Caprock Core Research Articles

A Study on the Breakthrough Pressure of Porous Rock Formations in Gas Storage Reservoirs

Breakthrough pressure of natural gas in rock is an important evaluation parameter in gas reservoir development. In this study, experimental measurements of porosity and permeability of the caprock core were carried out. A digital core model was obtained by body rendering of rock CT (Computed Tomography) slices using Avizo software. Then, the grid model was imported into Fluent software for a numerical simulation of natural gas breakthrough pressure in the core. The innovations of this paper include (1) an accurate calculation method of cap breakthrough pressure based on the VOF method; (2) the method performs a perceptual analysis of average pore radius, wettability, roughness height, and viscosity ratio.

Old core, new tricks: a comparative study of old and new mudstone cores for applications in the energy transition

Repurposing depleted oil and gas reservoirs for secondary storage may play an important role in the transition to low-carbon energy. The integrity of the cap rocks overlying the reservoirs is an important factor for gas storage and needs to be understood prior to repurposing. In some cases, old cap-rock cores collected during exploration and development of oil and gas fields may be available for characterization using modern techniques but after being stored for decades these cores are likely to have experienced many changes in moisture, which can lead to physical changes. A comparative study of samples taken from old, unpreserved mudstone core and samples from a recently acquired and preserved core taken from the same formation shows that the mineralogy, porosity and permeability results are relatively similar between the two cores. The differences in the porosity measurements between the old and new core samples are primarily due to natural variations in grain size, rather than the preservation status of the cores. Geomechanical data, however, show significant and non-systematic differences between the old samples and the new samples, suggesting that old core samples are not suitable for geomechanical characterization. In the absence of new, well-preserved core, old core samples may provide suitable porosity, permeability and mineralogical data, whereas the old, unpreserved core is unlikely to provide reliable geomechanical data. Supplementary material: Individual BIB-SEM porosity measurements for each sample are available at https://doi.org/10.6084/m9.figshare.c.6725765 Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Fracture mechanical properties of carbonate and evaporite caprocks in Sichuan Basin, China with implications for reservoir seal integrity

Fracture development in reservoir rocks enhances the flow and transport properties of the petroleum system, yet fracture in caprocks can significantly risk reservoir seal integrity. Over geological time scales, the slow, subcritical fracture propagation can contribute considerably to the fracture system development, especially under reactive fluid environments during petroleum migration and accumulation. Using the double torsion technique, we measure the subcritical fracture growth properties of carbonate and anhydrite caprock core samples in Sichuan Basin, China, under different environments of ambient air, de-ionized water, and formation water. Experimental results show that the aqueous fluids significantly promote subcritical fracture growth: (1) compared to ambient air, the presence of aqueous fluids dramatically reduces both the fracture toughness (KIC) and subcritical fracture growth index (SCI) of the caprocks; (2) the KIC reduction is more prominent for the anhydrite (50%) caprock than the carbonate (30%) caprock, which suggest that mineral solubility is responsible for the fluid-weakening effect; (3) a systematic change of SCI with varying fluid conditions is observed: SCI is the largest in air, smallest in formation water, and intermediate in de-ionized water. Microstructural analysis suggests a predominantly opening mode for both the natural fractures and induced fractures during fracture mechanical testing. Our results further demonstrate that subcritical fracture growth process is also strongly related to rock composition and stress conditions. These observations provide insights into the mechanisms controlling fracture growth in carbonate and evaporite caprocks, which could extend to brittle failure and fluid-rock interactions occurring during the seismic cycle in the upper crust.

Geophysical Monitoring of Gaseous and Supercritical CO2 Fracture Flow Through a Brine-Saturated Shale Caprock

