Caprock Thickness Research Articles

Caprock sealing integrity and key indicators of CO2 geological storage considering the effect of hydraulic-mechanical coupling: X field in the Bohai Bay Basin, China

Caprock sealing efficiency is an essential guarantee for the long-term safety and stability of CO2 geological storage (CCS). However, the uncertainty in the physical and mechanical properties of deep formations poses challenges to accurately predict the risks of CO2 leakage resulting in CO2 breakthrough or caprock fracture. This study aims to address the issue of imperfect key indicators for caprock sealing by focusing on the CCS project in the Bohai Bay Basin, China. A hydraulic-mechanical (HM) coupling program without considering multiphase flow and the chemical reactions is secondary developed based on the finite element software ABAQUS. Furthermore, a three-dimensional finite element numerical model is established for the analysis of HM coupling, with pore pressure increment (∆PP), Coulomb failure stress (∆CFS) and displacement (U) as evaluation criteria. The Tornado analysis and response surface analysis are employed to analyze the impact of 17 indicators on the caprock sealing, including caprock thickness, burial depth, reservoir and caprock permeability parameters, and mechanical parameters. Subsequently, key performance indicators for caprock sealing are determined. The research results indicate that the reservoir permeability, injection rate, caprock permeability, caprock Young's modulus, caprock internal friction angle, caprock Poisson's ratio, and caprock burial depth are key indicators of caprock sealing capability. The reservoir permeability has a greater impact sensitivity compared to the caprock permeability. Pore pressure and displacement increase with increasing in reservoir permeability. The caprock's resistance to deformation and fracturing increases with increasing in Young's modulus and Poisson's ratio of caprock. This study provides valuable insights for evaluating caprock sealing during CO2 storage in saline aquifers.

Key indicators of caprock sealing assessment with consideration of faults in potential CO2 geological storage sites in Subei Basin, China

Good caprock sealing is crucial for ensuring the long-term safety and security of carbon dioxide (CO2) geological storage. However, concealed faults within caprocks and reservoirs can impact the transport and accumulation of CO2 plumes. Due to the uncertainties associated with the geometric structure, physical properties, and combined relationships among reservoir, caprock and fault, accurately evaluating caprock sealing is challenging. To address the challenge of identifying key indicators for caprock sealing considering faults, this study focuses on the one potential CO2 geological storage field in the Subei Basin, China. First, this study establishes a hydraulic-mechanical (HM) coupled finite element model considering a combination of caprock, reservoir and fault. Then, 22 research indicators, including fault offset, fault dip, caprock thickness, burial depth, permeability and mechanical properties, are analysed to evaluate their influence on caprock sealing via the tornado analysis and response surface methods. Finally, key indicators are determined based on evaluation criteria, such as pore pressure increment (ΔPP) and Coulomb failure stress (CFS), in the fault plane. The research results indicate that fault dip, fault offset, fault permeability, burial depth, and reservoir permeability are key indicators. The caprock thickness, caprock permeability, and caprock Young's modulus significantly influence the caprock sealing capacity. The ΔPP and CFS increase with increasing fault dip and offset. When the fault dip exceeds 45°, the ΔPP and CFS reach maximum values at the interface between the reservoir and caprock. Fault permeability has a greater impact than reservoir permeability and caprock permeability. The research results may provide guidance for the evaluation of caprock sealing capacity for CO2 geological storage.

Sedimentological and petrophysical characterization of the Bokabil Formation in the Surma Basin for CO2 storage capacity estimation

