Caprock Integrity Research Articles

Investigation of Caprock Integrity Due to Pressure Build-up During High-volume Injection into the Utsira Formation

In this work, we investigate the pressure-limited storage capacity of the Utsira formation. We employ the use of a simple capacity estimate based on maximum sustainable pressure. Here, the pressure during injection or post-injection cannot exceed the least compressive stress at the base of the caprock at any location. Given the global capacity estimate, large-scale simulations are performed to determine if the global capacity can be reasonably attained given local injectivity constraints and long-term CO2 trapping. We find that the Utsira can withstand injection rates over 100 Mt/y for 50 years, which is equivalent to 8.3 Gt of CO2.

Quantification of CO2-cement-rock interactions at the well-caprock-reservoir interface and implications for geological CO2 storage

Wellbore integrity is a key risk factor for geological CO2 storage. A primary purpose of this study is to analyze the impacts of CO2 leakage through wellbore cement and surrounding caprock with a gap (annulus) in between. Key parameters for cement-CO2 interactions were verified with a cement core sample from the SACROC Unit exposed to CO2 for 30 years. These parameters and other data served as the basis of reactive transport model simulations. The case study example for this analysis is the Farnsworth CO2 enhanced oil recovery (EOR) unit (FWU) in the northern Anadarko Basin in Texas. Specific objectives of this study are: (1) to analyze impacts on wellbore integrity under CO2-rich conditions within an operational time scale; and (2) to predict mechanisms of chemical reactions associated with cement-CO2-brine interactions.Simulation results suggest that cement tortuosity and diffusion coefficient are the two most important parameters that dictate cement carbonation penetration distance. Portlandite (Ca(OH)2) reacts with CO2 and forms calcite, reducing porosity, in turn directly impacting CO2 leakage rates by infilling pathways. Simulated calcium-silicate-hydrate (CSH) degradation is limited, suggesting that a wellbore will maintain its integrity and structure under the considered conditions. Simulations also suggest that sulfate concentration <2500mg/L in the leaking brine would not cause monosulfate degradation. Without an existing fracture, CO2 will likely not enter the caprock, and the cement would not degrade accordingly. For the FWU specifically, the wellbore cement would likely keep its structure and integrity after 100 years. However, if a fracture exists at the cement-caprock interface, calcite dissolution in the limestone caprock fracture could occur and increase the fracture volume, a concern for caprock integrity.

Experimental investigation of injection-induced fracturing during supercritical CO2 sequestration

Leakage risk assessment is an inevitable procedure in permanent sequestration and storage of CO2 in deep saline aquifers and depleted oil and gas reservoirs, where the integrity of caprock is most critical. Low porosity and low permeability concrete cubes were employed as caprock analogs to investigate the supercritical CO2 injection-induced fracturing processes under true tri-axial stress conditions. A systematic experimental procedure, consisting of active acoustic emission measurement, pressure decay, injection pressure and temperature monitoring, fracture coloring, and gas fracturing, is formulated to qualitatively and quantitatively characterize the injection-induced fracturing processes and fracture morphology. Occurrence of injection-induced fracturing can be directly identified from peaks of borehole pressure profiles as well as sharp drops on temperature profiles due to CO2 expansion, but generally there was no fracture propagation plateau appearing for the 20cm rock cubes with zero pore pressure. Acoustic wave signatures, including both waveform change and arrival time delay, can effectively capture the extension of induced fractures inside the opaque rock. Initiation and propagation of supercritical CO2 injection-induced fractures are highly dominated by the tri-axial stresses, following the general trend of continuum mechanics at high stress levels with large stress difference. As the stress difference decreases, induced fractures branch off in relatively arbitrary directions. For these supercritical CO2 injection-induced fracturing experiments, poroelastic mechanics model makes a decent fit with the measured breakdown pressure of the caprock analogs. Findings in this study are valuable for risk analysis and operation optimization of geological CO2 sequestration and storage as well as for CO2 fracturing design and implementation in shale and tight reservoirs.

