Carbonate Caprock Research Articles

Quantification of hydrogen depletion and mineral reactivity in underground hydrogen storage reservoirs

The utilisation of renewable energy has surged over the past decades due to shifts in climate patterns and the diminishing reserves of fossil fuels. Among the renewables, hydrogen energy has emerged as a promising clean energy carrier in recent years. In the hydrogen industry, storage faces a notable hurdle due to the relatively low density of hydrogen gas (0.0813 kg/m³ at 25 °C and 1 atm) and its lower storage density (7–27 kg/m³ at 25 °C and 100–400 atm). As a potential remedy, underground hydrogen storage emerges as a viable option, even though it is not without its challenges. Among these challenges, a prominent one involves the diversity in the composition and physical properties of the reservoir due to the influence of both biological and geo-chemical reactions. In this study, an extensive modelling effort was undertaken to gain insights into the impact of both bio and geo-chemical reactions, variations in porosity, hydrogen depletion, and the effects of diffusion across various levels of salinity, pressure, and temperature. Diverse Water/Rock ratios, distinct minerals, and residual gases were also considered. The modelled conditions encompassing mineral properties and parameters led to a cumulative hydrogen loss of 8.38% over a century. From this, 2.31% was identified due to the reactivity in reservoir rock and 6.07% due to the aqueous diffusion to cap rock and its reactivity. Among these reactions, carbonate dissolution emerged as the most noteworthy, resulting in considerable hydrogen loss contingent upon the presence of methanogenesis bacteria. As per the modelled scenario, porosity was reduced in reservoir rock by 0.41%, and in carbonate cap rock, it was increased by 56%, which could increase the hydrogen leakage. Also, methane (CH4) exhibited the most favourable characteristics as a cushion gas due to its lower reactivity. However, it's crucial to acknowledge that these figures could significantly fluctuate based on variations in mineral composition, bacterial populations and their growth, and the prevailing subsurface conditions. These modelled findings can serve as a valuable tool for comprehending the mechanisms of hydrogen loss and mineral reactivity within a given underground system.

Petrophysical parameters of carbonate cap rock during CO2 sequestration in an offshore oil and gas reservoir – a case study

Sekwestracja CO2 jest obecnie jednym z najintensywniej rozwijanych sposobów zmniejszenia ilości tego gazu w atmosferze Ziemi. Wiąże się ona z szeregiem zjawisk w górotworze mających wpływ na właściwości zarówno poziomów zbiornikowych, jak i uszczelniających. Jednym z kluczowych elementów technologicznych związanych z sekwestracją jest wykazanie, w jaki sposób długotrwałe zatłaczanie CO2 do górotworu będzie wpływało na parametry skał zbiornikowych w obrębie horyzontu docelowego, a także czy nie doprowadzi do nadmiernego wzrostu przepuszczalności w wyżejległych formacjach uszczelniających. W artykule zostały przedstawione wyniki badań laboratoryjnych wpływu sekwestracji CO2 na parametry petrofizyczne skał węglanowych, stanowiących warstwę uszczelniającą pułapki w morskim złożu ropno-gazowym. Wpływ CO2 został wyznaczony na podstawie porównania współczynników przepuszczalności, porowatości oraz dynamicznych parametrów sprężystości przed ekspozycją próbek na CO2 i po niej. Próbki skał zostały nasycone solanką złożową, a następnie poddane 12-tygodniowej ekspozycji na CO2 w stanie nadkrytycznym w warunkach złożowych. Odnotowano wzrost współczynnika przepuszczalności w części próbek posiadających szczeliny naturalne, podczas gdy w próbkach niezawierających szczelin wystąpił jego spadek. Zaobserwowano także spadek współczynnika porowatości efektywnej, jednakże prawdopodobnie w efekcie wytrącania się kryształów z solanki, którą próbki były nasycane. Moduły Younga oraz odkształcenia postaci próbek po ekspozycji nie zmieniły się zasadniczo w stosunku do wartości referencyjnych. Zarówno w próbkach eksponowanych na CO2, jak i w próbce niepoddanej ekspozycji odnotowano niewielki wzrost współczynnika Poissona oraz wzrost modułu odkształcenia objętości, co mogło być spowodowane przekroczeniem granicy plastyczności podczas obciążania próbek w pomiarach referencyjnych, prowadzącym do ich trwałej kompakcji.