Large-scale geological sequestration of CO2 is one of the most effective strategies to limit global warming to below 2 °C, as recommended by the Intergovernmental Panel on Climate Change (IPCC). Therefore, identifying and characterizing high-quality storage units is crucial. The Surma Basin, with its four-way dip closed structures, high-quality reservoirs, and thick regional cap rocks, is an ideal location for CO2 storage. This study focuses on the Bokabil Formation, the most prominent reservoir unit in the Surma Basin. Detailed petrographic, petrophysical, XRD, and SEM analyses, along with mapping, have been conducted to evaluate the properties of the reservoir and cap rock within this formation. The Upper Bokabil Sandstone in the Surma Basin ranges from 270 to 350 m in thickness and consists of fine- to medium-grained subarkosic sandstones composed of 70–85% quartz and 5–12% feldspar, with good pore connectivity. Petrophysical analysis of data from four gas fields indicates that this unit has a total porosity of 21–27.4% and a low shale volume of 15–27%. Cross plots and outcrop observations suggest that most of the shales are laminated within the reservoir. The regional cap rock, known as the Upper Marine Shale (UMS), ranges in thickness from 40 to 190 m and contains 10–40 nm nano-type pores. A higher proportion of ductile materials with a significant percentage of quartz in the UMS indicates higher capillary entry pressures, enhancing its capacity to hold CO2. Using the CSLF method with a 6% cut-off of the available pore volume, it is estimated that 103 Mt, 110 Mt, 205 Mt, and 164 Mt of CO2 can be effectively stored in the Sylhet, Kailashtila, Habiganj, and Fenchuganj structures, respectively. Due to the shallow depth of the storage unit and the thick cap rock, the southern Surma Basin is the optimal location for CO2 injection.

Morphogenesis of Hollow Bulbous Gypsum Structures Along a Brine Spring in Northeast Alberta

Abstract The stromatolite tufa mound at La Saline Lake developed along the Athabasca River Valley in northeast Alberta consists of a 30 m-high structure with a multi-meter thick caprock of stratified gypsum. The gypsum caprock developed when the meteoric-charged groundwater channeled along shallowly buried Upper Devonian limestone was redirected deeper and encountered anhydrite beds of the Middle Devonian Prairie Evaporite Formation, only 175–200 m below. Discharge of the sulfate-saturated brine from the central vent of the gypsum caprock eventually ceased and the flow was redirected to the western lakefront bank of the tufa mound. This active brine spring, characterized by total dissolved solids level of ∼79,000 mg/L, is channeled along a 25 m gully toward La Saline Lake. The bottom sediment in each of the interconnected brine pools along the gully consists of a 2–4 cm-thick calcite-gypsum thrombolite and an overlying gypsum crust. This sulfate crust developed as densely packed arrays of hollow botryoidal to hemispheroidal and bulbous gypsum protuberances, each 0.5–1.5 cm long, that extend upward into the brine. This is the first documented example of bulbous protuberances of gypsum that developed within brine pools with hollow interiors. The unusual hollowness of these bulbous gypsum protuberances resulted from the rapid encasement of gas bubbles that ascended from the underlying thrombolite ooze and were trapped within the overlying microbial mats and meshwork of gypsum crystallites on the surface of the bottom pool sediment. Nanoscale biomineralization of gypsum developed along the parallel arrays of microbial stalks within the enveloping mat, resulting in a meshwork of parallel aligned crystallites that encased the surfaces of the trapped bubbles. Continued abiotic gypsum precipitation transitioned the abiotic crystallites into enlarged needle-form crystallites distributed as parallel arrays along curvilinear growth surface laminae. Sufficient rigidity on the bubble surfaces precluded implosion-collapse or detachment. Strontium adsorption widely stabilized the acicular crystals, inhibiting complete coalescence as gypsum spar.

Effect of intensity of sedimentary cover deformation on hydrocarbon accumulation in Dongying Sag, Bohai Bay Basin, China

The developmental phase of the fault deformation zone denotes the zone of weak deformation (with strong concealment) that evolves within the sedimentary cover of the basin. Recent studies have unveiled the objectively existing tectonic phenomenon of weakly deformed tectonic belts within the sedimentary basin cover, closely intertwined with oil and gas accumulation. To elucidate the deformation intensity and hydrocarbon accumulation scale within the cap cover deformation zone, a pivotal concern in oil and gas geology, this study focuses on the Dongying Sag. The structural physical simulation experiment method, incorporating variable caprock thickness and variable shear strength, is employed to scrutinize the impact of basement fault strike-slip activity on the development of faults in the sedimentary caprock of the basin and dyed oil is charged. In conjunction with sag examples, Early R shear single-channel migration-isolated aggregation, Early and mid-term R shear main channel migration-geese and beaded aggregation, P shear main channel migration-intermittent zonal aggregation, Full channel migration-continuous belt aggregation accumulation models of basement faults are established. It is emphasized that the R shear pressurized deformation section and the R and P shear intersection section in the deformation zone are favorable target areas for oil and gas exploration.

