Carbonate Reservoir Rocks Research Articles

Application, Progress, and Trend of Thickened Acid Fracturing in Carbonate Rock Reservoir Development

Application, Progress, and Trend of Thickened Acid Fracturing in Carbonate Rock Reservoir Development

Interfacial properties of CO2 and liquid sulfur in high-sulfur gas fields: Molecular simulations on carbonate mineral surfaces

As the global energy landscape transforms, the development of high-sulfur natural gas has become increasingly critical. However, sulfur deposition during these gas field developments significantly affects operational efficiency. This study employed molecular dynamics simulation to explore the effectiveness of CO2 in alleviating sulfur deposition on carbonate rock reservoirs. Specifically, it examined the interfacial tension between liquid sulfur and CO2, the wettability of sulfur on carbonate rock mineral surfaces, and the kinetics of CO2 displacing liquid sulfur. Results show that as CO2 pressure increases from 10 MPa to 60 MPa, the interfacial tension between liquid sulfur and CO2 decreases by 84 %, from 35.54 mN/m to 5.53 mN/m. The contact angles of sulfur droplets on calcite and dolomite surfaces stabilize at 41.82° ± 2.10° and 44.33° ± 3.27°, respectively, indicating greater sulfur spread on calcite surfaces. With higher CO2 pressures, sulfur deposition on mineral surfaces and interfacial tension both decrease significantly, while the wetting angle of liquid sulfur increases, particularly on dolomite. At 60 MPa CO2 pressure, the adsorption energy of dolomite for liquid sulfur drops from 364.56 kcal/mol to 25.46 kcal/mol, a 93 % reduction, suggesting CO2′s dual role in displacing sulfur and promoting its desorption from mineral surfaces. Furthermore, the efficiency of sulfur deposition alleviation in carbonate rock slit structures improves and stabilizes at around 40 MPa CO2 pressure. This study presents a potential environmentally friendly approach for efficiently developing high-sulfur gas fields, and its findings provide practical insights for optimizing CO2 injection strategies to mitigate sulfur deposition.

Asphaltene deposition effects on reservoir rock wettability and modification strategies

Asphaltene deposition, a widespread challenge in the petroleum industry, detrimentally affects oil production, transport, and processing. Our study investigates asphaltene's impact on sandstone and carbonate reservoir rock wettability using ASTM-D6560 extraction and heptol solutions. A significant part of our focus was to examine wettability change due to asphaltene damage and the use of nanoparticles to improve this situation. Qualitatively, advanced techniques reveal altered rock composition, and contact angle measurements, along with zeta potential assessments, highlight significant wettability changes. Quantitatively, asphaltene-infused solutions induce a quantifiable increase in contact angles. Specifically, with gamma alumina nanoparticle addition, contact angles rise from 68° to 87° for sandstone and 110°–142° for carbonate rocks. Temperature variations within our experimental range also induce notable wettability changes. These findings establish a clear link between asphaltene deposition and quantifiable wettability modifications, providing crucial insights for optimizing oil recovery processes and enhancing well performance in the petroleum industry. The study's results suggest that nano-gamma alumina can be an effective solution for improving wettability and mitigating asphaltene deposition issues in carbonate rocks, offering promising prospects for the oil and gas industry.

Comparative evaluation of pore volume compressibility of carbonate reservoir rocks: different laboratory measurement approaches

The pore volume compressibility (C PV) of a reservoir plays an essential role in estimating the reserve oil and recovery factor. Therefore, selecting an appropriate laboratory measurement approach for determining the C PV is crucial. This study aims to compare three different routine approaches to C PV measurement. Fifty-eight carbonate core plug samples with diverse porosity from the Sarvak Formation in the Southwest of Iran were selected. The measurements were performed at different saturation, pressure, and temperature conditions in triaxial core holders. Results show that samples with the lowest porosity have the highest compressibility value, and samples with the highest porosity have the lowest value. Furthermore, the compressibility measured on brine-saturated cores at pressure and temperature conditions was higher than only brine-saturated, and consequently higher than dry core plugs. Hence, the measurement methods and approaches severely affect the resultant compressibility. The values obtained at representative reservoir conditions are advised to be utilized in simulation and modeling studies. A novel reciprocal model was also proposed to appropriately correlate the data with porosity. The results of this work give insight into the selection of the best laboratory measurement approach to estimate the actual C PV value in reservoir conditions, especially at varying pore pressure and temperature.