Impact of diagenesis on the pore evolution and sealing capacity of carbonate cap rocks in the Tarim Basin, China

Impact of diagenesis on the pore evolution and sealing capacity of carbonate cap rocks in the Tarim Basin, China

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.

Relationship between stylolite morphology and the sealing potential of stylolite-bearing carbonate cap rocks

AbstractWe analyzed the sealing effectiveness of cap rocks bearing different types of stylolites using a combination of petrographic, petrophysical, pore structure, and sealing capacity characterization techniques. This study was based on examples of carbonate cap rocks that seal ultradeep hydrocarbon reservoirs of the Tarim Basin (China). Samples from both drill cores and their outcrop analogues were investigated to quantify how morphology influences the sealing capacity of different types of stylolite-bearing rocks. The study cap rocks consisted of mudstone, wackestone to packstone, grainstone, and dolomitic limestone. Four types of stylolites were identified: rectangular layer, seismogram pinning, suture and sharp peak, and simple wave-like types. The difference in the sealing capacity of carbonate cap rocks is attributed to their pore structure connections and the types of stylolites they develop. Samples bearing simple wave-like stylolites showed the best sealing capacity, followed by those with rectangular layer and suture and sharp peak types, whereas carbonates hosting seismogram pinning types had the lowest sealing capacity. The impact of stylolite segments on the rock sealing properties, however, differed from one segment to another. Rectangular layer–type stylolites could be divided into three distinct segments (with good, moderate, and poor sealing, respectively). Both the seismogram pinning and suture and sharp peak stylolite types were divided in two parts, with the former one having moderate and poor sealing and the latter exhibiting good and moderate sealing. The simple wavelike type had a good sealing capacity all along the pressure-solution seam. The most effective sealing barriers for vertical fluid flow form when (1) calcite and siliceous cements are pervasively distributed in the vicinity of stylolites, forming highly cemented zones with lower porosity and permeability than their surrounding host rocks; (2) stylolites are enriched in insoluble residues; and (3) rare microfractures and dissolution vugs are found along the stylolites. This work provides useful examples for the prediction of the sealing potential of stylolite-bearing carbonate rocks according to stylolite morphology in other geologic settings.

Carbonate Caprock–Brine–Carbon Dioxide Interaction: Alteration of Hydromechanical Properties and Implications on Carbon Dioxide Leakage

Summary Caprocks play a crucial role in the geological storage of carbon dioxide (CO2) by preventing its escape and thus trapping it into underlying sequestering reservoirs. An evaluation of interaction-induced alteration of the hydromechanical properties of caprocks is essential to better assess the leaking risk and injection-induced rock instability, thus ensuring a long-term viability of geological CO2 storage. We study the changes in minerals, nanopores, elastic velocities, and mechanical responses of a carbonate caprock caused by rock–water/brine–CO2 interaction (CO2 pressure: ≈12 MPa; 50°C). Before the interaction, the total and accessible porosities are 1.6 and 0.6%, respectively, as characterized by the small-angle neutron scattering (SANS) technique. SANS results show that the total porosity of the carbonate caprock increases, apparently because of rock–brine–CO2 interaction, and the increasing rate rises as brine concentration increases (2.2% for 0 M NaCl, 2.6% for 1 M NaCl, and 2.7% for 4 M NaCl). The increase in total porosity is due to the dissolution of calcite, which tends to enlarge accessible pores (by 0.8 to 1.2%) while slightly decreasing the inaccessible pores (by 0.1–0.2%). Under a CO2–acidified water environment, the compressional-wave (P-wave) and shear-wave (S-wave) velocities (5536.7 and 2699.7 m/s) of a core sample containing natural fractures decrease by 8.5 and 8.1%, respectively, whereas both P- and S-wave velocities (6074.1 and 3858.8 m/s) for an intact sample show only ≈0.5% decreases. The interaction also causes more than 50% degradation of the uniaxial compressive strength for the core sample with natural fractures. X-ray microcomputed tomography experiments on three tiny cores (diameter: 1 mm) after 5-day treatment with CO2 (12 MPa) also show that matrix erosion occurs under CO2–acidified water environment but barely occurs without a direct contact with liquid water. Our study suggests that the hydromechanical properties of carbonate caprocks could evolve over the long-term CO2–brine invasion, and it is critical to monitor the CO2–acidified brine interface for a better and long-term evaluation of the caprock integrity.