Feasibility Assessment of Acid Gas Injection in an Iranian Offshore Aquifer

Acid gas injection operations function as the commercial equivalent of certain aspects within the realm of geological CO2 storage. Acid gas, composed of H2S and CO2, alongside minor quantities of hydrocarbon gases stemming from either petroleum production or processing, constitute the composition of acid gas. The primary aim of acid gas injection operations lies in the disposal of H2S. Nevertheless, substantial volumes of CO2 are concurrently injected due to the economic impracticality of segregating the two gases. This investigation delves into the comprehensive, step-by-step procedure that can be employed to determine the suitability of a field or formation for acid gas injection, utilizing all accessible data, including the literature and data from neighboring fields. This approach incorporates sensitivity analysis of various parameters to ascertain the feasibility of AGI while minimizing costs and time consumption. The focus of this study centers on evaluating the feasibility of Acid Gas Injection (AGI) in a saline aquifer offshore in Iran. The assessment encompasses the examination of reservoir properties, geomechanical aspects, caprock integrity, and gas plume dynamics. The Surmeh formation emerges as a promising candidate for AGI due to the presence of upper dolomite and lower carbonate within the rock formations. Geomechanical analysis reveals a pore pressure of 3800 psi and a fracture pressure of 6100 psi. Caprock integrity, particularly within the Hith formation, emerges as pivotal for both containment and long-term stability. Seismic mapping highlights variations in caprock thickness, influencing containment effectiveness. Capillary trapping emerges as a significant factor in short-term gas entrapment and plume distribution. Numerical simulations elucidate the impact of heterogeneous rock properties on capillary trapping and gas plume movement. The projection estimates approximately 2 TCF (Trillion Cubic Feet) of acid gas injection into the Surmeh formation. Based on the acid gas content and the gas in place at the source of injection, the recommended injection rate stands at 180 MMSCFD (million standard cubic feet per day). The formation’s inherent tightness limits injectivity, allowing for a maximum achievable rate of 7 MMSCFD with a permeability of 1 mD (millidarcy). However, a higher porosity (12%) and a permeability of 100 mD enable more efficient injection without fracturing the formation. To achieve this, it becomes imperative to implement two injection wells, each with a capacity of 90 MMSCFD.

Analytical model for CO2 geo-sequestration in deep saline aquifers considering the effect of heterogeneity and matrix-fracture interaction

Deep saline aquifers are considered to be the best storage option for long-term CO2 geo-sequestration because such geological formation has the largest identified storage potential that can securely trap CO2 under its low-permeability caprock layers. Many analytical models have been proposed to rapidly detect the CO2 leakage from the storage aquifers. However, the heterogeneity and matrix-fracture interaction of storage layers have not been taken into consideration in previous studies. In this paper, we develop an analytical model to determine the dimensionless leakage rate and pressure build-up due to CO2 leakage from the heterogeneous, dual-porosity and multi-layer bounded storage aquifer. Based on the model description and assumptions, the analytical solution is obtained by means of dimensionless transformation, Laplace transform and numerical inversion. Afterwards, our model is verified by comparing with existing analytical model. In order to determine the effect of heterogeneity and the matrix-fracture interaction on the dimensionless leakage rate and pressure change, we conducted sensitivity analysis taking account of the heterogeneous factors. Based on the obtained results, increasing layer number and layer thickness from the bottom layer to the upper layer will delay the CO2 leakage. Furthermore, each layer in storage aquifer with greater fluid mobility is not conductive to CO2 storage but the overall effect is not obvious. As for the matrix-fracture fluid transfer processes, when the ratio of the matrix permeability to the fracture permeability is small, the fast flow of CO2 through the fracture system without significant storage in the matrix. Obviously, the resistance along the leakage path is decreasing with the decrease of the caprock thickness, which leads to greater leakage between the two aquifers. The derived analytical solutions considering heterogeneity and dual media is practical and helpful for CO2 geo-sequestration site selection and storage risk assessment.