Pre-existing and induced fractures and faults can play a role as bypass conduits and fast leaking channels in CO2 storage sites. They should therefore be well characterized during site selection, and monitored thoroughly during operation to track the movement and fate of the CO2 plume. Despite to date extensive research on the geophysical properties of brine- and CO2-saturated porous reservoir rocks, changes in acoustic velocity and electrical resistivity during a sole fracture fluid displacement are, however, rather little investigated. Hence, we herein present a laboratory study of core-scale geophysical monitoring during drainage-imbibition cycles of the brine-CO2 system through a shale caprock core sample with a vertical fracture. The experiments were conducted using both gaseous and scCO2 with 4 and 9 MPa pore pressures, respectively, at 12 MPa confining pressure. The tests were performed at 40°C during the loading and unloading stages in order to look into the hysteresis effect. We used a fractured core sample from the Upper Jurassic organic-rich shales of the Draupne Formation, which is the primary caprock for the Smeaheia CO2 storage site – a full-scale CCS project in Norway. The primary objective of the experiment was to compare the geophysical measurements using gaseous and scCO2 drainage-imbibition cycles during the tests in a core-scale experiment. Moreover, we were interested to see how sensitive acoustic velocity and electrical resistance techniques are to the fracture fluid displacement using different CO2 phase states. The outcomes of our high-pressure high-temperature experiment of simultaneous measurements of fracture flow and geophysical properties indicate that potential leakage of injected CO2 through the fractured-shale caprock can be detected in the core-scale laboratory experiments. The performed drainage-imbibition cycles using gaseous and scCO2 resulted in different behaviors in P-wave velocity (Vp) and electrical resistance in axial and radial directions for these two phase states. The measured Vp during the displacement of fracture fluid, CO2-brine subsequent cycles, showed a limited sensitivity in terms of magnitude and relative change. The electrical resistance, on the other hand, shows higher sensitivity and larger variation during fluid displacement along the fracture. It was also observed that the crossplot of Vp versus electrical resistance could detect and even differentiate the different phases during the loading and unloading stages.

From core-scale experiment to reservoir-scale modeling: A scale-up approach to investigate reaction-induced permeability evolution of CO2 storage reservoir and caprock at a U.S. CO2 storage site

Mineral dissolution and secondary mineral precipitation can cause porosity and permeability changes of CO2 storage reservoirs and caprocks after injection of CO2. In this paper, a 3-step approach (core-scale experiment →core-scale modeling →reservoir-scale modeling) is developed to simulate reservoir-scale porosity and permeability evolution of CO2 storage formation and caprock at a model CO2 storage site. The model site is based on characteristics of a real site in Mississippi, USA. Important chemical and permeability modeling parameters in the reservoir-scale model are validated by core-scale experimental and reactive transport modeling results. The reservoir-scale model predicts a maximum 3.2% permeability increase of the CO2 storage formation and a maximum 1.1% permeability increase of the caprock after 1000 years of exposure to CO2-rich brine, while the core-scale model predicts 7% permeability decrease for a small CO2 storage formation core and 296% permeability increase for a small caprock core after 180-day exposure to CO2-rich brine. The discrepancy between permeability results of reservoir-scale model and core-scale model is attributed to strong pH buffering effect of CO2 storage formation with large mass of H+-consuming minerals. Therefore, using core-scale experiments/models only is not sufficient to elucidate reservoir-scale permeability evolution. Variations of key model parameters have a small effect on permeability evolution of both CO2 storage formation and caprock, except for variations of Keq (SiO2 (am)) and the exponent n in permeability-porosity correlation. SiO2 (am) is a key mineral that governs permeability evolution of CO2 storage formation and caprock, given the characteristics of the model CO2 storage site.

A combined geochemical and μCT study on the CO2 reactivity of Surat Basin reservoir and cap-rock cores: Porosity changes, mineral dissolution and fines migration