Fractal characteristics of pore networks and sealing capacity of Ordovician carbonate cap rocks: A case study based on outcrop analogues from the Tarim Basin, China

Understanding and predicting the main controls on the sealing capacity of carbonate cap rocks is of great significance for ultradeep carbonate reservoir exploration and production. This study focuses on revealing the pore networks and sealing capacity of the Ordovician carbonate cap rocks in the Tarim Basin by analyzing samples from outcrop analogues using optical and scanning electron microscopy and a combination of mercury intrusion capillary pressure and nitrogen gas adsorption. Three classes of cap rocks are defined here according to their pore-throat structure, fractal dimension, and sealing capacity. These carbonate cap rocks are dominated by limestones and dolomitic limestones. Four pore types are identified: microfractures, intragranular, intercrystalline, and intracrystalline. Six pore structure types show multiscale variability from macropores to micropores. The pore structures present multiple fractal behaviors, with fractal dimensions showing an increasing trend as the pore diameter decreases. The cover coefficient, a parameter that allows characterization of the caprock sealing performance, shows an increasing trend along with increasing the fractal dimension of pore structure. The average cover coefficients of six pore structure types not only show good correlations (either exponential or linear) with certain fractal dimensions, but they also demonstrate a strong positive correlation with the average fractal dimension. These results suggest that the sealing capacity of the studied rocks increases with increasing fractal dimension. The sealing performance of cap rocks significantly decreases with an increasing amount of macropores. This work provides a relevant case study for further understanding of pore structures and sealing capacity of carbonate cap rocks.

Using characteristics of pressure-temperature induced permeability variation of typical carbonate rock to determine its performance as reservoir or cap rock

The current research on carbonate rock often focuses on the storage space for oil and gas, and exploration of carbonate rock in petroliferous basins also mainly searches for high-quality reservoir rock for hydrocarbons. However, the importance of effective carbonate reservoir-cap rock configuration is increasingly highlighted, as hydrocarbon exploration advances towards deeper and older strata. Exploration practice shows that the favorable facies belt of carbonate rock, though deeply buried, still develops highly desirable reservoir rock with high porosity and permeability. Therefore, the presence of an effective carbonate cap rock collaborating with this reservoir rock becomes key to hydrocarbon exploration in deep carbonate rock. This research, for the first time, systematically and thoroughly carries out permeability measurement through the whole triaxial compression process of typical carbonate rock at varied temperatures, and captures the permeability evolution during deformation and failure, affected by temperatures and confining pressures. Test results show that typical dolomite and limestone present varied permeability variation characteristics in a triaxial loading state. Dolomite appears to be more of reservoir rock. It presents higher critical confining pressure for brittle–ductile transition, and is more prone to fracturing. Its permeability grows with temperature elevation. As for limestone, it has better performance as cap rock, which is embodied as the lower critical confining pressure for brittle–ductile transition, high sealing capacity, and permeability reduction with elevated temperatures. To sum up, vertical stacking of dolomite and limestone can form an effective reservoir-cap rock assemblage for hydrocarbon accumulation.

Geomechanical characteristics of potential carbon dioxide sinks and seals in the DeSoto Canyon Salt Basin, eastern Gulf of Mexico

Recent studies indicate vast storage capacity exists in Cretaceous and Paleocene–Miocene sandstones in the eastern Gulf of Mexico. Understanding the geomechanical integrity of reservoirs and associated seals is useful for reducing the risk of migration of injected CO2 out of the storage complex. In this study, we investigated the rock mechanical properties and reservoir-seal integrity of three potential reservoir units in the DeSoto Canyon Salt Basin using geophysical well logs. Geomechanical analysis shows the Cretaceous reservoir units contain competent carbonate cap rocks that arrest possible fracture propagation from injection. Results of reservoir and seal integrity analyses indicate all three potential reservoirs and associated seals are geomechanically stable. The injection pressure of CO2 should stay below the minimum horizontal stress to prevent the occurrence of tensile hydraulic fractures. The three candidate reservoir units are ranked according to reservoir geomechanics for long-term commercial carbon storage. Future work should focus on geomechanical simulation of the reservoir units and additional assessment of leakage risk to further ensure safe carbon storage during and after CO2 injection. Laboratory core tests are recommended to confirm the accuracy of the empirical geomechanical analysis of the candidate reservoir and seal rocks.

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.