The Application of the Fuzzy Comprehensive Evaluation Method in the Sealing Evaluation of Caprocks in Underground Gas Storage

The good sealing caprocks are significant for the integrity of underground gas storage (UGS) in depleted natural gas reservoirs. The screening of parameters, weight assignment, and evaluation method are important for evaluating the sealing performance of caprocks. Many factors can affect the sealing performance of caprocks, including caprock thickness, lithology, brittleness, porosity and permeability, breakthrough pressure, etc. In this paper, the dominant factors in the sealing performance of caprocks in UGSs are systematically analyzed, and the weights of these factors are analyzed by the analytic hierarchy process (AHP). The fuzzy comprehensive evaluation method (FCEM) is applied in the sealing evaluation of caprocks in three typical underground gas reservoirs (i.e., Zhujiadun, Xu-2, and Xing-9) in China. The sandstone reservoir in the Zhujiadun gas field is only about 20 m, and the thickness of the overlying mudstone is about 600 m. The caprock of the Xu-2 gas reservoir in Zhongba gas field is well distributed and developed, and the breakthrough pressure is relatively large. The caprock of Xing-9 gas field is mudstone with a thickness of over 400 m. The results show that the breakthrough pressure and permeability are the key parameters affecting the sealing ability of caprocks, with weights of 0.4291 and 0.2157, respectively. Among these three examples of gas fields, the sealing performance of caprocks in Zhujiadun gas storage is the best. The evaluation procedure and methods proposed in this paper are valuable for the evaluation of the tightness of caprocks in depleted gas reservoirs.

Migration characteristics and local capillary trapping mechanism after the CO2 leakage out of saline aquifers

CO2 may leak from the wellbore, cross-section of faults, fractures, and pore space due to geological tectonic activity or human-induced activity during the CO2 geological storage in deep saline aquifers. To evaluate the CO2 leakage risk and select safe saline aquifers, it is necessary and crucial to predict the CO2 migration characteristics and trapping mechanism after its leakage. Although some previous studies have shown that heterogeneous capillary pressure can change CO2 migration path, its impact on the migration and storage after CO2 leakage is still unclear. Therefore, a simulation model of CO2 leakage and migration in saline aquifers is established by adopting stochastic modeling in geology and two-phase seepage modeling in the fluid. Based on the model, the influence of capillary pressure heterogeneity and caprock factors (thickness and leakage area) on the leaked CO2 migration, distribution, and trapping is analyzed quantitatively. The research result shows that heterogeneous capillary pressure in the saline aquifers can effectively trap the leaked CO2 and enlarge the lateral swept volume of leaked CO2. With the increase of capillary pressure and its heterogeneity, the upward migration of CO2 slows down but the local capillary trapping increases. Both of these can weaken the risk of CO2 leakage to the surface. Under the local capillary trapping above and below the caprock, the increasing of caprock thickness and leakage area have little effect on CO2 leakage amount, but may increase the local capillary trapping and make the formation safer. Therefore, priority should be given to selecting saline aquifers with thicker caprock to reduce the potential risk of CO2 leakage. In order to ensure the safety of CO2 storage, a saline aquifer with strong capillary pressure heterogeneity and good trapping performance should be selected.

Characteristics of the stratigraphic reservoirs and caprocks of the geothermal resources in the Northwestern Shandong region

The genetic relationships between the stratigraphic textures, thickness changes, burial depths, and the characteristics of the geothermal zoning of the Cenozoic in the northwestern Shandong region were analyzed in this study. Methods involving segmented water temperature measurements of geothermal well drilling, wellhead hydrological surveys, geothermal reservoirs, and caprock thickness measurements and statistics were adopted. The following findings were revealed in this study's research results: (1) The Paleogene and Neogene reservoir types in the northwestern Shandong region were determined to be mainly water-bearing fine sandstone and medium-fine sandstone pores, with thick layered, interbedded, and zoned stratigraphic structures. The layered and zoned geothermal reservoirs were found to be primarily distributed in a zonal manner on the bedding plane and characterized by good regional continuity. The fine sandstone and medium-fine sandstone sections with well-developed pores and high water content levels were geothermal reservoirs, while mudstone sections were geothermal barriers. The reservoirs and barriers were characterized by interlayer structures; (2) The boundary between the sag basin and the uplifting was taken as the dividing line of the geothermal fields, and the geothermal areas in the northwestern Shandong region were divided into different geothermal fields, all belonging to the sedimentary basin's conductive geothermal resources; (3) The major geothermal reservoirs included the lower members of the Neogene Minghuazhen Formation, Guantao Formation, and Dongying Formation. The Quaternary argillaceous sediment and the mudstone in the upper member of the Minghuazhen Formation formed the caprocks in the study area. In this study, the macroscopic distribution laws of geothermal resources in the northwestern Shandong region were proposed and were considered to have practical significance for further exploration and development.