A Study of CO2 Storage in Bimodal Carbonate Aquifer Rocks: Challenges and Enhancement through Foaming

Summary In carbonate rock reservoirs, the presence of dual-pore systems, characterized by two distinct pore size distributions, plays a crucial role in gas storage in saline aquifers. However, comprehensive research on the impact of bimodal porosity on CO2 storage in such reservoirs is lacking. This study explores CO2 storage efficiency in carbonate aquifer rocks with bimodal porosity. Petrographic examination, capillary pressure measurements, and nuclear magnetic resonance (NMR) T2 profiling revealed two distinct and interconnected pore systems with equal effective porosity proportions. While both systems facilitated fluid flow, the micropores had a high capillary entry pressure (>100 psi). Coreflood experiments showed gas displacement efficiencies below 50%, primarily in larger pores, with only 49–58% of these large pores (20–28% of total pores) storing injected gas through residual trapping after water imbibition. To address this challenge, CO2 was foamed using a foaming agent to enhance viscous forces and overcome capillary forces. This resulted in significant improvements, including a 31% increase in displacement efficiency and a 28% increase in residual gas. NMR analysis revealed effective redirection of CO2 into smaller pores when foam was applied. In another experiment on a sample with a different pore geometry, the use of nanoparticles to strengthen foam increased sweep efficiency by up to 117%, with a corresponding increase of up to 169% in residual trapping. While the use of foam entails additional operational expenses, we contend that the economic viability of foam technology for CO2 storage hinges on a rigorous cost-benefit analysis that weighs increased storage capacity/security against chemical costs. Such analysis should also consider the time, cost, and uncertainty associated with developing additional storage sites. Furthermore, improved site selection criteria in carbonate rocks are needed, including a predictive model for T2 cutoff to identify aquifers with excessive micropores and avoid them during site selection. While fractured porosity is not within the scope of this study, it is expected that foam can equally improve sweep and trapping efficiencies in naturally fractured carbonate rocks.

Use digital rock physics to characterize velocity and attenuation signatures of deep cavity-fracture carbonate reservoirs

Abstract Conventional rock physics experiments and well logging analyses face challenges in deep carbonate formation containing meter-scale cavity-fracture system, since it is unfeasible to extract representative samples from targeted formation. In this study, differing from the conventional digital rock models at the core scale, we construct a digital rock model from realistic outcrop images with meter-scale heterogeneity of cavities and fractures. Using a dynamic stress–strain simulation, we investigate how reservoir type, fracture density and spacing, cavity porosity and size, fluid saturation, and connectivity influence wave dispersion and attenuation. By selecting the simulation frequency of 0.3 MHz approximately corresponding to the field seismic measuring frequency of 30 Hz, the simulation results can reflect the realistic seismic velocity and attenuation characteristics of deep carbonate reservoir rocks. We find that the P-wave velocity decreases linearly with increasing fracture and cavity porosity. The P-wave attenuation is sensitive to variations in fracture density but shows limited sensitivity to changes in cavity porosity and size. Fractures with narrower spacing result in higher attenuation when fracture density remains constant. Deep carbonate rocks with cavity-fracture systems saturated with two immiscible fluids display enhanced attenuation compared to fully saturated conditions. The velocity demonstrates an almost linear increase with water saturation, while attenuation initially increases before decreasing at a peak water saturation of 70%–80%. The connectivity between fractures and cavities significantly influences the attenuation behavior. Our simulation results provide valuable guidance for seismic data processing and interpretation of deep carbonate reservoir rocks with cavity-fracture systems.