Origin of the Neoproterozoic rim dolomite as lateral carbonate caprock, Patawarta salt sheet, Flinders Ranges, South Australia

The ‘rim dolomite’ of South Australia’s Central Flinders Ranges is a prominent ridge-forming, layered dolomitic and siliceous unit. The rim dolomite is interpreted to be a lateral caprock found exclusively at the salt–sediment interface between the Patawarta diapir and the Ediacaran-aged Bunyeroo Formation. Lateral dolomite caprock is defined by the following field relationships: (1) the rugose dolomicrite base that parallels the contact of the diapiric matrix and the bedding in the overlying stratigraphy, (2) the exclusive presence of dolomite at the salt–sediment interface, (3) the lack of sedimentary structures or fossils (cyanobacterial laminites and stromatolites), (4) the lack of interbedded Bunyeroo lithofacies, and (5) the inability to trace the rim dolomite capstone away from the diapir margin into the outboard stratigraphy. In addition to the field relationships, the rim dolomite displays the following capstone fabrics: (1) massive—microcrystalline dolomite, (2) porphyritic—two distinct crystal sizes, one forming microcrystalline dolomite groundmass and the other forming rosettes of silica, (3) banded—microcrystalline dolomite forming pressure-dissolution layers of silica and authigenic hematite, and (4) brecciated—mosaic to disorganised, forming a microcrystalline dolomite groundmass, which locally contains remnant clasts of Callanna non-evaporite lithologies, such as quartz arenite to arkosic sandstones and basalts, surrounded by an anastomosing cement-filled vein network. All capstone fabrics contain various amounts of anhydrite, quartz, feldspar and non-evaporite grains that represent the insoluble residue during halite dissolution and caprock accretion. Three different genetic models for the lateral caprock are described and tested, and that of these, only the halokinetically rotated caprock model fits the data. The field relationships and capstone fabrics of the rim dolomite match other lateral caprocks in salt basins such as the Paradox Basin and Gulf Coast, USA.

Three-Dimensional Pore-Scale Modeling of Fracture Evolution in Heterogeneous Carbonate Caprock Subjected to CO2-Enriched Brine.

Fractures in caprocks overlying CO2 storage reservoirs can adversely affect the sealing capacity of the rocks. Interactions between acidified fluid and minerals with different reactivities along a fracture pathway can affect the chemically induced changes in hydrodynamic properties of fractures. To study porosity and permeability evolution of small-scale (millimeter scale) fractures, a three-dimensional pore-scale reactive transport model based on the lattice Boltzmann method has been developed. The model simulates the evolution of two different fractured carbonate-rich caprock samples subjected to a flow of CO2-rich brine. The results show that the existence of nonreactive minerals along the flow path can restrict the increase in permeability and the cubic law used to relate porosity and permeability in monomineral fractured systems is therefore not valid in multimineral systems. Moreover, the injection of CO2-acidified brine at high rates resulted in a more permeable fractured media in comparison to the case with lower injection rates. The overall rate of calcite dissolution along the fracture decreased over time, confirming similar observations from previous continuum scale models. The presented 3D pore-scale model can be used to provide inputs for continuum scale models, such as improved porosity-permeability relationships for heterogeneous rocks, and also to investigate other reactive transport processes in the context of CO2 leakage in fractured seals.

Influence factors and an evaluation method about breakthrough pressure of carbonate rocks: An experimental study on the Ordovician of carbonate rock from the Kalpin area, Tarim Basin, China

There are many oil and gas fields around the world that are sealed by tight carbonate caprocks. Compared with gypsum rocks and shales, tight carbonate caprocks are characterized by brittleness and ease of structural fracturing and dissolving in acidic groundwater. The breakthrough pressure (BP) is a significant indicator that indicates the sealing capacity of the caprocks. Therefore, we conducted a series of experiments, including effective porosity, permeability, casting thin-sections, BP, mineral composition, microstructural characteristics and clay minerals contents on carbonate samples from Ordovician system in the Kalpin area, Tarim Basin, China to research factors that affect the BP of carbonate caprocks. According to the experimental data analysis, the BP deceases with macropore proportions and increases with proportions of micropore and mesopore volume. Due to the large macropore proportion and low clay content (<10%), expansion of clay minerals with water hardly reduces effective porosity and permeability. Pore throat and cement influence effective porosity and permeability, and thus influence the BP. Generally, the BP decreases with the increase of effective porosity and permeability, and linear correlations exist between the reciprocal of effective porosity (A), −0.48 power of permeability (B) and the BP. Due to the interdependency between A and B, a principal component regression procedure (PCRP) is implemented with the statistical analysis system (SAS) software to eliminate the interdependencies and obtain a fitting formula of BP. The calculated BP with depth by this method matches gas logging results. This study provides a research idea and a mathematical calculation model of the BP of carbonate caprocks to further evaluate and predict carbonate caprocks behaviour.