Geological storage of CO2 generally involves injection of a CO2 stream into a high porosity and permeability reservoir, contained by one or more overlying low permeability formations. Sandstone reservoirs and associated cap-rocks of targeted CO2 storage sites therefore have distinct properties such as porosity and mineral contents. Their geochemical response or reactivity to injected supercritical CO2 and associated changes in porosity, and permeability affecting scaling, mineral trapping, injectivity, or migration can therefore be very different. Six drill core samples including quartz-rich sandstones, calcite cemented sandstones, and feldspar or clay-rich cap-rocks from a proposed demonstration site in the Surat Basin, Australia, were characterized before and after reaction with pure supercritical CO2 and low salinity formation water. The quartz-rich sandstones have low reactivity, and maintain high porosities with visible pore connectivity after reaction, they are unlikely to be affected by scaling. Kaolin and fine grain movement observed via μCT and SEM could have the potential to open or plug pores, potentially increasing or decreasing permeability and CO2 injectivity. Calcite cemented sandstones had the greatest measured change in porosity after reaction via calcite dissolution. Narrow angular channels were formed in the calcite cement around framework grains, extending through to the center of the sub-plug in the courser grained rock, and surface roughness increased. Solution pH was however quickly passivated. The highest concentrations of Ca, Mn, Sr, and Mg were released to solution from calcite dissolution. Clay (and feldspar) rich cap-rock core had mainly microporosity and the smallest initial pore throat diameters associated with clays. Small changes to μCT calculated porosities after reaction were related to a decrease in chlorite X-ray density, and dissolution of patchy carbonate minerals. Pores were disconnected in μCT images, except for some created horizontal connection along a sandy lamination in a cap-rock. Dissolved concentrations of Ca, Fe, Si, Sr, Mn, Li and Mg increased via dissolution of both carbonate and silicate minerals. Dissolved Ca, Fe, Mn and Mg from silicate minerals in the cap-rock were available for longer term mineral trapping of CO2. Potential increases in porosity and migration will be highest in the calcite cemented zones, while clay-rich cap-rocks could be expected to maintain integrity. There is a low likelihood of mineral trapping or scaling in the quartz rich lower Precipice Sandstone. Overlying rocks can provide Fe, Mg, Ca for mineral trapping of CO2 as ferroan carbonates such as siderite, ankerite and dolomite over longer time scales when pH is buffered.Changes to porosity, mineral content, and water chemistry after pure CO2 reaction observed here and in other published studies were dependent on mineral content and fluid accessibility. These results could be generalized to other sandstone reservoirs where it is expected to inject CO2. The results can also be used to validate geochemical models to build longer term predictions.

Impure CO2 reaction of feldspar, clay, and organic matter rich cap-rocks: Decreases in the fraction of accessible mesopores measured by SANS

During CO2 geological storage, low porosity and permeability cap-rock can act as a structural trap, preventing CO2 vertical migration to overlying fresh water aquifers or the surface. Clay and organic matter rich shales, fine-grained sandstones and mudstones often act as cap-rocks and may contain substantial sub-micron porosity. CO2-brine-rock interactions can open or close pore throats through dissolution, precipitation or migration of clay fines or grains. This could affect CO2 migration if the porosity is accessible, with unchanging or decreasing accessible porosity favourable for trapping and integrity. Two cap-rock core samples, a clay and organic-rich mudstone and a more organic-lean feldspar-rich fine grained sandstone, from a well drilled for a CO2 storage feasibility study in Australia were experimentally reacted with impure CO2 (+SO2, O2) and low salinity brine at reservoir conditions. Mercury injection capillary pressure indicated that the majority of pores in both cores had pore throat radii ~ 5–150nm with porosities of 5.5–8.4%. After reaction with impure CO2-brine the measured pore throats decreased in the clay-rich mudstone core. Dissolution and precipitation of carbonate and silicate minerals were observed during impure CO2 reaction of both cores via changes in water chemistry. Scanning electron microscopy identified macroporosity in clays, mica and amorphous silica cements. After impure CO2-brine reaction, precipitation of barite, Fe-oxides, clays and gypsum was observed. Ion leaching from Fe-rich chlorite was also apparent, with clay structural collapse, and fines migration. Small-angle neutron scattering measured the fraction of total and non-accessible pores (~10–150nm radii pores) before and after reaction. The fraction of pores that was accessible in both virgin cap-rocks had a decreasing trend to smaller pore size. The clay-rich cap-rock had a higher fraction of accessible pores (~0.9) at the smallest SANS measured pore size, than the feldspar rich fine-grained sandstone (~0.75). Both core samples showed a decrease in SANS accessible pores after impure CO2-water reaction at CO2 storage conditions. The clay-rich cap-rock showed a more pronounced decrease. After impure CO2-brine reaction the fraction of accessible pores at the smallest pore size was ~0.85 in the clay-rich cap-rock and ~0.75 in the feldspar-rich fine-grained sandstone. Reactions during impure CO2-brine-rock reaction have the potential to close cap-rock pores, which is favourable for CO2 storage integrity.