A Reservoir–Geomechanical Model to Study the Likelihood of Tensile and Shear Failure in the Caprock of Weyburn CCS Project with Regard to Interpretation of Microseismic Data

According to poroelastic theory and also field observations, an increase in reservoir pore pressures can result in a decrease in horizontal stresses in the seal layers. This reduction is in favor of hydrofracture initiation and reactivation of weak planes and has to be studied in caprock integrity analyses. In this paper, a field scale reservoir–geomechanical (GEM-FLAC3D) model is developed for the Phase IB area of the Weyburn (Canada) CCS project that is located in Williston sedimentary basin. A one-way coupling has been conducted between the two codes for the period of CO2 injection in Phase IB area from 2000 to 2010. Therefore, the reservoir pore pressures at selected timesteps are unidirectionally fed to the FLAC3D. In order to study the likelihood of tensile and shear failure in the seal layer on top as a result of stress transfer due to poroelastic effects, two margin ratios are defined for tensile and shear failure and their variations are studied above the reservoir upon changes in pore pressures within the reservoir. The results show that overall; the likelihood of shear failure has been about 25% greater than that of tensile failure in Weyburn. However, between 2008 and 2009, the pressures were high enough to trigger both tensile and shear mechanisms above the reservoir. A discussion is also presented on relevance of this study for interpretation of microseismic data with regard to failure margin ratios, magnitudes and distribution of events recorded in each year.

I can’t hear you, speak up — A case study of passive seismic monitoring of the CO2 injection at Delhi Field, Louisiana

Passive seismic monitoring has a variety of applications, most widely to monitor hydraulic fracturing in tight sandstone or shale reservoirs. For hydraulic fracturing, microseismic events can help to define the affected zone of the reservoir and the stress state. For enhanced oil recovery (EOR), wastewater, and carbon capture and storage (CCS) injection projects, passive seismic can aid in understanding the impact of injection on the reservoir or the surrounding formations. In any injection programme, containment and caprock integrity are always a concern. Passive seismic data can help to identify potential fracturing within the reservoir area or the overlying formations. The goal of an enhanced oil recovery (EOR) is not to fracture the reservoir and not to lose CO2 out of zone. CO2 seeping into non-reservoir zones wastes resources. Furthermore, there are potential environmental and legal consequences if CO2 is allowed to migrate closer to the surface. Thus, monitoring is a key component of an injection project. Programmes using passive seismic to monitor CO2 injection have experienced mixed results. A primary research field for fluid injection microseismicity is Weyburn field in Canada. Throughout the project, about 100 events were located up to 1600 ft from a downhole array with event magnitudes ranging from -3 to -1. The majority of events occurred at the start of CO2 injection, with lower levels of activity after (White, 2009). CSS projects, with injection into deeper formations, can have a greater level of microseismic activity (Bauer et al., 2015). In a CO2 injection project analysed by Verdon et al (2010), a number of small events were detected close to the monitor well. The majority of events occurred at the start of injection. A number of campaigns did not record microseismicity at all during injection, such as the Pembina oil field in Alberta, Canada (Martinez-Garzon et al., 2013). Additionally, analysis by Soma and Rutledge (2013) found the microseismicity in Aneth oil field was related to salt water disposal not the CO2 injection. The success of different monitoring campaigns is related to a number of factors including geology, geomechanics, and acquisition geometry.

Seismicity-permeability coupling in the behavior of gas shales, CO2 storage and deep geothermal energy

Contemporary methods of energy conversions that reduce carbon intensity include sequestering CO2, fuel switching to lower-carbon sources, such as from gas shales, and recovering deep geothermal energy via EGS. In all of these endeavors, either maintaining the low permeability and integrity of caprocks or in controlling the growth of permeability in initially very-low-permeability shales and geothermal reservoirs represent key desires. At short-timescales of relevance, permeability is driven principally by deformations—in turn resulting from changes in total stresses, fluid pressure or thermal and chemical effects. These deformations may be intrinsically stable or unstable, result in aseismic or seismic deformation, with resulting changes in permeability conditioned by the deformational mode. We report experiments and models to represent the respective roles of mineralogy, texture, scale and overpressures on the evolution of friction, stability and permeability in fractured rocks. Models show a transition from high to low residual coefficient of friction for homogenous mixtures of strong and weak aggregates when the proportion of the weak material reaches 25% with a significant transition occurring at 50%. This transition may occur at much lower proportions where the material is structured, such as in a thin layer. For pre-existing fractures, we observe that fracture permeability declines during shearing while the increased sliding velocity reduces the rate of decline. The physics of these observed behaviors are explored via parametric studies and surface measurement of fractures, showing that both permeability and frictional strength are correlated to the fracture asperity evolution that is controlled in-turn by the sliding velocity and fracture material.