Hierarchies of stratigraphic discontinuity surfaces in siliciclastic, carbonate and mixed siliciclastic‐bioclastic tidalites: Implications for fluid migration in reservoir quality assessment

AbstractThe hierarchies of the stratigraphic discontinuity surfaces observed in ancient tidalites are qualitatively assessed, aiming to evaluate their role as possible preferential conduits for fluid migration. Three outcrop examples are presented from microtidal settings of southern Italy: (i) siliciclastic tidalites consisting of quartz‐rich cross‐stratified sandstones generated by strong two‐directional tidal currents flowing along a tidal strait; (ii) carbonate tidalites, which accumulated in a Cretaceous lagoon and tidal flat where peritidal cycles formed vertically‐stacked sequences of biopeloidal and fenestral packstones, wackestones and bindstones during repeated phases of Milankovitch‐scale sea‐level changes; (iii) mixed, siliciclastic‐bioclastic tidalites, deposited in a bay and recording offshore‐transition, to shoreface wave‐dominated and tide‐influenced environments. Observations made during this study suggest that fluid movement can be controlled by the presence of main bounding surfaces that occur at different dimensions, from large (hectometre)‐scale, to medium (decametre)‐scale, to smaller (metre)‐scales. These surfaces produced either by depositional or erosional processes, are characterised by different features and geometries in siliciclastic, carbonate and mixed siliciclastic‐bioclastic tidalites arguably revealing complex internal pathways for fluid flows. These results suggest that fluids propagating along the main discontinuities follow a dominant sub‐horizontal direction of propagation, associated with minor sub‐vertical movements, due to local internal surface geometries and interconnections and a general lack of fractures. This surface‐based approach to the study of fluid‐flow transmission within stratified rocks represents a conceptual attempt to predict fluid mobility and reservoir potential in tidalite‐bearing siliciclastic, carbonate and mixed reservoir rocks.

Development of a new hydraulic electric index for rock typing in carbonate reservoirs

Rock typing techniques have relied on either electrical or hydraulic properties. The study introduces a novel approach for reservoir rock typing, the hydraulic-electric index (HEI), which combines the strengths of traditional electrical and hydraulic rock typing methods to characterize carbonate reservoirs more accurately. By normalizing the ratio of permeability and formation resistivity factor (K/FRF) with respect to porosity, the HEI method is applied to two datasets of carbonate core samples: dataset 1 consists of 112 carbonate core samples from the Tensleep formation in the Bighorn basin of Wyoming and Montana, and dataset 2 includes 81 carbonate core samples from the Asmari formation in the south-west of Iran. Statistical analysis confirms the effectiveness of the HEI in predicting permeability, with high determination coefficients for both datasets (resulting in determination coefficients (R2) of 0.965 and 0.904 for dataset 1 and dataset 2, respectively). The results classify the rock samples into distinct rock types, nine rock types for dataset 1 and four rock types for dataset 2, and demonstrate the HEI ability to capture the relationship between hydraulic conductivity and electrical resistivity in carbonate reservoir rocks. Applying the HEI method to the validation dataset yielded highly accurate permeability predictions, with average of determination coefficients of 0.883 and 0.859 for dataset 1 and dataset 2, respectively. Validation of the HEI method further confirms (20% of the dataset was set aside for validation, while the remaining 80% was used for the rock typing approach (5 folds)) its accuracy in predicting permeability, highlighting its robust predictive capacity for estimating permeability in carbonate reservoirs.

Petrophysical and petrographical delineation for carbonate reservoir rocks in north Western Desert, Egypt

Petrophysical and petrographical delineation for carbonate reservoir rocks in north Western Desert, Egypt