Mineralogical controls on porosity and water chemistry during O2-SO2-CO2 reaction of CO2 storage reservoir and cap-rock core

Reservoir and cap-rock core samples with variable lithology's representative of siliciclastic reservoirs used for CO2 storage have been characterized and reacted at reservoir conditions with an impure CO2 stream and low salinity brine. Cores from a target CO2 storage site in Queensland, Australia were tested. Mineralogical controls on the resulting changes to porosity and water chemistry have been identified. The tested siliciclastic reservoir core samples can be grouped generally into three responses to impure CO2-brine reaction, dependent on mineralogy. The mineralogically clean quartzose reservoir cores had high porosities, with negligible change after reaction, in resolvable porosity or mineralogy, calculated using X-ray micro computed tomography and QEMSCAN. However, strong brine acidification and a high concentration of dissolved sulphate were generated in experiments owing to minimal mineral buffering. Also, the movement of kaolin has the potential to block pore throats and reduce permeability. The reaction of the impure CO2-brine with calcite-cemented cap-rock core samples caused the largest porosity changes after reaction through calcite dissolution; to the extent that one sample developed a connection of open pores that extended into the core sub-plug. This has the potential to both favor injectivity but also affect CO2 migration. The dissolution of calcite caused the buffering of acidity resulting in no significant observable silicate dissolution. Clay-rich cap-rock core samples with minor amounts of carbonate minerals had only small changes after reaction. Created porosity appeared mainly disconnected. Changes were instead associated with decreases in density from Fe-leaching of chlorite or dissolution of minor amounts of carbonates and plagioclase. The interbedded sandstone and shale core also developed increased porosity parallel to bedding through dissolution of carbonates and reactive silicates in the sandy layers. Tight interbedded cap-rocks could be expected to act as baffles to fluids preventing vertical fluid migration. Concentrations of dissolved elements including Ca, Fe, Mn, and Ni increased during reactions of several core samples, with Mn, Mg, Co, and Zn correlated with Ca from cap-rock cores. Precipitation of gypsum, Fe-oxides and clays on seal core samples sequestered dissolved elements including Fe through co-precipitation or adsorption. A conceptual model of impure CO2-water-rock interactions for a siliciclastic reservoir is discussed.

Geomechanical characteristics of common reservoir caprock in Iran (Gachsaran Formation), experimental and statistical analysis

The evaporitic Gachsaran Formation consists of seven members with sequence of anhydrite, marl and salt layers. The first member (the lowest one) which is made up of anhydrite is known as the caprock of the Asmari carbonate reservoir, the most famous hydrocarbon reservoir in Iran. The geomechanical behavior of the Gachsaran Formation is the main concern of drilling and development operations in Iranian oil and gas fields. However, the chief problem is lack of deep core samples from Gachsaran sequences due to the challenging and costly coring process in the non-reservoir Gachsaran formation. In a practical approach of obtaining samples for essential geomechanical laboratory tests, caprock (anhydrite) core samples of Gachsaran Formation have been taken from depths of 80–300 m, at three dam sites. The rock physical and geomechanical properties were examined by analysis of variance (ANOVA) and Tukey's honestly significant difference (HSD) tests. The results from analysis of the properties of samples collected from Ghotvand and Chamshir dam sites showed no significant differences, but some of the characteristics of samples of Khersan dam site were considerably different from those of the other samples. Moreover, the physical properties of anhydrite samples were compared with the properties inferred from the petrophysical well logs from a depth of about 2000 m. It was demonstrated that the observed discrepancies between the measured values from Ghotvand and Chamshir samples and those from deep logs are not significant at the 95% confidence level. The investigation results illustrated that anhydrite samples taken from shallow depths can be used for evaluating the geomechanical properties of deeper anhydrites.

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.

Numerical Simulation of Permeability Change in Wellbore Cement Fractures after Geomechanical Stress and Geochemical Reactions Using X-ray Computed Tomography Imaging.

X-ray microtomography (XMT) imaging combined with three-dimensional (3D) computational fluid dynamics (CFD) modeling technique was used to study the effect of geochemical and geomechanical processes on fracture permeability in composite Portland cement-basalt caprock core samples. The effect of fluid density and viscosity and two different pressure gradient conditions on fracture permeability was numerically studied by using fluids with varying density and viscosity and simulating two different pressure gradient conditions. After the application of geomechanical stress but before CO2-reaction, CFD revealed fluid flow increase, which resulted in increased fracture permeability. After CO2-reaction, XMT images displayed preferential precipitation of calcium carbonate within the fractures in the cement matrix and less precipitation in fractures located at the cement-basalt interface. CFD estimated changes in flow profile and differences in absolute values of flow velocity due to different pressure gradients. CFD was able to highlight the profound effect of fluid viscosity on velocity profile and fracture permeability. This study demonstrates the applicability of XMT imaging and CFD as powerful tools for characterizing the hydraulic properties of fractures in a number of applications like geologic carbon sequestration and storage, hydraulic fracturing for shale gas production, and enhanced geothermal systems.