Monitoring of Rock Stress Redistribution in Geological CO2 Sequestration

Shale gas has become an increasingly important clean energy, which has been explored worldwide in recent decades. Supercritical CO 2 acts as fracturing fluid for shale gas production. The safety monitoring is essential to prevent any kinds of leakage from the reservoir as the supercritical CO 2 physically stored hundred kilometres underground. Seismic tomography is an imaging technique that uses induced seismic waves to create three dimensional images of the subsurface. It is an effective monitoring method to evaluate the caprock integrity in the carbon dioxide sequestration storage (CCS). In this experimental research, a simulated uniaxial compressive load is applied on a granite sample to analyze the stress redistribution for long-term in-situ caprock integrity during CO 2 injection. The induced seismic waves are recorded and seismic events are traced based on the Geiger algorithm. The frequency of seismic events correlates with the caprock failure evolution. The acquired seismic data is divided into four regimes based on the frequency of seismic events and the failure process to examine the failure evolution. Furthermore, the travel time and distance is plotted to analyze the variation of velocity. Finally, the double difference tomography (TomoDD) algorithm using arrival time is adopted to recalculate the locations of seismic events and velocity structure in each regime. The results indicate that the passive seismic system can map the caprock stress distribution and allow for imaging of the caprock integrity. TomoDD exhibits sound improvements to relocate seismic events both in relative and absolute locations as well as to characterize the local velocity structure. The study further reveals that seismic monitoring along with TomoDD could evaluate the caprock failure accurately in the CCS.

Effects of phosphate on biotite dissolution and secondary precipitation under conditions relevant to engineered subsurface processes.

Brine-mica interfacial interactions affect both the caprock integrity and the fate and transport of reactive fluids at deep subsurface sites. Phosphate naturally exists at low concentration in subsurface brines, and its concentration can be increased significantly during energy-related engineered subsurface processes. However, our understanding of the influence of phosphate on brine-mica interactions is limited, especially under subsurface conditions. Here, biotite dissolution experiments were conducted without and with phosphate (0.1, 1, and 10 mM) at 95 °C and 102 atm CO2. Compared to the control, 0.1 mM, and 1 mM phosphate systems, biotite dissolution was four times higher with 10 mM phosphate. Despite the dissolution differences, in all the phosphate systems, phosphate interacted with Al and Fe sites in biotite, forming surface complexation and precipitating as Fe- or Al-bearing minerals on surfaces and in solutions. Consequently, aqueous Fe and Al concentrations became lower with phosphate than in the control experiments. In addition, the biotite basal surfaces became more hydrophilic after reaction with phosphate, even at 0.1 mM, mainly from phosphate adsorption. This study offers new information on how phosphate-containing brine interacts with caprocks and on the consequent wettability changes, results that can benefit current and future energy-related subsurface engineering processes.

Profitability Evaluation of a Hybrid Geothermal and CO2 Sequestration Project for a Coastal Hot Saline Aquifer.

With growing interest in commercial projects involving industrial volume CO2 sequestration, a concern about proper containment and control over the gas plume becomes particularly prominent. In this study, we explore the potential of using a typical coastal geopressured hot saline aquifer for two commercial purposes. The first purpose is to harvest geothermal heat of the aquifer for electricity generation and/or direct use and the second one is to utilize the same rock volume for safe and controlled CO2 sequestration without interruption of heat production. To achieve these goals, we devised and economically evaluated a scheme that recovers operational and capital costs within first 4 years and yields positive internal rate of return of about 15% at the end of the operations. Using our strategic design of well placement and operational scheduling, we were able to achieve in our numerical simulation study the following results. First, the hot water production rates allowed to run a 30 MW organic Rankine cycle plant for 20 years. Second, during the last 10 years of operation we managed to inject into the same reservoir (volume of 0.8 x 109 m3 ) approximately 10 million ton of the supercritical gas. Third, decades of numerical monitoring the plume after the end of the operations showed that this large volume of CO2 is securely sequestrated inside the reservoir without compromising the caprock integrity.

