomechanical site characterization

This paper reports a preliminary investigation of CO₂ sequestration and seal integrity at Teapot Dome oil field, Wyoming, USA, with the objective of predicting the potential risk of CO₂ leakage along reservoir-bounding faults. CO₂ injection into reservoirs creates anomalously high pore pressure at the top of the reservoir that could potentially hydraulically fracture the caprock or trigger slip on reservoir-bounding faults. The Tensleep Formation, a Pennsylvanian age eolian sandstone is evaluated as the target horizon for a pilot CO₂ EOR-carbon storage experiment, in a three-way closure trap against a bounding fault, termed the S1 fault. A preliminary geomechanical model of the Tensleep Formation has been developed to evaluate the potential for CO₂ injection inducing slip on the S1 fault and thus threatening seal integrity. Uncertainties in the stress tensor and fault geometry have been incorporated into the analysis using Monte Carlo simulation. The authors find that even the most pessimistic risk scenario would require ∼10 MPa of excess pressure to cause the S1 fault to reactivate and provide a potential leakage pathway. This would correspond to a CO₂ column height of ∼1,500 m, whereas the structural closure of the Tensleep Formation in the pilot injection area does not exceed 100 m. It is therefore apparent that CO₂ injection is not likely to compromise the S1 fault stability. Better constraint of the least principal stress is needed to establish a more reliable estimate of the maximum reservoir pressure required to hydrofracture the caprock.     

Review: The potential impact of underground geological storage of carbon dioxide in deep saline aquifers on shallow groundwater resources

Underground geological storage of CO₂ in deep saline aquifers is considered for reducing greenhouse gases emissions into the atmosphere. However, some issues were raised with regard to the potential hazards to shallow groundwater resources from CO₂ leakage, brine displacement and pressure build-up. An overview is provided of the current scientific knowledge pertaining to the potential impact on shallow groundwater resources of geological storage of CO₂ in deep saline aquifers, identifying knowledge gaps for which original research opportunities are proposed. Two main impacts are defined and discussed therein: the near-field impact due to the upward vertical migration of free-phase CO₂ to surficial aquifers, and the far-field impact caused by large-scale displacement of formation waters by the injected CO₂. For the near-field, it is found that numerical studies predict possible mobilization of trace elements but concentrations are rarely above the maximum limit for potable water. For the far-field, numerical studies predict only minor impacts except for some specific geological conditions such as high caprock permeability. Despite important knowledge gaps, the possible environmental impacts of geological storage of CO₂ in deep saline aquifers on shallow groundwater resources appears to be low, but much more work is required to evaluate site specific impacts.     

A pressure-monitoring method to warn CO2 leakage in geological storage sites

This paper proposes a pressure-monitoring method to warn any possible CO₂ leakage by monitoring pressure change at the upper layer of storage reservoirs within injection wells. The monitoring method is tested with two problems under various scenarios. With a current pressure detection limit, the proposed pressure-monitoring technique can be widely applicable wherever a permeable upper formation exists above the CO₂ storage reservoir and is effective even in offshore storage sites wherever conventional monitoring methods for onshore sites cannot be applied. Meanwhile, the method is limited to apply during injection and is subject to any possible pressure dampening.     

Chemical effects of sulfur dioxide co-injection with carbon dioxide on the reservoir and caprock mineralogy and permeability in depleted gas fields

The most suitable candidates for subsurface storage of CO₂ are depleted gas fields. Their ability to retain CO₂ can however be influenced by the effect which impurities in the CO₂ stream (e.g. H₂S and SO₂) have on the mineralogy of reservoir and seal. In order to investigate the effects of SO₂ we carried out laboratory experiments on reservoir and cap rock core samples from gas fields in the northeast of the Netherlands. The rock samples were contained in reactor vessels for 30 days in contact with CO₂ and 100 ppm SO₂ under in-situ conditions (300 bar, 100 °C). The vessels also contained brine with the same composition as in the actual reservoir. Furthermore equilibrium modeling was carried out using PHREEQC software in order to model the experiments on caprock samples.After the experiments the permeability of the reservoir samples had increased by a factor of 1.2–2.2 as a result of dissolution of primary reservoir minerals. Analysis of the associated brine samples before and after the experiments showed that concentrations of K, Si and Al had increased, indicative of silicate mineral dissolution.In the caprock samples, composed of carbonate and anhydrite minerals, permeability changed by a factor of 0.79–23. The increase in permeability is proportional to the amount of carbonate in the caprock. With higher carbonate content in comparison with anhydrite the permeability increase is higher due to the additional carbonate dissolution. This dependency of permeability variations was verified by the modeling study. Hence, caprock with a higher anhydrite content in comparison with carbonate minerals has a lower risk of leakage after co-injection of 100 ppmv SO₂ with CO₂.     