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 30days in contact with CO2 and 100ppm SO2 under in-situ conditions (300bar, 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 100ppmv SO2 with CO2.

Experimental investigation of porosity and permeability variations in reservoirs and caprock following co-injection of sulfur dioxide and hydrogen sulfide with carbon dioxide

Abstract Carbon dioxide (CO 2 ) capture, transport and storage (CCTS) in deep geological formations can mitigate the atmospheric concentration of greenhouse gases. Purity of this gas is an important aspect for CCTS since it drives up the cost of capture. When leaving some impurities from the flue gas in the CO 2 stream, a cost reduction may be achieved but the risks at transport and storage may increase. In order to investigate the effects of the possible impurities (H 2 S and SO 2 ) in the CO 2 stream during subsurface storage laboratory experiments were performed on Permian Rotliegend reservoir and Zechstein cap rock core samples from gas fields in northeast Netherlands. The rock samples were subjected for 30 days to static in situ conditions (300 bar, 100 °C) in the presence of brine and an injected gas mixture of CO 2 +100 ppm SO 2 +100 ppm H 2 S. Following injection of the mixture permeability of the reservoir and caprocks increased by a factor of 1.02–1.9 and 1.2–3.1, respectively. Although an enhanced level of anhydrite precipitation was observed, the increase in permeability of the samples show that dissolution of carbonate, feldspar and kaolinite minerals is dominant. In addition it was shown that the initial porosity–permeability relation of the samples remains valid to predict the behavior of the reservoir after injection of the gas mixture. For the caprock, the precipitation of anhydrites results in a less enhanced permeability than in the case of injection of pure CO 2 . This may lead to the conclusion that the addition of low quantities (100 ppm) of SO 2 and H 2 S in CO 2 during subsurface storage does not increase the risk of leakage through the Zechstein caprock more than when using pure CO 2 .

SO2 impurity impacts on experimental and simulated CO2–water–reservoir rock reactions at carbon storage conditions

Some industrial CO2 streams stored geologically may contain impurities including SO2, O2, and NOX. The impacts of these reactive gases in CO2–water–rock interactions have received limited attention relative to pure CO2 studies. An experimental and geochemical modelling study of reservoir and cap-rock core samples from a potential CO2 storage site in the Surat Basin, Queensland, Australia is described. Reservoir and cap-rock samples were reacted with low salinity fluid saturated with an impure CO2 stream containing 0.16% SO2 at reservoir simulated in situ conditions. This study is relevant to the storage of impure CO2 streams from industrial sources in sandstone reservoirs.Experimentally, dissolution of SO2 from the supercritical gas phase into the aqueous phase showed a kinetic control. The acidification from sulphuric acid generation, and the resulting silicate and carbonate dissolution were generally observed in all experiments. Significant dissolved cation concentrations in solution (up to ~843mg/kg) indicated a higher potential for CO2 trapping, especially from mineralogically reactive core samples. The extent of mineral dissolution was dependent on the rock mineralogy. Precipice Sandstone samples showed the lowest reactivity indicating its suitability as a reservoir unit. However this study indicates the potential for localised changes to water quality in the near wellbore region that necessitate further investigation. Corrosion of the carbonates calcite, siderite and ankerite, and silicates including iron-rich chlorite, plagioclase, and K-feldspar was observed on rock surfaces in potential seal rocks. Calcite cement partially dissolved and acicular gypsum precipitated on the surface of a sandstone formation that could act as a potential secondary sealing unit. The formation of dense sulphates may self-seal some cap-rock. Simulations showed a good history match with the experiments, with the main predicted reactive phases including calcite, ankerite, siderite and chlorite +/− Fe oxides on the time scale of the experiments. Redox potential of the system was important; where oxidised iron was present SO2 oxidation to sulphuric acid was predicted to dominate in the simulations; otherwise pyrite and elemental S formation were also predicted (as observed experimentally). The findings of this study are generally applicable to understanding likely impacts to water quality from impure CO2 injection in CCS sites in Australia and internationally. Data has been provided which may be used to improve longer term modelling predictions.