Comprehensive Evaluation of the Hydrocarbon Preservation Conditions in the Complex Tectonic Area of the Southwestern Sichuan Basin, China

There are various styles of faults, folds, and unconformity structures in the southwestern Sichuan Basin, which have an important impact on hydrocarbon preservation. Based on the data of regional geological, seismic, formation water characteristics, caprock characteristics, and production, the hydrocarbon preservation conditions of the key horizons (Cambrian, Upper Permian, and Triassic) were analyzed. Southwestern Sichuan Basin margin structure has two obvious tectonic layers (the upper and lower). The upper tectonic layer is dominated by Middle Triassic detachment faults and derived thrust faults, while the lower tectonic layer has concealed structures composed of basement detachment faults and derived thrust faults. There are mainly NE, near-SN, NW, and near-EW faults. The outcrops are in the Middle-Cenozoic strata, changing from old to new from outside the Basin to inside the Basin. There are three main sets of high-quality caprocks, i.e., the mudstone of the bottom of the Xujiahe Formation, the gypsum-salt rocks of the Middle-Lower Triassic, and the Lower Cambrian mudstone. Based on the faults, outcrops, formation water type, mineralization, and caprock characteristics, the hydrocarbon preservation evaluation system was established, which divides into the areas of Class I, II, and III. The distribution range of the favorable areas of different horizons has good inheritance, and the hydrocarbon preservation conditions gradually improve from outside the basin to inside the basin. Class I favorable areas are the most widely distributed and are mainly located within the basin, with the characteristics of a low degree of fault development, relatively new outcropping strata, CaCl2 formation water type, and large caprock thickness.

Quantitative evaluation and models of hydrocarbon accumulation controlled by faults in the Pearl River Mouth Basin

The Pearl River Mouth Basin is the largest petroliferous basin in the northern South China Sea, where hydrocarbon accumulation is strongly controlled by fault activities. This study performed the quantitative evaluation of the effects of faults on hydrocarbon migration and accumulation in the basin. The results indicate that the critical values of vertical migration of middle-shallow hydrocarbon, including the active strength of faults and the ratio of fault throw to shale caprock thickness, were up to 10 m/Ma and 5, respectively. The lateral hydrocarbon migration efficiency of the unbreached relay zone was higher than that of the barely breached and strongly breached types. The lower critical value of shale gouge ratio for the clay sealing efficiency was 0.32. Additionally, the zones with the EW-trending transtensional faults were found to have unique dual functions of migration and stress sealing, suggesting that the linking fault positions play important roles in the lateral migration of hydrocarbons. Finally, seven hydrocarbon accumulation models controlled by faults in different tectonic settings were constructed to clarify the effects of faults on the vertical and lateral migrations of hydrocarbon. These models suggested that fine hydrocarbon exploration should be undertaken in the northeastern Baiyun Sag, and that middle-deep hydrocarbon exploration should be enhanced in the Enping, Huizhou, and southwestern Baiyun Sags. Cited as: Peng, G., Wu, Z., Dai, Y., Zhang, L., Yu, S., Wang, W., Pang, H. Quantitative evaluation and models of hydrocarbon accumulation controlled by faults in the Pearl River Mouth Basin. Advances in Geo-Energy Research, 2023, 8(2): 89-99. https://doi.org/10.46690/ager.2023.05.03

Sealing of oil-gas reservoir caprock: Destruction of shale caprock by micro-fractures

The sealing ability of caprock is affected by many factors, such as cap thickness, displacement pressure, fracture development, and lithology of caprock. Shale is one of the ideal materials for oil and gas sealing cap formation due to its low porosity and permeability. Microfractures can destroy the sealing property of shale caprock. When buried deep enough, shale will change from toughness to brittleness. In general, the greater the brittleness of shale, the more developed the fractures will be. In areas with high tectonic stress, such as the anticline axis, syncline axis and stratum dip end, the strata stress is high and concentrated, and it is easier to generate fractures. When the stress state of the caprock changes, new micro-cracks are formed or previously closed cracks are re-opened, reducing the displacement pressure of the caprock. These micro-fractures are interconnected to form microleakage spaces, which reduces the sealing capacity of the caprock.