Analysis of the Effects of Partially Hydrolyzed Polyamide on Oil Reservoir Rocks

The exploitation of heavy oil fields has recently gained momentum due to increased investment in new oil and gas fields and especially due to environmental legislative constraints. That is why in this article I have described the possibility of using partially hydrolyzed polyacrylamide in the exploitation of heavy crude oil deposits, by injecting it into reservoir rocks followed by injection of reservoir water. The role of this polymer is to provide lubrication of the crude oil and water flow channels and especially to block (by reverse osmosis) the large pore communication channels in order to limit pressure leaks in uncontrollable areas. In the study we created two polymers that were used in order to increase the flow rate and decrease the viscosity and the freezing point (additives that are easy to procure and especially with spectacular results in the treatment of stills and without affecting the stability and quality of the final products refinery). We also studied the flow of the polymer through carbonate reservoir rocks, managing to obtain a numerical model that provides data on the rock resistance factor to the flow of partially fluidized polyacrylamide. The adsorption on the surface of the rocks determined the reduction of the mobility of the polymer but also the modification of the gel structure by the modification (crossing) of the polymer (of the polymer chains) which led to clogging (blocking of the pores) and increasing the possibility of fluid flow. In the laboratory we determined the adsorption of silicon for a solution of polyacrylamide of 0.05% partially hydrolyzed concentration in water, it increases from the value of 0.01 mg/m2 to 0.05 mg/m2 when the concentration in NaCl increases from 0 .5% to 10% in are we showed that adsorption increases for pH values ​​lower than 7, and it is stated that for a porous sand medium with a permeability of 140 mD, replacing saline water with 20 g/l NaCl, a presence of the polymer with a concentration of 400 ppm was observed in the effluent, and this value being approximately stabilized after 5 injected pore volumes.

An Integrated Numerical Study of CO2 Storage in Carbonate Gas Reservoirs with Chemical Interaction between CO2, Brine, and Carbonate Rock Matrix

In light of the burgeoning interest in mitigating anthropogenic CO2 emissions, carbonate reservoirs have emerged as promising sequestration sites due to their substantial storage potentials. However, the complexity of CO2 storage in carbonate reservoirs exceeds that in conventional sandstone reservoirs, predominantly due to the rapid interactions occurring between the injected CO2, brine, and carbonate rock matrix. In this study, a numerical model integrated with the chemical CO2–brine–rock matrix interaction was developed to analyze the carbonate rock dissolution process and the physical property variations of different carbonate gas reservoirs during the CO2 injection and sequestration process. More specifically, a total of twenty scenarios were simulated to examine the effects of lithology, pore size, pore–throat structures, and CO2 injection rate on carbonate rock matrix dissolution and reservoir property variation. Calcite is significantly easier and quicker to react with CO2-solvated brine than dolomite; as a result, limestones exhibit an expedited rock dissolution and pore volume increase, along with a slower pressure buildup in comparison to dolomites. Also, the carbonate reservoir with a smaller pore size has a higher rock dissolution rate than one with a larger pore size. Furthermore, the simulation results show injected CO2 can modify the pore-dominant carbonate reservoir to a more pronounced extent than the fracture-dominant carbonate reservoir. Lastly, the carbonate rock dissolution is more obvious at a lower CO2 injection rate. The insights derived from this research aid evaluations related to CO2 injectivity, storage capacity, and reservoir integrity, thereby paving the way for environmentally and structurally sound carbon sequestration strategies.

Characterization of Carbonate Reservoir Potential in Salawati Basin, West Papua: Analysis of Seismic Direct Hydrocarbon Indicator (DHI), Seismic Attributes, and Seismic Spectrum Decomposition

Carbonate reservoir of Kais Formation in Salawati Basin, West Papua, is the most famous oil and gas reservoir in the eastern part of Indonesian Archipelago since 1970’s. Nowadays, new prospects in this area are more challenging and most relevant near the infrastructure of previous oil and gas fields. In this study, a relatively new seismic dataset was investigated to figure out new prospects in carbonate reservoir rocks in the area of interest. In this preliminary study, where seismic data are not supported by well data, direct hydrocarbon indicator (DHI), seismic attribute, and spectral decomposition (CWT: continuous wavelet transform) allow the authors to characterize the reservoir geometry and to predict pore fluids within the reservoir rocks. The reservoir geometry of carbonate reef of Kais Formation (C1) was identified by seismic reflectors with high amplitude contrast at the top C1. The hydrocarbon indicator was predicted by DHI where dim spots, flat spots, and polarity reversals are indicative of hydrocarbon prospects. From the attribute analysis, the attribute instantaneous amplitude detected the top carbonate C1, whereas pore fluids were predicted from high sweetness attribute. In addition, spectral decomposition CWT method confirms the top C1, identified as saturated rock by the frequency of 10 Hz, 20 Hz, and 30 Hz. Based on a seismic study in the researched area, the target zone is expected to be a very promising hydrocarbon reservoir, specifically a carbonate reservoir. As a result, the preferred well-test location is in a region with access to the Kais Formation limestone reef layer. This study can assist in reservoir characterization, especially in areas with limited well control.