Impact of pore structure and fractal characteristics on the sealing capacity of Ordovician carbonate cap rock in the Tarim Basin, China

Abstract Evaluating the heterogeneity and sealing capacity of carbonate cap rocks is of great significance for hydrocarbon production. However, the main controls on pore size distribution in carbonate cap rocks are not well constrained. In this contribution we analyze drill core samples of carbonate cap rocks from the Ordovician Yingshan Formation (Tarim Basin) to study their pore properties and investigate the controls of pore-throat structure and fractal dimension on the sealing capacity of the cap rock. Results from petrography and a combination of mercury injection capillary pressure and nitrogen gas adsorption tests reveal that there are four lithological cap rock types, with micrite being the most prevalent one, followed by calcarenite. Six types of pore-throat structures and fractal dimensions (from D1 to D6) are classified based on the pore size distributions, including macropore-I, macropore-II, mesopore-I, mesopore-II, transitional pore-I and transitional pore-II. The fractal dimensions show that there is a decreasing trend from D1 to D6 with decreasing pore-size diameter, suggesting that the macropore and mesopore types present more complex pore-throat structures than the transitional type. The total fractal dimension (Dtotal) indicates that the pore throat structures are complex and heterogeneous. The sealing heights of the gas column have a positive correlation with cement content in calcarenite and a negative correlation with microfracture density. Mesopore-II and transitional pore types make a significant contribution to enhancing the breakthrough pressure. The fractal variations mainly result from macropores and mesopores, while transitional pores and micropores weaken the impact of the whole pore system on the Dtotal value. The heterogeneity and anisotropy of macropores is the main control on the sealing capacity of the cap rock. The increasing of D1 considerably contributes to the pore shape heterogeneity and enhances the capillary resistance force to hydrocarbon migration. Therefore, the fractal dimension is an effective approach for investigating the pore throat structure and sealing capacity of carbonate cap rocks.

Influence of Rock Mineralogy on Reactive Fracture Evolution in Carbonate-Rich Caprocks.

Fractures present environmental risks for subsurface engineering activities, such as geologic storage of greenhouse gases, because of the possibility of unwanted upward fluid migration. The risks of fluid leakage may be exacerbated if fractures are subjected to physical and chemical perturbations that alter their geometry. This study investigated this by constructing a 2D fracture model to numerically simulate fluid flow, acid-driven reactions, and mechanical deformation. Three rock mineralogies were simulated: a limestone with 100% calcite, a limestone with 68% calcite, and a banded shale with 34% calcite. One might expect transmissivity to increase fastest for rocks with more calcite due to its high solubility and fast reaction rate. Yet, results show that initially transmissivity increases fastest for rocks with less calcite because of their ability to deliver unbuffered-acid downstream faster. Moreover, less reactive minerals become persistent asperities that sustain mechanical support within the fracture. However, later in the simulations, the spatial pattern of less reactive mineral, not abundance, controls transmissivity evolution. Results show that a banded mineral pattern creates persistent bottlenecks, prevents channelization, and stabilizes transmissivity. For sites for geologic storage of CO2 that have carbonate caprocks, banded mineral variation may limit reactive evolution of fracture transmissivity and increase storage reliability.

A conceptual model to investigate the impact of diagenesis and residual bitumen on the characteristics of Ordovician carbonate cap rock from Tarim Basin, China