A fuzzy bayesian network based method for CO2 leakage risk evaluation during geological sequestration process

CO2 leakage risk is a critical threat to a safe and long-term storage of CO2 in the underground space. However, there is a lack of effective risk assessment methods for CO2 leakage in the storage system. In this paper, a novel method is constructed in which Fuzzy Set Theory (FST) and Bayesian Network (BN) are incorporated to evaluate CO2 leakage risk. Firstly, a Bayesian Directed Acyclic Graph, or BDAG, is constructed after analysis of the storage system failure mechanism including wellbore integrity, caprock integrity and the entire storage system, induced by different factors. Secondly, the priori probability and Conditional Probability Table, or CPT, of nodes in BN model are obtained by defuzzification of the fuzzy number given by experienced experts. Finally, the probability of CO2 leakage and the potential sources of damage is analyzed based on the posteriori probability of the Fuzzy Bayesian Network model, or FBN. A case study shows that under the condition of different combinations of parameter values of root nodes, the probability of leakage of the entire storage system (leaf node) ranges from 13% to 74%, and the leakage probability through wellbore is higher than that through caprock, which are both intermediate nodes. A sensitivity analysis is also conducted to study the influence of these variables on CO2 leakage probability. The ranking of CO2 leakage risk factors from strong to weak is cementing quality, cement corrosion, Net-to-Gross ratio, and caprock thickness, respectively. Moreover, the FBN model can also help to look for the risk sources of the CO2 storage system by posteriori probability calculation. In our case, the CO2 leakage risk source is mainly the wellbore with poor cementing quality, which should be paid more attention during operation.

Capacity Analysis and Understanding of Pilot Test Well in Gas Storage A

There is a relatively simple gas reservoir structure in gas storage A, with good trap sealing, large cap rock thickness, relatively inactive fault activity, good overall reservoir connectivity, large storage capacity, water invasion occurs in only a few wells in the low part of the structure, so there are the geological conditions for building gas storage reservoir. This paper analyzed the capacity and maximum recovery capacity of horizontal wells in this block, and the pressure influence range during the recovery process of high-speed pilot production through the pilot test of reservoir construction; moreover, it got the following understanding: the horizontal wells with good development effect, high recovery capacity, and the pressure influence range in this block are mainly within 400m from the well distance; there are differences in the gas production capacity of different types of reservoirs, and the capacity contribution of Class I reservoirs is large, while the capacity contribution of Class II and III reservoirs is small, together these believe that Shengping gas storage has the capacity conditions for building reservoir.

Evolution process and factors influencing the tight carbonate caprock: Ordovician Yingshan Formation from the northern slope of the Tazhong uplift, Tarim Basin, China

