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Predicting facies and petrophysical properties along and between wells is challenging in carbonate reservoir modeling. In the Nullipore carbonate reservoir, Ras Fanar field, depositional and long-term diagenetic processes result in a high degree of heterogeneity and complex distribution of facies, which in turn affect the reservoir quality. This provides a significant obstacle to building accurate geological models. This study integrates thin sections, routine core analyses, and well logging data to overcome such difficulties and model the Nullipore carbonate facies and permeability. The detailed petrographic analysis revealed the existence of seven microfacies in the reservoir, which are summed up into three facies associations (FAs), each of which represents a specific reservoir rock type (RRT): (1) supratidal FA, (2) intertidal FA, and (3) shallow subtidal FA. The three FAs were correlated with the gamma-ray logs to create facies logs for the studied wells, which were further populated via the Truncated Gaussian Simulation method. Cross-validation was used to evaluate the model's accuracy. The analysis of the available core data infers that the three RRTs are prospective and have a wide permeability distribution. However, RRT3 constitutes the best reservoir quality. The sedimentological analysis revealed that the long-term diagenetic events, involving the dolomitization of limestone and the dissolution of allochems have a major role in improving the pore connectivity and permeability of the reservoir. Fracture characterization discloses that fractures play a significant role in fluid storage and migration. Three Machine Learning (ML) models, including Adaptive boosting (AdaBoost), Gradient Boosting (GB), and Extreme Gradient Boosting (XGB), were developed to integrate the RRTs, porosity, and permeability to improve permeability prediction. Statistical analysis revealed that the XGB model outperforms other models and exhibits the highest prediction performance. The present study provides further insights into the characterization and modeling of facies and permeability of complex carbonate reservoirs. It can be applied in similar geological settings to better interpretation of depositional and diagenetic controls on reservoir quality assessment and aid in the field development plan. [ABSTRACT FROM AUTHOR]

Carbonates in the Lower Cretaceous (Barremian to early Aptian) Kharaib Formation are reservoir rocks at giant oil fields in the UAE and Qatar. The Barremian Kharaib‐2 member (K60), the focus of this study, is in general composed of a regionally continuous succession of high‐energy, shallow‐water limestones bounded above and below by "dense" low‐energy mud‐rich strata. Despite several decades of research, conventional carbonate facies classification schemes and resulting facies groupings for the Kharaib‐2 member have failed to show a statistically acceptable correlation with core‐ and log‐derived petrophysical data. Moreover, sedimentary bodies potentially responsible for dynamic reservoir heterogeneities have not clearly been identified. This paper proposes a standardized facies classification scheme for the Kharaib‐2 carbonates based on vertical facies proportion curves (VPCs) and variogram analyses of core data to construct stratigraphic correlations at both field and regional scales. Data came from 295 cored wells penetrating the Kharaib‐2 member at ten fields in the on‐ and offshore UAE. Thin, dense intervals separating reservoir units were adopted as fourth‐order transgressive units and were used for stratigraphic correlation. Field‐scale probability maps were used to identify sedimentary bodies such as shallow‐water rudistid shoals. Regional stratigraphic correlations of the Kharaib‐2 member carbonates based on the VPCs identified variations in depositional environments, especially for the lower part of the reservoir unit; depositional facies at fields in the SE of the UAE were interpreted to be more distal compared to those at offshore fields to the NW. At a field scale, the VPCs failed to identify significant lateral variations in the carbonates. However, variogram analyses of cored wells showed spatial concentrations of specific facies in the inner ramp domain which could be correlated with high‐energy depositional bodies such as shoals dominated by rudist debris. The bodies were sinusoidal in plan view with lengths of up to 8 km and widths of ca. 1 km. Although similar‐shaped bodies with these dimensions have been reported from other carbonate depositional systems, they have not previously been reported in the Kharaib Formation. At a regional (inter‐field) scale, the stratigraphic correlation of standardized sedimentary facies remains problematic; however, mapping of facies associations and their relative proportions relative to their environments of deposition demonstrated new patterns for the stratigraphic architecture of the Kharaib‐2 member in the UAE. [ABSTRACT FROM AUTHOR]