The Lower-Middle Ordovician Yingshan (O1-2y) Formation associated with large unconformity weathering crust was the main hydrocarbon reservoir in the Tarim Basin, and the dense limestone/dolomite within this formation was revealed as the local carbonate cap rock. Based on petrophysical properties, thin sections, cathodeluminescence (CL) and scanning electron microscope (SEM) measurements, the effects of cap rock on depositional settings, diagenesis and pyrobitumen were carefully analyzed. Carbonate cap rock dominated by micrite has ultralow porosity and permeability, with an average porosity of 0.568% and permeability of 0.07 × 10−3 μm2. There is a significant bottom-up thickness variation (from several to tens of meters) in different members within the O1-2y formation. The steady cap rock is more likely to be distributed in low-energy depositional environments, corresponding to intershoal sea, low-lying land of open platform and lagoon of restricted platform. Constructive diagenesis processes mainly comprise extreme filling, compaction and cementation, resulting in a significant decrease in the quantity and size of pores. Conversely, leaching and paleokarst dissolution, together with diagenesis associated with hydrothermal fluids, has a detrimental effect on the effective preservation of cap rock. Three types were summarized to characterize the cementation-compaction relationship between cement distribution and intraclast deformation. The increase in intraclast size indicate that the intergranular pores are likely to be cemented. A good sealing impact on the underlying oil-gas is confirmed in sparry calcarenite when its cement content reaches 15% and higher by volume. Early compaction vs. early cementation processes probably affect the sealing capacity, so high quality cap rock is primarily presented while cementation precedes compaction. Highly abundant stylolites filled with residual bitumen and precipitated cements in the cap rock intervals consistently have low poroperm values, resulting in micropore occlusion and occlusion of the late hydrocarbon migration pathways, which can act as barriers for the upward migration of oil-gas. A conceptual model of the evolution feature of cap rock provides a plausible interpretation for better understanding of the spatial distribution of carbonate cap rock in future exploration and development.

Identification and characteristic analysis of carbonate cap rock: A case study from the Lower-Middle Ordovician Yingshan Formation in Tahe oilfield, Tarim Basin, China

Accurate description of heterogeneous distribution and complex sealing capacity of carbonate cap rock is essential for prospecting carbonate reservoirs. Based on core and thin sections, well drilling, fullbore microscan imaging (FMI) and conventional logs, qualitative and quantitative identifications of cap rock were performed within the Yingshan Formation (O1-2y) in Tahe oilfield. Porosity and permeability measurements, scanning electron microscope (SEM) analysis, and displacement pressure calculations were used to characterize the reservoir-cap assemblages. After calibration based on cores and wireline logs, four recognition patterns of cap rock, including blocky-bearing, layered-bearing, porphyritic-bearing and linear-bearing, are developed on FMI. Four sensitive logging parameters (deep-shallow dual lateral resistivity (RD-RS), natural gamma ray (GR), caliper (CAL)) were chosen to construct the quantitative identification criteria, with the higher value being RD-RS ≥ 1000 Ω m and lower being GR ≤ 15 API. Four lithologic types and eleven subtypes were identified in carbonate cap rock, and micrite was dominant lithology. The cap rock is characterized by low porosity ranging from 0.04 to 1.4% (averaging 0.568%) and low permeability ranging from 0.004×10−3 to 0.95×10−3μm2 (averaging 0.07×10−3μm2). Five sets of cap rock have a significant bottom-up difference in diverse members, and the thickness of individual cap rock ranges from several meters to tens of meters. The stability parameter (S) was adopted to reflect the distribution differences, and superior cap rock defined as the Order I (S > 3.84) occurs in the middle part of the 3rd member. Capillary seals control the sealing capacity, and the displacement pressure difference of effective sealing among the cap rock and underlying oil-bearing intervals should be 3 MPa and higher. Strong vertically superimposed and poor laterally connected direct carbonate cap rock plays a decisive role in controlling hydrocarbon preservation and production of carbonate reservoirs.

Frictional Properties of Simulated Fault Gouges from the Seismogenic Groningen Gas Field Under In Situ P–T ‐Chemical Conditions

AbstractWe investigated the frictional properties of simulated fault gouges derived from the main lithologies present in the seismogenic Groningen gas field (NE Netherlands), employing in situ P–T conditions and varying pore fluid salinity. Direct shear experiments were performed on gouges prepared from the Carboniferous shale/siltstone substrate, the Upper Rotliegend Slochteren sandstone reservoir, the overlying Ten Boer claystone, and the Basal Zechstein anhydrite–carbonate caprock, at 100°C, 40 MPa effective normal stress, and sliding velocities of 0.1–10 μm/s. As pore fluids, we used pure water, 0.5–6.2 M NaCl solutions, and a 6.9 M mixed chloride brine mimicking the formation fluid. Our results show a marked mechanical stratigraphy, with a maximum friction coefficient (μ) of ~0.66 for the Basal Zechstein, a minimum of ~0.37 for the Ten Boer claystone, ~0.6 for the reservoir sandstone, and ~0.5 for the Carboniferous. Mixed gouges showed intermediate μ values. Pore fluid salinity had no effect on frictional strength. Most gouges showed velocity‐strengthening behavior, with little systematic effect of pore fluid salinity or sliding velocity on (a–b). However, Basal Zechstein gouge showed velocity weakening at low salinities and/or sliding velocities, as did 50:50 mixtures with sandstone gouge, tested with the 6.9 M reservoir brine. From a rate and state friction viewpoint, our results imply that faults incorporating Basal Zechstein anhydrite–carbonate material at the top of the reservoir are the most prone to accelerating slip, that is, have the highest seismogenic potential. The results are equally relevant to other Rotliegend fields in the Netherlands and N. Sea region and to similar sequences globally.