Selection of suitable geothermometers for predicting the subsurface temperatures with higher accuracy: A study based on globally distributed geothermal field data

Subsurface reservoir temperature of a geothermal province is popularly estimated using various geothermometers but it is necessary to examine the suitability of them. Present work studies the performances of five popular geothermometers Na-K, Na-K-Ca, Quartz, Chalcedony and K-Mg to forecast the reservoir temperature of 148 geothermal springs located in different parts of the world. The predicted temperature of the geothermometers have been compared with the bottom whole temperature (BHT) of the wells drilled in those geothermal fields to check the accuracy of the predictions.The results show that performance of a particular geothermometer is significantly affected by the type of rocks in a geothermal reservoir. Na-K geothermometer provides highest accuracy for the basaltic and sandstone reservoir rocks with average errors 15 % and 11 % respectively. The quartz geothermometer also provides almost equally good prediction for sandstone. The best result for a granitic reservoir rock is obtained by Na-K-Ca with an average error about 15 %. The carbonate reservoir rocks are the most difficult reservoir rock to use any geothermometer as lowest error of prediction using any geothermometer is about 26 %. The chalcedony performed the poorest among all geothermometers and is not recommended for any reservoir rock types under considerations. Thus, the study on global geothermal fields shows that the reservoir rock type must be considered to select a geothermometer else it may cause very high error in prediction of reservoir temperature. However, none of the geothermometer could produce error less than 10 %. It is worth noting that the present study though establishes the suitability of a geothermometer for a particular lithology, it does not explore the rationale for such a suitability.

Controls on fracture propagation in bioturbated carbonate rocks: Insights from the Aruma formation, central Saudi Arabia

Previous research has explored the linkage between bioturbation, porosity, and permeability in carbonate reservoir rocks. The impact of bioturbation on natural fractures in such rocks remains relatively unexplored, however, but is crucial for effective subsurface resource management. This study focuses on the relationship between bioturbation and fracture characteristics in a well-exposed outcrop, the upper Cretaceous Khanasir Member of the Aruma Formation, central Saudi Arabia. The approach includes field investigation, petrography, imaging analysis, and CT scanning to quantify the relationship between burrows and fracture characteristics at scales from thin section to outcrop scale. At the outcrop scale, the Khanasir Member comprises three distinct units based on their fracture and burrow characteristics. These units reveal two primary categories of fractures: (1) burrow-related fractures, influenced and controlled by bioturbation; and (2) non-burrow-related fractures, unaffected by bioturbation. The characteristics of fractures within these units are influenced by multiple factors including: if burrows are filled; composition of the burrow fillings; mineralogy of host rock matrix; texture of the host rock matrix; and burrow percentage. The interplay of these factors affects fracture attributes such as density, length, and spacing, all of which have a direct impact on fluid flow behavior within subsurface reservoirs.