Previous attempts to classify flow units in Iranian carbonate reservoirs, based on porosity and permeability, have faced challenges in correlating the rock's pore size distribution with the capillary pressure profile. The innovation of this study highlights the role of clustering techniques, such as Discrete Rock Type, Probability, Global Hydraulic Element, and Winland's Standard Chart in enhancing the reservoir's rock categorization. These techniques are integrated with established flow unit classification methods. They include Lucia, FZI, FZI*, Winland R35, and the improved stratigraphic modified Lorenz plot. The research accurately links diverse pore geometries to characteristic capillary pressure profiles, addressing heterogeneity in intricate reservoirs. The findings indicate that clustering methods can identify specific flow units, but do not significantly improve their classification. The effectiveness of these techniques varies depending on the flow unit classification method employed. For instance, probability-based methods yield surpassing results for low-porosity rocks when utilizing the FZI* approach. The discrete technique generates the highest number of flow unit classes but provides the worst result. Not all clustering techniques reveal discernible advantages when integrated with the FZI method. In the second part, the study creatively suggests that rock classification can be achieved by concurrently clustering irreducible water saturation (SWIR) and porosity in unsuccessful flow unit delineation cases. The SWIR log was estimated by establishing a smart correlation between porosity and SWIR in the pay zone, where water saturation and SWIR match. Then, the estimated saturation was dispersed throughout the reservoir. Subsequently, the neural network technique was employed to cluster and propagate the three finalized flow units. This methodology is an effective recommendation when conventional flow unit methods fail. The study also investigates influential factors causing the failure of flow unit classification methods, including pore geometry, oil wettability, and saturation in heterogeneous reservoirs. [ABSTRACT FROM AUTHOR]

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The residual oil left behind after water flooding in petroleum reservoirs can be mobilized by surfactant formulations that yield ultralow interfacial tension (IFT) with oil. However, finding ultralow IFT surfactant formulations is difficult for high-temperature, off-shore, carbonate reservoirs. These reservoirs are often water-flooded with seawater (with a lot of divalent ions), which is often incompatible with many surfactants at high temperatures. The goal of this research is to develop a surfactant formulation for an off-shore carbonate reservoir at 100°C previously flooded by seawater. Surfactant-oil-brine phase behavior was studied for formulations, starting from a single surfactant to mixtures of surfactants and a co-solvent. Mixtures of three surfactants and one co-solvent were needed to produce ultralow IFT formulations for the oil of interest. The surfactant system with polymer mobility control was tested in crushed reservoir rock packs. The cumulative oil recovery was >99% for the surfactant-polymer (SP) flood with an optimal salinity gradient. The constant salinity SP floods with seawater increased oil recovery significantly beyond the water flood (cumulative oil recovery >91%), even though the recovery was lower than that of the optimal salinity gradient SP flood. Our experimental work demonstrates the effectiveness of the surfactant formulation for a high-temperature carbonate reservoir at seawater salinity. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

A comprehensive drilling of wells has been conducted in the Permian Qixia Formation in the central Sichuan Basin, revealing a significant number of dolomite reservoirs. High- and medium-porosity dolomite reservoirs are the main gas-producing reservoirs in the Qixia Formation. Seismic PP-wave data show a "bright spot" for high-porosity dolomite reservoir formations but weak responses for medium-porosity dolomite reservoir formations, which is attributed to the inability of P waves to distinguish between medium-porosity reservoirs and limestone. However, medium-porosity dolomite and limestone have different S-wave velocities. Therefore, in this study, the identification of different-porosity dolomite reservoirs using multi-component seismic data was investigated. A comprehensive analysis of the elastic waves by forward modeling shows that the PS-wave amplitude is more sensitive to medium-porosity dolomite than the PP-wave amplitude. Therefore, medium-porosity dolomite reservoirs can be predicted using the amplitude attributes of the PS-wave, and high-porosity dolomite reservoirs can be characterized using the PP-wave. Meanwhile, the elastic parameter λρ (the product of Lame constant λ and density ρ), which is highly correlated with the dolomite content, can be used as an indicator of dolomite formations. Furthermore, compared to the results of PP-wave inversion, the elastic parameters derived from the joint inversion of PP- and PS-waves exhibited a better correspondence with the well-logging results. The comprehensive use of the seismic amplitude responses of PP- and PS-waves and multi-component seismic joint inversion can effectively predict high- and medium-porosity dolomite reservoirs. The predicted results can support the exploration and development of the Qixia Formation. [ABSTRACT FROM AUTHOR]