Structural imaging of the East Beni Sueif Basin, north eastern Desert, Egypt

The East Beni Sueif Basin is the only tested hydrocarbon-bearing basin on the eastern side of the Nile in Egypt. The basin is located around 150 km to the south of Cairo. This work introduces the first attempt of seismic interpretation and structural patterns of this basin, for which subsurface published works are lacking. Structural imaging of the area is achieved through interpretation of pre-stack time migration (PSTM) seismic cube and data sets of seven wells. The penetrated sedimentary section is represented by Albian-Middle Eocene sediments.The East Beni Sueif Basin is a type of the whole graben-system and is bounded by two NW-SE bounding faults. These faults had continued activity in an extensional regime associated with fault-propagating folds. The basin is traversed by a N75°E-trending fault system at basement level. This fault system separates the basin into two structural provinces. The Northwestern Province is deeper and shows more subsidence with a predominance of NW-trending longitudinal faults and N60·W oblique faults to the basin trend. The Southeastern Province is shallow and crossed by N14·W-trending faults which are slightly oblique to the basin axis.Albian time had witnessed the main extensional tectonic phase and resulted in major subsidence along basin-bounding faults associated with growth thickening of basal deposits. During Senonian time, the basin experienced a mild phase of transtensional tectonics, which formed negative-flower structures entrapping different folds along the N75°E and N60·W faults. The timing and style of these structures are similar to the Syrian-Arc structures in several Western Desert oil fields. The basin emerged during the Paleocene with scoured and eroded top Cretaceous sediments. Subsidence was resumed during the Early Eocene and resulted in 1500 m-thick carbonate sediments. Lastly, a mild extensional activity possibly occurred during the Oligocene-Miocene time.Despite the possible restricted potentiality of the source rock, the main hydrocarbon accumulation risk is attributed to retention in traps of long-span tectonic history. Reaching of main faults to surface through brittle carbonate cap rocks and limited thickness of the shale in the reservoir section risk hydrocarbon sealing. Buried structures of passive setting during the Tertiary show a minor trapping risk.

Major factors affecting the closure of marine carbonate caprock and their quantitative evaluation: A case study of Ordovician rocks on the northern slope of the Tazhong uplift in the Tarim Basin, western China

There are many examples of oil and gas reservoirs throughout the world that have tight carbonate rock as the caprock. These oil and gas reservoirs are often vertically overlapped (with multiple oil and gas sections) and laterally connected (to many oil and gas reservoirs). The closure of carbonate caprock is affected by many factors, such as the clay content, differential diagenesis and layer thickness. As evaluation parameters, the clay content can be determined by a gamma ray well-logging curve; the differential diagenesis is reflected in filling effects, rupture effects, cement composition and content and can be measured through the displacement pressure; the layer thickness can be obtained from drilling and well-logging data. In different regions or different members, the factors and parameters to be considered or evaluated for the closure are dependent on actual geological conditions. In this study, the clay content, displacement pressure and layer thickness were analysed, determined, calculated and normalized to generate an overall closure evaluation index (λ) for the caprock in wells on Ordovician Liang 3–5 mud-bearing limestone members on the northern slope of the Tazhong uplift. On the plane distribution map, the area with λ ≥ 1 was effectively sealed. The tight carbonate in the inner Yingshan Formation (with high-resistivity, referred to as a high-resistivity layer) was also effectively caprock. Regardless of whether it can seal oil and gas, the sealing capacity mainly depends on the displacement pressure difference between the high-resistivity layer and the underlying carbonate reservoir. Based on drilling results and the comparison of the displacement pressure difference between the two layers (by actual measurements and calculations), we observed that when the pressure difference is more than 1.95 MPa, it is an effective caprock.