Geology of bitumen and heavy oil: An overview

On a world-wide basis there is an estimated 5.6 trillion barrels of bitumen and heavy-oil resources which occur in over 70 different countries, with most of the heavy-oil in Venezuela and most of the bitumen in Canada. The most common plate-tectonic settings in which the heavy-oil and bitumen are found are in continental multi-cyclic marginal basins and in continental rift basins.Heavy oil and bitumen resources are largely a result of natural degradation of formerly conventional oil accumulations. The natural degradation for most is biologic in origin, with the result that the majority of heavy-oil and bitumen deposits is characteristically in younger rocks (Cretaceous and younger) and at shallow depths (usually <200m, up to 2000m maximum). At a deposit-scale it is necessary for communication to have been established between the surface and subsurface to facilitate the biologic contamination of the pre-existing light petroleum reservoirs. Communication is through loss of caprock integrity, associated with major erosion (creation of unconformities), faulting, fracturing; and, for carbonate host-rocks, karstification. Two cases are discussed to illustrate these geologic processes: 1) the influence of the sub-Cretaceous unconformity on the Cretaceous oil-sands in the Western Canada Sedimentary Basin; and, 2) the influence of faulting, fracturing and karstification on the Grosmont carbonate-bitumen deposit of northeastern Alberta.

Numerical assessment of the maximum operating pressure for SAGD projects by considering the intrinsic shale anisotropy

This paper investigates the effect of anisotropic behavior of caprock shales on the caprock failure pressure in SAGD projects. Shales and mudstones exhibit strong anisotropy at the micro and macro scales. However, the anisotropic behavior has been neglected in the existing published works on this subject. This paper focuses on the effect of the intrinsic anisotropy of shales on caprock integrity. The Maximum Operating Pressure (MOP) is calculated from the failure pressure using an appropriate safety factor.In this paper, a coupled hydro-thermo-mechanical model was developed for the assessment of caprock integrity in thermal operations. A transversely isotropic constitutive model in the elastic range was combined with an anisotropic failure criterion to capture the intrinsic anisotropy of the cap shale. The coupled tool was validated against field data (mainly the surface heave) and employed in a study to determine the effect of shale anisotropic behavior on the pressure associated with caprock breach.Results display the effect of shale anisotropy on caprock response in terms of deformations, stresses and failure pressure. The assumption of isotropic shale behavior in caprock integrity assessment for a case study resulted in the overestimation of the failure pressure by about 7%.Existing numerical models for evaluating the integrity of caprocks during thermal operations employ isotropic constitutive laws. These models are believed to be deficient in capturing strongly anisotropic response of shales and mudstones. The research described in this paper incorporated elasto-plastic shale anisotropy in the caprock failure analysis model for the first time. This study demonstrates the importance of capturing shale anisotropy in the accurate prediction of caprock breach pressure in SAGD projects.

Impact of layer thickness and well orientation on caprock integrity for geologic carbon storage

Economic feasibility of geologic carbon storage demands sustaining large storage rates without damaging caprock seals. Reactivation of pre-existing or newly formed fractures may provide a leakage pathway across caprock layers. In this study, we apply an equivalent continuum approach within a finite element framework to model the fluid-pressure-induced reactivation of pre-existing fractures within the caprock, during high-rate injection of super-critical CO2 into a brine-saturated reservoir in a hypothetical system, using realistic geomechanical and fluid properties. We investigate the impact of reservoir to caprock layer thickness, wellbore orientation, and injection rate on overall performance of the system with respect to caprock failure and leakage. We find that vertical wells result in locally higher reservoir pressures relative to horizontal injection wells for the same injection rate, with high pressure inducing caprock leakage along reactivated opening-mode fractures in the caprock. After prolonged injection, leakage along reactivated fractures in the caprock is always higher for vertical than horizontal injection wells. Furthermore, we find that low ratios of reservoir to caprock thickness favor high excess pressure and thus fracture reactivation in the caprock. Injection into thick reservoir units thus lowers the risk associated with CO2 leakage.