Rock types with similar lithological components and pore structures form the basic units of porous limestone reservoirs; this influences the reservoir evaluation efficiency and water injection development. As the main oil and gas pay zone in central Iraq, the Cretaceous Khasib Formation reservoirs are influenced by deposition, dissolution, and cementation. There is strong vertical heterogeneity in the most important zone of the Kh2 layer, with diverse rock types and complex pore structures. Based on core observation and casting thinsection identification, the Kh2 layer in the study area was divided into eight lithofacies types as argillaceous bioclastic wackestone, planktic foraminiferium wackestone, lamellar bioclastic wackestone, intraclastic-bioclastic packstone, patchy green algae packstone, green algae and pelletoid packstone, benthic foraminiferium-bioclastic packstone, and intraclastic grainstone. Along with the reservoir void space types of the lithofacies, capillary pressure curves are used to quantitatively analyze the throat and pore features of the different lithofacies. From the porosity-permeability cross-plot characteristics and distribution of pore types, 14 petrophysical facies are obtained. Finally, based on the differences between the lithofacies and petrophysical facies, the Kh2 member is divided into 13 rock types with different geological origins and petrophysical characteristics. Among these, the rock type RT1-8-14 has the best and rock type RT1-1-1 has the worst physical properties among the reservoir rock types. This study provides an optimization method for carbonate reservoir evaluation and is expected to be beneficial for efficient development of similar carbonate reservoirs. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Copyright of Iraqi Journal of Chemical & Petroleum Engineering is the property of Republic of Iraq Ministry of Higher Education & Scientific Research (MOHESR) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Assessing fractures in carbonate reservoirs is crucial due to their substantial impact on reservoir permeability. Understanding the characteristics of these fractures is vital for optimizing oil production. Additionally, extremely heterogeneous and anisotropic permeability distribution within the natural fractured reservoir is often caused by the complexity of a fracture network. Therefore, accurate reservoir modelling and simulation must be conducted in order to achieve ultimate recovery. In this paper a sector model has been developed based on the studied example field, its results are compared with the full reservoir model to find out the degree of resemblance between their outputs. The study area has four natural fracture compartments, with an average reservoir height of 95m and water/oil contact (WOC) and gas/oil contact (GOC) depths of 685 m and 590 m, respectively. A dual-porosity with single-permeability modelling system was used to simulate the properties of the reservoir rock. This model was derived from the Petrel layercake model. A sensitivity analysis was also carried out to look into the relationships between field performance and the well. The outcomes of both models demonstrated that matrix permeability and fracture dimension had a significant impact on the early breakthrough of water and gas to comparable huge extents. While other factors, such as aquifer size and WOC, show a moderate impact on water and gas breakthrough as well as final recovery. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

This study investigates the adsorption behaviors of surfactants in sandstone reservoir rocks containing various amounts of carbonate cement/minerals and their impact on wettability alteration under low‐salinity conditions. Two types of rock samples from sandstone reservoirs of Assam oilfields in India are selected based on XRD results. These rock types are (i) high carbonate cement (HCC) core sample with higher carbonate cement (calcite 5.6% and dolomite 4.0%), and (ii) low carbonate cement (LCC) core sample with lower carbonate cement (calcite = 0.5% and dolomite 0%). The study reveals that the mineralogy of sandstone reservoir rocks especially the carbonate minerals affects the brine‐rock interactions including wettability alternation and surfactant adsorption. Notable differences (2° to 8°) in contact angles for the two rock types at different salinities revealed that carbonate cement in sandstone thus impacts brine‐rock interactions. Further, low salinity surfactant (LSS) could positively alter the wettability of both rock types to water‐wet conditions (contact angle <60°). The most favorable wettability alterations (up to 30°) were achieved with cationic LSS solutions for both core types. Using LSS solutions also reduced the adsorption of anionic surfactant by around 40% and 33% for HCC and LCC rock samples, respectively. The study's novelty emanates from investigating the impact of sandstone reservoir rock mineralogy with varying amounts of carbonate cements on the adsorption behavior of surfactants under low‐salinity conditions. Moreover, this study provides a better understanding of the interrelationship existing between the degree of wettability alteration and the amount of surfactant adsorbed by sandstone rocks. [ABSTRACT FROM AUTHOR]

Deep-buried marine carbonate reservoirs in the Tarim Basin present challenges for exploration. A regional unconformity in dolomite at the top surface of the Shuiquan Formation makes the carbonate rocks ideal reservoirs. This study determines the unconformity belt distribution, lithology, reservoir space types and the controlling factors of the Shuiquan Formation, to establish a paleokarst development model and predict the favourable exploration targets. By flattening the seismic-event section and tracking truncation points on the seismic profiles, the unconformity area and denudation trends of the Shuiquan Formation are identified. The denudation area appears on a NEE-trending plane as a band with a width of 10–20 km and a thickness that expands from the depression to the slope and uplift. The Sinian Shuiquan Formation developed in a carbonate platform–tidal flat environment. Outcrop, core, well logging, and thin-section observations reveal that the lithology of the Shuiquan Formation consists of crystalline dolomite and granular dolomite, with pore types that include intercrystalline dissolution pores, intercrystalline pores and structural fractures. Unconformity, karstification and tectonic activity with atmospheric freshwater leaching, storage space and communication channels, respectively, are considered crucial factors influencing carbonate reservoir formation in the study area. A prediction model for the carbonate reservoirs in the Tadong area shows that the strong karst belt on the slope is the ideal area for forming a carbonate reservoir. A regional unconformity at the top surface of the dolomite of the Shuiquan Formation makes the carbonate rocks favourable reservoirs. Sedimentation, unconformity, karstification and tectonic activity play an important role in controlling reservoir formation and evolution. The high-angle unconformity slope belt with long-term exposure and atmospheric freshwater leaching is the ideal area for large-scale epigenetic karst reservoir reconstruction and formation. [ABSTRACT FROM AUTHOR]