Determination of the oil saturation coefficient according to Dakhnov–Archi using a new methodological approach when studying core samples

Background. Predisposition of the rock to wetting by water (hydrophilicity) or oil (hydrophobicity) has a significant influence on the results of determining the oil saturation coefficient according to Dakhnov–Archi. Carbonate reservoir rocks in most cases are characterized by a complex type of wettability: heterogeneous (selective), mixed or neutral wettability. Collectively, the surface properties of such rocks can be defined by the term “nonhydrophilic wettability”. Studying rocks with nonhydrophilic wettability using standard core research methods can lead to subsequent errors in calculating oil reserves using the volumetric method. Objective. To eliminate the risk of such errors by adapting standard research methods, in particular the centrifugation method, to the results of experiments in reservoir conditions. Materials and methods. Capillarimetric method (semipermeable membrane method), centrifugation method, core “aging”. Results. The results of core studies necessary for calculating the oil saturation coefficient of nonhydrophilic reservoirs using formation resistivity data using the Dakhnov–Archi method are presented. A methodological approach is proposed for adapting the centrifugation method to reservoir conditions. Conclusions. The applied methodological approach makes it possible to increase the volume of statistical data and calculate an adequate value of the oil saturation coefficient according to Dakhnov–Archi for nonhydrophilic reservoirs.

The research on high efficiency water injection development of carbonate rock reservoir in the middle east

More and more attention has been paid to the waterflood development of carbonate reservoir in the Middle East with continuous expansion of the scale of carbonate reservoir development. Strong non-homogeneity of carbonate reservoirs results in serious conflicts between injection and production, causing low degree of water-driven control in the well network, and low degree of vertical mobilization. This article takes the main reservoir of an oil field in the Middle East region as an example, combining geological evaluation, dynamic analysis, and reservoir development strategies to study the effectiveness of water injection development in carbonate reservoirs. It shows that there is a correlation between pore type, oil-water relative permeability, and development method in the development of carbonate reservoirs. For reservoirs with matrix pores and micropores, water injection should be strengthened in the later stage of development; for reservoirs with dissolved pores and coarse pores, the iso-permeability point is relatively high, and the later development should focus on balanced water injection. Three different waterflooding models for formation development are designed to verify the feasibility of fine waterflooding schemes. The main differences are that one set of well patterns is combined injection and production, and three sets of well patterns are layered system waterflooding. The results show that the development effect in layered system waterflooding is the best. The daily production can be increased by about 16%, the cumulative oil production can be increased by about 8%, and the recovery factor can be increased by about 3%. Eventually, the stable oil and water control of carbonate reservoir can be realized.

Molecular dynamics simulation and key performance study of VES self-diverting acid system for deep carbonate reservoirs

Viscoelastic Surfactant (VES) self-diverting acid technology is an ideal approach for enhanced recovery from heterogeneous reservoirs. Most VES self-diverting acid systems currently used in field operations are only suitable for low-temperature reservoirs, and research on self-diverting VES acid systems for deep carbonate rock formations is lacking. Additionally, studies on the molecular dynamics of the self-assembly of VES have mainly focused on cationic surfactants, with insufficient research on the self-assembly of betaines in the oil industry. This study investigated the effects of temperature, surfactant concentration, and metal ion concentration on the self-assembly of erucamide propyl hydroxysulfobetaine (EHSB) based on a self-assembly model through molecular simulation methods. Moreover, the viscosity of the EHSB was predicted under various conditions. The results indicated that the system viscosity was optimal at an EHSB concentration of 4 wt%. The EHSB system requires initiation by metal ions to enhance the viscosity, with Ca2+ having a more pronounced effect than Mg2+. This is attributed to the formation of a unique “octahedral” structure by Ca2+ in solution, which aids in the formation of large micelles. Furthermore, because of the smaller ionic radius of Mg2+ compared with that of Ca2+, Mg2+ is more likely to penetrate micelles and form salt bridges, promoting a tighter arrangement of surfactant molecules. Based on molecular simulation and laboratory experiments, under optimal concentrations of inorganic salts and EHSB, the system’s viscosity remained greater than 150 mPa·s at 140 °C, meeting the requirements for diversion in deep carbonate rock formations. Finally, the acidization capacity and diversion effects of the acidic system were demonstrated using single-core flood and dual-core diversion experiments. The results showed that the acid solution significantly etched the core, and the residual acid reduced the permeability contrast of the core from 3.54 to 2.35, indicating a good acidizing diversion performance. This study utilizes a combination of computer simulations and laboratory experiments to optimize a VES self-diverting acid system. The computer-predicted viscosity corresponds well with the actual measured viscosity, providing new technical insights for evaluating the performance of VES under complex formation conditions that are unattainable through laboratory tests. A self-diverting VES acid system suitable for deep carbonate rock reservoirs at 140 °C was developed, providing technical support for the efficient development of deep carbonate reservoirs.