Experimental and numerical investigations on CO2 injection and enhanced gas recovery effects in Altmark gas field (Central Germany)

The feasibility of CO₂ storage and enhanced gas recovery (EGR) effects in the mature Altmark natural gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO₂ as well as reservoir simulation studies to evaluate the CO₂ wellbore injectivity and displacement efficiency of the residual gas by the injected CO₂. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO₂ has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO₂ injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO₂ gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO₂ volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO₂ will be maximized. The migration/extension of CO₂ varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO₂ extension and pressure propagation suggested no breakthrough of CO₂ at the prospective production well during the 3-year injection period studied.     

Thermo-hydro-mechanical modeling of carbon dioxide injection for enhanced gas-recovery (CO2-EGR): a benchmarking study for code comparison

The objective of this paper was to investigate the THM-coupled responses of the storage formation and caprock, induced by gas production, CO₂-EGR (enhanced gas recovery), and CO₂-storage. A generic 3D planer model (20,000?×?3,000?×?100?m, consisting of 1,200?m overburden, 100?m caprock, 200?m gas reservoir, and 1,500?m base rock) is adopted for the simulation process using the integrated code TOUGH2/EOS7C-FLAC3D and the multi-purpose simulator OpenGeoSys. Both simulators agree that the CO₂-EGR phase under a balanced injection rate (31,500?tons/year) will cause almost no change in the reservoir pressure. The gas recovery rate increases 1.4?% in the 5-year CO₂-EGR phase, and a better EGR effect could be achieved by increasing the distance between injection and production wells (e.g., 5.83?% for 5?km distance, instead of 1.2?km in this study). Under the considered conditions there is no evidence of plastic deformation and both reservoir and caprock behave elastically at all operation stages. The stress path could be predicted analytically and the results show that the isotropic and extensional stress regime will switch to the compressional stress regime, when the pore pressure rises to a specific level. Both simulators agree regarding modification of the reservoir stress state. With further CO₂-injection tension failure in reservoir could occur, but shear failure will never happen under these conditions. Using TOUGH-FLAC, a scenario case is also analyzed with the assumption that the reservoir is naturally fractured. The specific analysis shows that the maximal storage pressure is 13.6?MPa which is determined by the penetration criterion of the caprock.     

Impact of CO<Subscript>2</Subscript> injection rate on heat extraction at the HDR geothermal field of Zhacanggou,China

CO₂ is now considered as a novel heat transmission fluid to extract geothermal energy. It can achieve the goal of energy exploitation and CO₂ geological sequestration. Taking Zhacanggou as research area, a “Three-spot” well pattern (one injection with two production), “wellbore–reservoir” coupled model is built, and a constant injection rate is set up. A fully coupled wellbore–reservoir simulator—T2Well—is introduced to study the flow mechanism of CO₂ working as heat transmission fluid, the variance pattern of each physical field, the influence of CO₂ injection rate on heat extraction and the potential and sustainability of heat resource in Guide region. The density profile variance resulting from temperature differences of two wells can help the system achieve “self-circulation” by siphon phenomenon, which is more significant in higher injection rate cases. The density of CO₂ is under the effect of both pressure and temperature; moreover, it has a counter effect on temperature and pressure. The feedback makes the flow process in wellbore more complex. In low injection rate scenarios, the temperature has a dominating impact on the fluid density, while in high rate scenario, pressure plays a more important role. In most scenarios, it basically keeps stable during 30-year operation. The decline of production temperature is <5 °C. However, for some high injection rate cases (75 and 100 kg/s), due to the heat depletion in reservoir, there is a dramatic decline for production temperature and heat extraction rate. Therefore, a 50-kg/s CO₂ injection rate is more suitable for “Three-spot” well pattern in Guide region.     