Observational evidence confirms modelling of the long-term integrity of CO2-reservoir caprocks.

Storage of anthropogenic CO2 in geological formations relies on a caprock as the primary seal preventing buoyant super-critical CO2 escaping. Although natural CO2 reservoirs demonstrate that CO2 may be stored safely for millions of years, uncertainty remains in predicting how caprocks will react with CO2-bearing brines. This uncertainty poses a significant challenge to the risk assessment of geological carbon storage. Here we describe mineral reaction fronts in a CO2 reservoir-caprock system exposed to CO2 over a timescale comparable with that needed for geological carbon storage. The propagation of the reaction front is retarded by redox-sensitive mineral dissolution reactions and carbonate precipitation, which reduces its penetration into the caprock to ∼7 cm in ∼105 years. This distance is an order-of-magnitude smaller than previous predictions. The results attest to the significance of transport-limited reactions to the long-term integrity of sealing behaviour in caprocks exposed to CO2.

Reactivity of micas and cap-rock in wet supercritical CO2 with SO2 and O2 at CO2 storage conditions

Seal or cap-rock integrity is a safety issue during geological carbon dioxide capture and storage (CCS). Industrial impurities such as SO2, O2, and NOx, may be present in CO2 streams from coal combustion sources. SO2 and O2 have been shown recently to influence rock reactivity when dissolved in formation water. Buoyant water-saturated supercritical CO2 fluid may also come into contact with the base of cap-rock after CO2 injection. Supercritical fluid-rock reactions have the potential to result in corrosion of reactive minerals in rock, with impurity gases additionally present there is the potential for enhanced reactivity but also favourable mineral precipitation.The first observation of mineral dissolution and precipitation on phyllosilicates and CO2 storage cap-rock (siliciclastic reservoir) core during water-saturated supercritical CO2 reactions with industrial impurities SO2 and O2 at simulated reservoir conditions is presented. Phyllosilicates (biotite, phlogopite and muscovite) were reacted in contact with a water-saturated supercritical CO2 containing SO2, or SO2 and O2, and were also immersed in the gas-saturated bulk water. Secondary precipitated sulfate minerals were formed on mineral surfaces concentrated at sheet edges. SO2 dissolution and oxidation resulted in solution pH decreasing to 0.74 through sulfuric acid formation. Phyllosilicate dissolution released elements to solution with ∼50% Fe mobilized. Geochemical modelling was in good agreement with experimental water chemistry. New minerals nontronite (smectite), hematite, jarosite and goethite were saturated in models. A cap-rock core siltstone sample from the Surat Basin, Australia, was also reacted in water-saturated supercritical CO2 containing SO2 or in pure supercritical CO2. In the presence of SO2, siderite and ankerite were corroded, and Fe-chlorite altered by the leaching of mainly Fe and Al. Corrosion of micas in the cap-rock was however not observed as the pH was buffered by carbonate dissolution. Ca-sulfate, and Fe-bearing precipitates were observed post SO2-CO2 reaction, mainly centered on surface cracks and an illite rich illite-smectite precipitate quantified. Water saturated impure supercritical CO2 was observed to have reactivity to rock-forming biotite, muscovite and phlogopite mineral separates. In the cap-rock core however carbonates and chlorite were the main reacting minerals showing the importance of assessing actual whole core.

High‐stress triaxial direct‐shear fracturing of Utica shale and in situ X‐ray microtomography with permeability measurement