Wellbore cement fracture evolution at the cement–basalt caprock interface during geologic carbon sequestration

Composite Portland cement–basalt caprock cores with fractures, as well as neat Portland cement columns, were prepared to understand the geochemical and geomechanical effects on the integrity of wellbores with defects during geologic carbon sequestration. The samples were reacted with CO2–saturated groundwater at 50°C and 10MPa for 3months under static conditions, while one cement–basalt core was subjected to mechanical stress at 2.7MPa before the CO2 reaction. Micro-XRD and SEM–EDS data collected along the cement–basalt interface after 3-month reaction with CO2–saturated groundwater indicate that carbonation of cement matrix was extensive with the precipitation of calcite, aragonite, and vaterite, whereas the alteration of basalt caprock was minor. X-ray microtomography (XMT) provided three-dimensional (3-D) visualization of the opening and interconnection of cement fractures due to mechanical stress. Computational fluid dynamics (CFD) modeling further revealed that this stress led to the increase in fluid flow and hence permeability. After the CO2-reaction, XMT images displayed that calcium carbonate precipitation occurred extensively within the fractures in the cement matrix, but only partially along the fracture located at the cement–basalt interface. The 3-D visualization and CFD modeling also showed that the precipitation of calcium carbonate within the cement fractures after the CO2-reaction resulted in the disconnection of cement fractures and permeability decrease. The permeability calculated based on CFD modeling was in agreement with the experimentally determined permeability. This study demonstrates that XMT imaging coupled with CFD modeling represent a powerful tool to visualize and quantify fracture evolution and permeability change in geologic materials and to predict their behavior during geologic carbon sequestration or hydraulic fracturing for shale gas production and enhanced geothermal systems.

Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated With H2S Into Depleted Gas Fields in the Northeast of the Netherlands

Summary Depleted gas fields are among the most probable candidates for subsurface storage of carbon dioxide (CO2). With proven reservoir and qualified seal, these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine because of the formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and caprock. Thus, for adequate, safe, and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. To investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30-day) laboratory experiments (300 bar, 100°C) on reservoir and caprock core samples from gas fields in the northeast of the Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream [hydrogen sulfide (H2S)] in these fields. The injected gases—CO2, CO2+100 ppm H2S, and CO2+5,000 ppm H2S—were reacting with core samples and brine (81 g/L Na+, 173 g/L Cl−, 22 g/L Ca2+, 23 g/L Mg2+, 1.5 g/L K+, and 0.2 g/L SO42−). Before and after the experiments, the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. The permeability of the samples was also measured. After the experiments, dissolution of feldspars, carbonates, and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S to the CO2 stream. First, we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection, where dissolution of anhydrite was dominant in the samples. Second, severe salt precipitation took place in the presence of H2S. This is mainly caused by the nucleation of anhydrite and pyrite, which enabled halite precipitation, and to a lesser degree by the higher solubility of H2S in water and higher water content of the gas phase in the presence of H2S. This was confirmed by the use of CMG-GEM (CMG 2011) modeling software. The precipitation of halite, anhydrite, and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and ≤3%, respectively. In caprock samples, permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5,000 ppm H2S, the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, halite, anhydrite, and pyrite precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.