盐膏层造斜井段井眼缩径及套管外载数值模拟

盐膏层是油气成藏的良好盖层,塔里木盆地多个大型油气藏都属于巨厚盐下油气藏,为了提高单井产能,决定采用定向井和水平井来开发盐下油气藏。由于盐膏层距离产层较近,需要在盐膏层进行造斜。造斜井段盐膏层井眼的缩径规律及其对套管外载的影响国内外鲜有报道。应用有限元方法建立了造斜井段砂岩和盐膏岩地层、水泥环及套管耦合的三维力学模型,以塔里木羊塔克区块岩石力学测试成果为基础,研究得到造斜段井斜和方位对井眼缩径及套管外载的影响规律。该研究成果成功应用于塔里木巨厚盐下定向井、水平井轨迹设计,钻遇盐膏层泥浆密度的确定和井身结构设计,为塔里木盐膏层钻井、完井施工提供了重要的理论参考。     

Well-based hydraulic and geochemical monitoring of the above zone of the CO2 reservoir at Ketzin, Germany

In order to detect hydraulic and geochemical impact on the groundwater directly above the CO₂ storage reservoir at the Ketzin pilot site continuous monitoring using an observation well is carried out. The target depth (446 m below ground level, bgl.) of the well is the Exter formation (Upper Triassic, Rhaetian) which is the closest permeable stratigraphic overlying formation to the CO₂ storage reservoir (630–636 m bgl. at well location). The monitoring concept comprises evaluation of hydraulic conditions, temperature, water chemistry, gas geochemistry and δ¹³C values. This is achieved by a tubing inserted inside the well with installed pressure sensors and a U-tube sampling system so that pumping tests or additional wireline logging can be carried out simultaneously with monitoring. The aquifer was examined using a pump test. The observation well is hydraulically connected to the regional aquifer system and the permeability of about 1.8 D is comparatively high. Between Sept. 2011 and Oct. 2012, a pressure increase of 7.4 kPa is observed during monitoring under environmental conditions. Drilling was carried out with drilling mud on carbonate basis. The concentration of residual drilling mud decreases during the pump test, but all samples show a residual concentration of drilling mud. The formation fluid composition is recalculated with PHREEQC and is comparable to the literature values for the Exter formation. The gas partial pressure is below saturation at standard conditions and the composition is dominated by N₂ similar to the underlying storage reservoir prior to CO₂ injection. The impact of residual drilling mud on dissolved inorganic carbon and the respective δ¹³C values decreases during the monitoring period. The pristine isotopic composition cannot be determined due to calcite precipitation. No conclusive results indicate a leakage from the underlying CO₂ storage reservoir.     

A numerical study of mineral alteration and self-sealing efficiency of a caprock for CO2 geological storage

Geochemical interactions of brine–rock–gas have a significant impact on the stability and integrity of the caprock for long-term CO₂ geological storage. Invasion of CO₂ into the caprock from the storage reservoir by (1) molecular diffusion of dissolved CO₂, (2) CO₂-water two-phase flow after capillary breakthrough, and (3) CO₂ flow through existing open fractures may alter the mineralogy, porosity, and mechanical strength of the caprock due to the mineral dissolution or precipitation. This determines the self-enhancement or self-sealing efficiency of the caprock. In this paper, two types of caprock, a clay-rich shale and a mudstone, are considered for the modeling analyses of the self-sealing and self-enhancement phenomena. The clay-rich shale taken from the Jianghan Basin of China is used as the base-case model. The results are compared with a mudstone caprock which is compositionally very different than the clay-rich shale. We focus on mineral alterations induced by the invasion of CO₂, feedback on medium properties such as porosity, and the self-sealing efficiency of the caprock. A number of sensitivity simulations are performed using the multiphase reactive transport code TOUGHREACT to identify the major minerals that have an impact on the caprock’s self-sealing efficiency. Our model results indicate that under the same hydrogeological conditions, the mudstone is more suitable to be used as a caprock. The sealing distances are barely different in the two types of caprock, both being about 0.6 m far from the interface between the reservoir and caprock. However, the times of occurrence of sealing are considerably different. For the mudstone model, the self-sealing occurs at the beginning of simulation, while for the clay-rich shale model, the porosity begins to decline only after 100 years. At the bottom of the clay-rich shale column, the porosity declines to 0.034, while that of mudstone declines to 0.02. The sensitive minerals in the clay-rich shale model are calcite, magnesite, and smectite-Ca. Anhydrite and illite provide Ca²⁺ and Mg²⁺ to the sensitive minerals for their precipitation. The mudstone model simulation is divided into three stages. There are different governing minerals in different stages, and the effect of the reservoir formation water on the alteration of sensitive minerals is significant.     