AbstractThe challenge of characterizing subsurface fluid flow has motivated extensive laboratory studies, yet fluid flow through rock specimens in which fractures are created and maintained at high‐stress conditions remains underinvestigated at this time. The studies of this type that do exist do not include in situ fracture geometry measurements acquired at stressed conditions, which would be beneficial for interpreting the flow behavior. Therefore, this study investigates the apparent permeability induced by direct‐shear fracture stimulation through Utica shale (a shale gas resource and potential caprock material) at high triaxial stress confinement and for the first time relates these values to simultaneously acquired in situ X‐ray radiography and microtomography images. Change in fracture geometry and apparent permeability was also investigated at additional reduced stress states. Finite element and combined finite‐discrete element modeling were used to evaluate the in situ observed fracturing process. Results from this study indicate that the increase in apparent permeability through fractures created at high‐stress (22.2 MPa) was minimal relative to the intact rock (less than 1 order of magnitude increase), while fractures created at low stress (3.4 MPa) were significantly more permeable (2 to 4 orders of magnitude increase). This study demonstrates the benefit of in situ X‐ray observation coupled with apparent permeability measurement to analyze fracture creation in the subsurface. Our results show that the permeability induced by fractures through shale at high stress can be minor and therefore favorable in application to CO2 sequestration caprock integrity but unfavorable for hydrocarbon recovery from unconventional reservoirs.

Numerical investigation of CO2 storage in hydrocarbon field using a geomechanical-fluid coupling model

Abstract Increasing pore pressure due to CO 2 injection can lead to stress and strain changes of the reservoir. One of the safely standards for long term CO 2 storage is whether stress and strain changes caused by CO 2 injection will lead to irreversible mechanical damages of the reservoir and impact the integrity of caprock which could lead to CO 2 leakage through previously sealing structures. Leakage from storage will compromise both the storage capacity and the perceived security of the project, therefore, a successful CO 2 storage project requires large volumes of CO 2 to be injected into storage site in a reliable and secure manner. Yougou hydrocarbon field located in Orods basin was chosen as storage site based on it's stable geological structure and low leakage risks. In this paper, we present a fluid pressure and stress-strain variations analysis for CO 2 geological storage based on a geomechanical-fluid coupling model. Using nonlinear elasticity theory to describe the geomechanical part of the model, while using the Darcy's law to describe the fluid flow. Two parts are coupled together using the poroelasticity theory. The objectives of our work were: 1) evaluation of the geomechanical response of the reservoir to different CO 2 injection scenarios. 2) assessment of the potential leakage risk of the reservoir caused by CO 2 injection.

Offshore injection and overburden surveillance using real-time passive seismic

In 2013 a seismic caprock monitoring system with 172 nodes was installed on the Oseberg oil and gas field in the Norwegian North Sea. It was specifically designed for active and passive seismic monitoring of a disposal injection well. The aim of the monitoring is for a safer operation with avoidance of leakages to the sea, and increased injection. Despite installation and yearly maintenance costs but owing to benefits in the operation of the injector, the system provides yearly savings of around $1.2 million. Currently, the system does most of the passive seismic analysis – microseismic and interferometry – in real time, and we present data examples from the last two years. Typical noise in the data (seismic shooting, platform generated noise and marine traffic) are removed and the signal-to-noise ratio is significantly improved, resulting in better detections and event location, especially for small microseismic events. Seismic interferometry is used to observe/detect changes in the water column and the shallow subsurface down to several hundred metres. Several offshore hydrocarbon-bearing fields have experienced fractures in the overburden from injection into disposal wells, including leakage to the surface. Although injection procedures to avoid this are effective, they significantly limit the rates and pressures of the injection. To overcome this, a permanent offshore seismic monitoring system using both active and passive seismic methods has been developed. It was installed at the seabed of the North Sea Oseberg field in 2013 with the main aim to control caprock integrity and ensure safe injection, which makes the system unique.

Caprock integrity determination at the Christina Lake Thermal Recovery Project, Alberta

Abstract The Cenovus-ConocoPhillips Christina Lake oilsands project uses Steam-Assisted Gravity Drainage (SAGD) to recover bitumen from the Lower Cretaceous McMurray Formation at depths between 300 and 400 m. The McMurray Formation at the Christina Lake Field consists of fluvial to estuarine sands and muds capped by marine shales and sands of the Wabiskaw member of the Clearwater Formation. The SAGD process involves injecting steam under pressure to mobilize the bitumen, which is then pumped to the surface. The increased reservoir pressure is expected to be contained by the caprock. In the event of a failure of the caprock to contain these pressures the steam and oil may escape to shallower units and possibly the surface. This is not a desired outcome. We describe a process to characterize overburden and evaluate caprock strength. The minimum in situ principal stress is shown to be five times reservoir operating pressure and 2.5 times startup pressure. Compressive strength at the reservoir confining pressure of 4.5 MPa is six times operating pressure and three times startup pressure. The Wabiskaw member is shown to contain laterally continuous and impermeable semiconsolidated muds. Porosities and permeabilities are low and capillary entry pressure is high. A program of subsurface and surface monitoring is described.