The tight limestone of the Yingshan Formation (Ordovician) is a local tight carbonate caprock in the Ordovician Tarim Basin. It vertically overlaps with the hydrocarbon reservoirs. The diagenesis and evolution processes affect the closure of this type of caprock, but it has been scarcely studied. This research utilized detailed laboratory experiments such as thin section study, cathodoluminescence (CL) examination, isotopic analysis (carbon, oxygen, and strontium isotopes), fluid inclusion, and the well-logging data to evaluate the evolution process and factors influencing the tight carbonate caprock of the Ordovician Yingshan Formation from the northern slope of the Tazhong uplift, Tarim Basin, China. The tight carbonate rocks of the Yingshan Formation in the study area are mainly composed of micrite and grainstone. The caprock thickness of the upper Ying 1 and the upper Ying 2 members of the Yingshan Formation are 15–44 m and 8–80 m, respectively, showing good continuity. However, the seal rocks in the other members of the Yingshan Formation are discontinuous. Low energy facies zone, vertical vadose zone, slow flow zone, and zone with weak tectonic destruction are the main areas of caprock distribution. Karstification in the epigenetic stage and cementation in the burial stage are the crucial factors affecting the evolution and distribution of carbonate seal rocks. Paleogeomorphology, phreatic surfaces, original sedimentary environment, and fault distribution influence the karstification, thus enhancing the macro heterogeneity of caprock. Cementation is controlled by buried fluids (formation water, hydrocarbons, hydrothermal fluid) and improves the micro sealing of the caprock. Multistage tectonic movements and changes in the fluid environment constantly change the sealing property of the caprock, and the reservoir and seal rock can transform each other in the process of evolution. These results suggest carbonate reservoirs evaluation can thus be enhanced by combining caprock evolution to analysis effectiveness. This research explains the mechanism of the spatial distribution of carbonate caprocks and provides the theoretical basis for carbonate reservoirs exploration.

Quantitative Evaluation of Gypsum-Salt Caprock Sealing Capacity Based on Analytic Hierarchy Process—A Case Study from the Cambrian in the Tarim Basin, Western China

Gypsum-salt caprock is one of the most important caprocks in petroliferous basins around the world. Its sealing capacity extremely affects hydrocarbon accumulation and distribution. However, there are numerous variables that affect caprock sealing performance, making a quantitative evaluation challenging. The analytic hierarchy process (AHP), which has the advantage of turning several influencing factors into multi-level single objectives, can be utilized in this context to quantify the weight of each element impacting caprock sealing capacity. As a result, using the Tarim Basin’s Cambrian as an example, this article quantitatively assessed the gypsum-salt caprock sealing capacity using AHP. The results show that factors affecting the sealing capacity of Cambrian gypsum-salt caprock in the Tarim Basin can be summarized into three major categories and nine sub-categories, including the lithology (rock assemblage type and lithology zoning), the thickness (total thickness of thick single layer, maximum thickness of thick single layer, total thickness, and ratio of caprock to stratum), and the mechanical properties (internal friction coefficient, compressive strength, peak strength). The sealing ability evaluation index (C) was created by applying AHP to quantify a number of different characteristics. The capacity of the caprock to seal is inversely correlated with the C-value. The value of C in the plane climbs consistently from Tabei to Tazhong and subsequently to the Bachu region, indicating a steady improvement in caprock sealing ability. Additionally, the evaluation’s findings are in line with how hydrocarbon accumulations are currently distributed. Furthermore, hydrocarbons are mostly distributed in subsalt and subsalt-dominated layers when C is greater than 2. On the contrary, hydrocarbons are mainly distributed in post-salt layers when C is less than 2. Furthermore, in areas affected by faults, hydrocarbons are favorably distributed in subsalt layers when C reaches 2, and fault activity is poor or strong in the early period and weak in the late period.

The control effect of normal faults and caprocks on hydrocarbon accumulation: A case study from the Binhai fault nose of the Huanghua Depression, Bohai Bay Basin, China

An exploration breakthrough was made in the Paleogene strata in the Binhai fault nose of the Huanghua Depression, but the distribution of hydrocarbons remained insufficient to understand. A series of fault-controlled traps were formed around the Gangdong fault, especially a large number of fault-block traps, which gave us a unique opportunity to use seismic data to study the distribution of the hydrocarbons under the control of normal fault and caprocks. By analysing the vertical and lateral changes of the fault throws (T-x and T-z plots), combined with the expansion index (EI), the characteristics of the Gangdong fault were studied and the evolution process of the fault was reconstructed. The fault has undergone the evolution process of lateral and dip linkage, and finally, the Gangdong fault was formed. The reconstruction of the evolution process and determination of charging stages found that the Gangdong fault was formed dip linkage just before late Neogene, providing an excellent vertical pathway for hydrocarbon migration. Besides, when the fault throw exceeds than 39 m, hydrocarbons were found near the fault, indicating a lower limit of fault throw. However, there were differences in the spatial distribution of hydrocarbons in the study area, which may be related to the integrity of the caprock. A lower thickness limit was found by analysing the relationship between the difference in hydrocarbon distribution above and below the regional caprock and the effective caprock thickness. When the effective caprock thickness is greater than this lower thickness limit, hydrocarbons can only accumulate below the caprock. When the effective caprock thickness is less than this lower limit, there is hydrocarbon accumulation above the caprock. This work highlights the evolution of normal fault and the control effect of fault-caprocks on hydrocarbon accumulation and further understands the spatial distribution of petroleum near the fault.