Geochemical and Geomechanical Effects on Wellbore Cement Fractures

Experimental studies were conducted using batch reactors, X-ray microtomograpy (XMT), and computational fluid dynamics (CFD) simulation to determine changes in cement fracture surfaces, fluid flow pathways, and permeability with geochemical and geomechanical processes. Composite Portland cement-basalt caprock core with artificial fractures was prepared and reacted with CO2-saturated groundwater at 50°C and 10 MPa for 3 to 3.5 months under static conditions to understand the geochemical and geomechanical effects on the integrity of wellbores containing defects. Cement-basalt interface samples were subjected to mechanical stress at 2.7 MPa before the CO2 reaction. XMT provided three-dimensional (3-D) visualization of the opening and interconnection of cement fractures due to mechanical stress. After the CO2 reaction, XMT images revealed that calcium carbonate precipitation occurred extensively within the fractures in the cement matrix, but only partially along fractures located at the cement-basalt interface. The permeability calculated based on CFD simulation was in agreement with the experimentally measured permeability. The experimental results imply that the wellbore cement with fractures is likely to be healed during exposure to CO2-saturated groundwater under static conditions, whereas fractures along the cement-caprock interface are still likely to remain vulnerable to the leakage of CO2. CFD simulation for the flow of different fluidsmore » (CO2-saturated brine and supercritical CO2) using a pressure difference of 20 kPa and 200 kPa along ~2 cm-long cement fractures showed that a pressure gradient increase resulted in an increase of CO2 fluids flux by a factor of only ~3-9 because the friction of CO2 fluids on cement fracture surfaces increased with higher flow rate as well. At the same pressure gradient, the simulated flow rate was higher for supercritical CO2 than CO2-saturated brine by a factor of only ~2-3, because the viscosity of supercritical CO2 is much lower than that of CO2-saturated brine. The study suggests that in deep geological reservoirs the geochemical and geomechanical processes have coupled effects on the wellbore cement fracture evolution and fluid flow along the fracture surfaces.« less

Experimental and Modelling Study of Storage of CO2 and Impurities in a Depleted Gas Field in Northeast Netherlands

Abstract In order to investigate the effects of impurities on subsurface storage of CO2, experiments were carried out on Permian Rotliegend reservoir and Zechstein caprock core samples at subsurface conditions of 300 bar and 100°C. The experiments were performed in the presence of brine and the following gas compositions: CO2, CO2+5000 ppm H2S, CO2+100 ppm H2S and CO2+100 ppm SO2 for a 30 day duration. Following CO2 injection, permeability of the reservoir and caprock samples increased by 10-30% and by a factor of 3-10 respectively. After co-injection of 5000 ppm H2S permeability of both reservoir and caprock samples reduced significantly. When the concentration of H2S was reduced to 100 ppm, minimal variation of permeability took place because the dissolution of minerals was balanced with the precipitation of secondary phases. In the case of co-injection of 100 ppm SO2 permeability of reservoir samples increased by a factor of 1.18 to 2.2. In the caprock samples permeability changed by a factor of 0.8 to 23. In addition, in order to determine long term (>100 years) interaction between CO2 and the reservoir mineralogy we need to rely on modelling programs. This requires accurate and fit for purpose input parameters, associated with the lithological composition of reservoirs and seals at the storage site. For this purpose, we specifically focused on the reactive surface area of minerals, which we measured by scanning electron microscopy. Using the range of measured reactive surface area of minerals as an input in the modelling software, we could obtain the distribution of the sequestered CO2 as a mineral (3-9 kg of CO2/m3).

Sayindere cap rock integrity during possible CO2 sequestration in Turkey

Abstract One way to reduce the amount of CO 2 in the atmosphere for the mitigation of climate change is to capture the CO 2 and inject it into geological formations. The most important public concern about carbon capture and storage (CCS) is whether stored CO 2 will leak into groundwater sources and finally into the atmosphere. To prevent the leakage, the possible leakage paths and the mechanisms triggering the paths must be examined and identified. It is known that the leakage paths can be due to CO 2 - rock interaction and CO 2 –well interaction. The objective of this research is to identify the geochemical reactions of the dissolved CO 2 in the synthetic formation water with the rock minerals of the Sayindere cap rock by laboratory experiments. It is also aimed to model and simulate the experiments using ToughReact software. Sayindere formation is a regionally extensive cap rock for many oil fields in southeastern Turkey. The mineralogical investigation and fluid chemistry analysis of the experiments show that calcite was dissolved from the cap rock core as a result of CO 2 -water-rock interaction. Using the reactive transport code TOUGHREACT, the modeling of the dynamic experiment is performed. Calcite, the main primary mineral in the Sayindere is dissolved first and then re-precipitated during the simulation process. The decreases of 0.01% in the porosity and 0.03% in permeability of the packed core of the Sayindere cap rock are observed in the simulation. The simulation was continued for 25 years without CO 2 injection. However, the results of this simulation show that the porosity and permeability are increased by 0.001% and 0.004%, respectively due to the CO 2 -water-rock mineral interaction. This shows that the Sayindere cap rock integrity must be monitored in the field if application is planned.

99/01601 Emission and immission development at the Schwarze Pumpe site, Germany : Schoenherr, D. and Mueller, W. Braunkohle, 1998, 50, (3), 245–250. (In German)

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.