Numerical investigation of the formation displacement and caprock integrity in the Ordos Basin (China) during CO2 injection operation

Theoretical and numerical studies of coupled hydro-mechanical processes during geothermal and hydrocarbon production, nuclear waste disposal, and CO2 sequestration in geological media have become a research focus worldwide. However, their application in China, especially CO2 sequestration, is still in infancy and may need several years to develop. In this paper coupled hydro-mechanical processes in CO2 migration, formation uplift and the state of caprock integrity as a result of CO2 sequestration have been investigated by simulation at field scale for an integrated CCS (CO2 Capture and Sequestration) project launched in the Ordos Basin, China. The paper aims at attaining long-term safety and integrity of caprock to ensure success for subsequent project operations at field scale. The linked TOUGH2MP-FLAC3D simulator has been used to study the coupled hydraulic-mechanical responses to primary stresses, injection rate and reservoir permeability during CO2 injection and post-injection periods by means of 4 case studies. In the short-term operation of a CO2 sequestration project launched in the Ordos Basin 0.1Mt CO2 has been injected in four saline aquifers within a period of 1 year and 9 years of relaxation time allotted for simulation runs. Contrary to using hydraulic field conditions alone, a combination of hydraulic-mechanical effects accounts for lateral migration of CO2 in aquifer layers that leads to partial volumetric expansion of the reservoir. Amongst the main factors affecting hydro-mechanical processes, injection rate has the most significant impact. This is followed by reservoir permeability that is responsible for gauging the uplift trend rate in the post-injection period through hindering the dissipation of pore pressure. Results indicate that the scope of pore pressure attained will be larger in the isotropic stress state than in the compressional stress condition, pointing to the significance of primary stress. Calculation of the maximum storage pressure within safety limits using the integrity and shear criteria reveals that failure of caprock integrity increases with the amount of CO2 injected. During injection however, the risk of caprock failure, especially in thin sandstone-caprock interlayered systems, increases with time. This paper estimates the pressure buildup in the four injection aquifers in the Ordos Basin, as a basis to ensure safety in the long-term operation of the CO2 sequestration project, hence providing important reference for future commercial operations at field scale.

Numerical modeling of percolating flow path in a caprock formation during aquifer pressurization and its implication for CO2 sequestration

Spatial distribution of sand bodies in caprock is important to its sealing potential in the evaluation of a potential waste disposal site. A numerical investigation was conducted to investigate the roles of sand bodies in caprock integrity, and a new leaking mechanism associated with the embedded sand bodies has been identified for the first time. This numerical model is characterized by a low proportion of sand bodies in caprock formation and stochastic permeability assignments to the shale facies with a consideration of stress-sensitive permeability. The research revealed that sand bodies in caprock, even initially unconnected due to their low concentration, represent the foundation for creating a percolating flow path if certain conditions are met. These conditions include a relatively high pore pressure gradient across the caprock, which may occur during fluid injection and a favorable geometric configuration of these sand bodies. Sand bodies of different shapes play different roles in forming a percolating flow path. Sand bars/dykes can lead pore pressure front to cover a considerable vertical thickness quickly, while thin sand sheets tend to transfer the pore pressure front across a large horizontal range and thus increase the possibility of involving other local sand bodies in the evolution of percolating flow paths. On the other hand, the presence of percolating flow path in caprock can limit the pore pressure increase in the aquifer formation during fluid injection. The more active the flow paths, the less increase the pore pressure that occurs in the aquifer. Stress-dependent permeability can facilitate the formation of percolating flow path, but evaluating how much impact it may have remains a question for future research. The modeling results indicate that the underlying geologically based discrete structure of permeable domains, even when masked by a low-permeable rock matrix, exerts a significant influence on the location and magnitude of fluid flow within the system during fluid injection.