An enhancement in the petrophysical evaluation in a vuggy carbonate gas reservoir by integrating the core data and empirical methods, Zagros basin, south of Iran

The presence of vuggy pore types poses challenges in accurately assessing effective porosity. This study focuses on the significant scientific issue of improving petrophysical evaluation in vuggy carbonate gas reservoirs. The Kangan Formation is one of the main gas reservoir formations in the southern Zagros region, Iran. The main objective of the current research is to distinguish and exclude the influence of vuggy pore types from effective porosity in the reservoir pay zones of the Kangan reservoir.In the current research, a combination of full suite logs, image logs, core analysis, and thin section studies was employed. The image logs illustrate that vuggy porosity is abundant in the Kangan Formation and these results are confirmed by the available core thin sections, specifically in Zone Kangan_B; Additionally, the cross plots of compressional velocity versus bulk density and total porosity, as a part of rock physics study, indicate the characteristics of the vuggy reservoir. Two methods are utilized to quantify vuggy porosity. The first method, the Velocity Deviation Log (VDL) approach, identifies various available pore types, especially vugs. The second method is a newly proposed approach that can exclude vuggy porosity from the computed effective porosity. In this novel approach, a variable porosity exponent (m) is derived by adopting the Lucia equation to exclude vuggy porosity from the effective porosity computations. Thus, petrophysical evaluation can be implemented based on the constant and variable “m”. Comparing both petrophysical results, it is evident that the amounts of effective porosity and water saturation are modified in the vuggy-bearing intervals. Applying the proposed approach will improve the accuracy of petrophysical properties and lead to the proper calculation of the hydrocarbon volume in the carbonate reservoir rocks containing isolated vugs, particularly in gas-bearing reservoirs where conventional logs are affected by gas contents.

Fracture identification and characterization of Ordovician carbonate rock reservoir in block B of the Tahe oilfield

Fracture identification and characterization of Ordovician carbonate rock reservoir in block B of the Tahe oilfield

Adsorption mechanism study of sour natural gas and sulfur in high-sulfur carbonate rock gas reservoirs

As the world pivots towards green and renewable energy sources, natural gas stands out as a clean and efficient alternative. In particular, there has been an upsurge in the exploration and development of gas fields rich in hydrogen sulfide (H2S). However, an escalating issue of sulfur deposition is notably pronounced in carbonate rock reservoirs predominantly comprised of dolomite, as exemplified in China's Yuan Ba gas field. This study examines sulfur adsorption in high-sulfur gas reservoirs and its effects on carbonate rock formations. Molecular simulation analysis reveals that the sour natural gas density in 20 Å dolomite nanopore structure experiences an average increase of 30% at the nanoscale. Notably, CO2 and H2S manifested strong adsorption tendencies in smaller pore sizes, with CO2's strong adsorption state layer thickness measuring approximately 2.93 Å, and H2S's at about 1.871 Å. Additionally, it was found that the adsorption energy of sour natural gas decreases with rising temperature and pore size, and falling pressure, yet the temperature's effect on excess adsorption density is minor above 40 MPa. As the pore size reaches 160 Å, the strong adsorption states of CO2 and H2S dissipate. Beyond 160 Å, the influence of nanoscale dimensions is negligible, with only a 2.23% increase in adsorbed phase density compared to the bulk phase. The introduction of S8 molecules amplified the adsorption proclivities of CO2 and H2S, urging them closer to the pore wall. The study reveals that CO2 or H2S reinjection into formations could effectively mitigate sulfur deposition in pores smaller than 160 Å, offering valuable insights for the development of high-sulfur gas fields.