油气沿不同时期断裂穿过泥岩盖层渗滤散失的地质条件及其识别方法

为了研究含油气盆地断裂发育区油气分布规律,在确定油气沿活动期和静止期断裂穿过泥岩盖层发生渗滤散失机理的基础上,针对油气沿活动期和静止期断裂穿过泥岩盖层渗滤散失的地质条件及识别方法进行了研究。研究结果表明：油气沿活动期断裂穿过泥岩盖层渗滤散失所需的地质条件是活动期断裂在盖层内上下连接分布,作为油气穿过泥岩盖层的输导通道;油气沿静止期断裂穿过泥岩盖层渗滤散失所需的地质条件是下伏储层油气剩余压力大于断层岩排替压力。通过比较泥岩盖层断接厚度与油气沿活动期断裂穿过泥岩盖层渗滤散失所需最小断接厚度的相对大小和下伏储层剩余压力与断层岩排替压力的相对大小,分别建立了油气是否沿活动期断裂和静止期断裂穿过泥岩盖层渗滤散失的识别方法,并将其应用于渤海湾盆地南堡凹陷南堡5号构造天然气能否通过活动期和静止期NP5 2断裂穿过东二段泥岩盖层渗滤散失的识别。结果表明：在断裂活动期,仅在L2和L8测线处天然气可以沿着NP5 2断裂穿过东二段泥岩盖层渗滤散失,其余测线处(L1、L3、L4、L5、L6、L7、L9)则不能;但是在断裂静止期,天然气不能沿NP5 2断裂穿过东二段泥岩盖层渗滤散失,与目前南堡5号构造东二段泥岩盖层之下已发现的天然气分布相吻合,表明这2种方法分别用于识别油气是否通过静止期断裂和活动期断裂穿过泥岩盖层渗滤散失是可行的。     

Study on Effects of Low Viscosity Fluid Pre-injection on Hydraulic Fracture Complexity in Tight Heterogeneous Glutenite Reservoirs

Tight heterogeneous glutenite reservoir is typically not easy to form complex hydraulic fracture (HF) due to its poor physical properties, poor matrix seepage capacity, and small limit discharge radius and undeveloped natural fracture system. To improve the HF complexity and the stimulated reservoir volume (SRV), a novel stimulation technology called CO₂ miscible fracturing has been introduced and its fracturing mechanism has been studied. The CO₂ miscible fracturing modifies the in situ stress field by injecting low viscosity fluid to increase the HF complexity and SRV. Therefore, a series of numerical simulations based on a hydro-mechanical-damage model were carried out to study the effects of low viscosity fluid pre-injection on pore pressure, stress field, and fracturing effect in tight heterogeneous glutenite reservoirs. The results indicate that the low viscosity fluid injection can effectively increase the pore pressure around the wellbore and reduce the effective stress of the glutenite. The FCI and SRV increase with the increase of the pre-injection amount of the low viscosity fluid. The HF complexity and SRV can be improved by pre-injecting low viscosity fluid to transform the in situ stress field. The field application of this technology in a well of Shengli Oilfield showed that low-viscosity fluid pre-injection can effectively increase the width of the fractured zone, improve the SRV, and optimize the fracturing effect.