Prediction Method of Sealing Capacity Distribution of Regional Mudstone Caprocks Damaged by Fault During the Hydrocarbon Accumulation Period

In order to study the distribution law of oil and gas above and below the regional mudstone caprocks damaged by fault in petroliferous basins, based on the study of the sealing mechanism and degree of regional mudstone caprocks damaged by fault during the hydrocarbon accumulation period, the paleo-juxtaposition thickness of regional mudstone caprock was calculated by determining the paleo-fault throw of faults and the paleo-thickness of regional mudstone caprocks during the hydrocarbon accumulation period. According to the relation between the paleo-juxtaposition thickness of regional mudstone caprocks at known well points in the study area and the distribution of oil and gas above and below the regional mudstone caprock, the maximum juxtaposition thickness required for the upper and lower connection of the fault-associated fracture zone in the regional mudstone caprock was determined. On this basis, a set of prediction methods for the sealing capacity of regional mudstone caprocks damaged by fault during the hydrocarbon accumulation period was established. Then, this method was applied to the prediction of the damage degree distribution of the Zhangdong Fault to the regional mudstone caprock of the middle sub-member of the first member of the Shahejie Formation in the middle and late depositional periods of the Minghuazhen Formations in Qikou Sag of the Bohai Bay Basin during the hydrocarbon accumulation period. The results show that the damage degree of the Zhangdong Fault to the regional mudstone caprock of the middle sub-member of the first member of the Shahejie Formation during the hydrocarbon accumulation period is large. The largest damage appears in the east, with an a-value greater than 1, followed by the west, with an a-value between 0.5 and 1. The relatively minor damage occurs in the middle west part, with an a-value less than 0.5. The middle part is conducive to the accumulation and preservation of oil and gas generated from the source rock of the underlying third member of the Shahejie Formation, which is consistent with the fact that oil and gas discovered in the lower sub-member of the first member of the Shahejie Formation near the Zhangdong Fault are mainly distributed in its middle part. It shows that this method is feasible to predict the damage degree distribution of regional mudstone caprocks during the hydrocarbon accumulation period.

Influence of Depositional and Diagenetic Processes on Caprock Properties of CO2 Storage Sites in the Northern North Sea, Offshore Norway

Characterization of caprock shale is critical in CO2 storage site evaluation because the caprock shale acts as a barrier for the injected buoyant CO2 plume. The properties of shales are complex and influenced by various processes; hence, it is challenging to evaluate the caprock quality. An integrated approach is therefore necessary for assessing seal integrity. In this study, we investigated the caprock properties of the Lower Jurassic Drake Formation shales from the proposed CO2 storage site Aurora (the Longship/Northern Lights CCS project), located in the Horda Platform area, offshore Norway. Wireline logs from 50 exploration wells, various 2D seismic lines, and two 3D seismic cubes were used to investigate the variations of the caprock properties. The Drake Formation was subdivided into upper and lower Drake units based on the lithological variations observed. Exhumation and thermal gradient influencing the caprock properties were also analyzed. Moreover, rock physics diagnostics were carried out, and caprock property maps were generated using the average log values to characterize the Drake Formation shales. In addiiton, pre-stack seismic-inverted properties and post-stack seismic attributes were assessed and compared to the wireline log-based analysis. The sediment source controlled at 61° N significantly influenced the depositional environment of the studied area, which later influenced the diagenetic processes and had various caprock properties. The upper and lower Drake units represent similar geomechanical properties in the Aurora area, irrespective of significant lithological variations. The Drake Formation caprock shale near the injection site shows less-ductile to less-brittle brittleness values. Based on the caprock thickness and shaliness in the Aurora injection site, Drake Formation shale might act as an effective top seal. However, the effect of injection-induced pressure changes on caprock integrity needs to be evaluated.