     

Accessing effects and signals of leakage from a CO<Subscript>2</Subscript> reservoir to a shallow freshwater aquifer by reactive transport modelling

CO₂ geological storage is a transitional technology for the mitigation of climate change. In the vicinity of potential CO₂ reservoirs in Hungary, protected freshwater aquifers used for drinking water supplies exist. Effects of disaster events of CO₂ escape and brine displacement to one of these aquifers have been studied by kinetic 1D reactive transport modelling in PHREEQC. Besides verifying that ion concentrations in the freshwater may increase up to drinking water limit values in both scenarios (CO₂ or brine leakage), total porosity of the rock is estimated. Pore volume is expected to increase at the entry point of CO₂ and to decrease at further distances, whereas it shows minor increase along the flow path for the effect of brine inflow. Additionally, electrical conductivity of water is estimated and suggested to be the best parameter to measure for cost-effective monitoring of both worst-case leakage scenarios.     

Numerical modeling of the geomechanical behavior of Ghawar Arab-D carbonate petroleum reservoir undergoing CO<Subscript>2</Subscript> injection

Sedimentary porous rocks can be used for long-term subsurface containment of CO₂. Before injecting CO₂ to sedimentary reservoirs, it is necessary to perform stability analysis of the reservoir and to estimate the maximum sustainable pore fluid pressures. In order to avoid the reservoir damage during the CO₂ injection, the effective stresses in the reservoir should be evaluated. In this paper, numerical modeling techniques are used for the evaluation of stresses and deformations in a naturally fractured carbonate sedimentary reservoir. The developed numerical modeling scheme couples the behavior of the CO₂ injection and the change in the geomechanical behavior of the sedimentary carbonate reservoir for a case study from Saudi Arabia. The present investigation extends the previous studies by considering the sorption-based deformation during the injection of the compressed CO₂ fluid into the Arab-D naturally fractured carbonate reservoir. The change in permeability during the injection of CO₂ is evaluated. The adopted CO₂ injection scenario was shown to be within the safe maximum occupancy, and that the increase in the pore pressure does not result in the reservoir failure.     

Simulation of CO2 plume movement in multilayered saline formations through multilayer injection technology in the Ordos Basin,China

Deep saline aquifers still remain a significant option for the disposal of large amounts of CO₂ from the atmosphere as a means of mitigating global climate change. The small scale Carbon Capture and Sequestration demonstration project in Ordos Basin, China, operated by the Shenhua Group, is the only one of its kind in Asia, to put the multilayer injection technology into practice. This paper aims at studying the influence of temperature, injection rate and horizontal boundary effects on CO₂ plume transport in saline formation layers at different depths and thicknesses, focusing on the variations in CO₂ gas saturation and mass fraction of dissolved CO₂ in the formation of brine in the plume’s radial three-dimensional field around the injection point, and interlayer communication between the aquifer and its confining beds of relatively lower permeability. The study uses the ECO2N module of TOUGH2 to simulate flow and pressure configurations in response to small-scale CO₂ injection into multilayer saline aquifers. The modelling domain involves a complex multilayer reservoir–caprock system, comprising of a sequence of sandstone aquifers and sealing units of mudstone and siltstone layers extending from the Permian Shanxi to the Upper Triassic Liujiagou formation systems in the Ordos Basin. Simulation results indicate that CO₂ injected for storage into deep saline aquifers cause a significant pressure perturbation in the geological system that may require a long duration in the post-injection period to establish new pressure equilibrium. The multilayer simultaneous injection scheme exhibits mutual interference with the intervening sealing layers, especially when the injection layers are very close to each other and the corresponding sealing layers are thin. The study further reveals that injection rate and temperature are the most significant factors for determining the lateral and vertical extent that the CO₂ plume reaches and which phase and amount will exist at a particular time during and after the injection. In general, a large number of factors may influence the CO₂–water fluid flow system considering the complexity in the real geologic sequence and structural configurations. Therefore, optimization of a CO₂ injection scheme still requires pursuance of further studies.