The primary goal of a carbonate reservoir study is to precisely predict the reservoir rock and fluid properties and their controlling factors in the associated reservoir body from the limited data available from cores and logs (bore-holes). However, carbonate reservoir cannot be characterized using the conventional single-continuum concept like a sandstone reservoir; and it essentially requires a multicontinuum approach due to the associated heterogeneity. Thus, capturing the spatial and temporal distribution of reservoir rock and fluid properties remain to be of prime importance in a carbonate reservoir. Despite such importance, relatively fewer studies have focused on carbonate reservoir characterization. This study has made an attempt to provide the complexities associated with the characterization of carbonate reservoir with reference to their rock and fluid properties, which remain associated with various scales. This study is expected to provide deeper insights on further investigation of carbonate reservoir characterization, which would essentially help to bridge the gap between laboratory-scale observations with that of a real field-scale scenario. [ABSTRACT FROM AUTHOR]

Injection of smart water into reservoirs for recovery enhancements remains a low-cost and an environmentally safe method of enhanced oil recovery (EOR). However, a definitive explanation for the incremental recovery enhancement, or lack thereof, is far from established and the research, therefore, continues to be very active. This study investigates the effect of divalent ion-based modified brines on wettability alteration in carbonate reservoirs. The focus is on analyzing wettability alteration via integrating precise quantitative zeta potential measurements and contact angle analysis. Experiments were carried out on carbonate core-plug samples analyzing the impact of various brines, including formation brine, seawater, low salinity, and engineered smart water. Specific formulations were prepared using softened seawater with multiple dilution factors and optimized phosphate and hexametaphosphate concentrations. To establish the baseline wetting state, core-plug samples were aged with the respective light crude oil and formation brine from a giant Abu Dhabi carbonate oilfield. Wettability alteration confirmed by changes in contact angles was recorded over a span of 72–80 h with each of the tested brines. Zeta potential measurements were performed utilizing a reproducible approach on the same core-plug samples at all stages of the experiments. The integrated measurements presented important conclusions on the effect of ionically modified smart brines on wettability alteration. [ABSTRACT FROM AUTHOR]

Lower Cretaceous carbonates of the Fahliyan Formation form prolific reservoir rocks at oilfields in the Dezful Embayment, central Zagros fold‐thrust belt, SW Iran. The carbonates have undergone significant diagenetic alteration in phases which can in general be linked to the pre‐, syn‐ and post‐tectonic evolution of the fold‐thrust belt. This paper investigates the impact of diagenetic processes on the reservoir quality of the carbonates using integrated petrographic, geochemical and sedimentological analyses of subsurface and outcrop samples of the formation. Diagenetic alterations include: (i) pre‐tectonic eogenesis in the marine and shallow‐burial realm, which resulted in micritization of allochems and cementation by equant and isopachous calcite rims and framboidal pyrite together with limited dolomitization and dissolution of metastable bioclasts. The isotopic compositions of micrite and early calcite cement depart from postulated values of Lower Cretaceous marine carbonates, signifying early stabilization of precursor metastable carbonate minerals and the possible effects of the incursion of meteoric waters and/or increasing burial temperatures; (ii) mesogenesis during the subsequent syn‐tectonic phase, which included Late Cretaceous ophiolite obduction at the northern margin of the Arabian Plate and the later Zagros orogeny in the Miocene‐Pliocene. Diagenetic modifications included the emplacement of hydrocarbons, the development of stylolites and fractures, and the precipitation of saddle dolomite, replacive rhombic dolomite, discrete pyrite, microcrystalline quartz, kaolin and anhydrite. The average stable isotope compositions of saddle dolomite (δ18O: ‐6.9 ‰ ±.9 and δ13C 0.5 ‰ ± 1.6, respectively) also reflects the influence of high temprature basinal fluids; and (iii) "late" (telogenetic, post‐tectonic) uplift‐related modification starting in the Pliocene, when the incursion of meteoric waters resulted in the formation of vugs, the calcitization of dolomite, and cementation by fracture‐filling blocky calcite. The negative δ18O and δ13C stable isotope values (average: ‐5.5 ‰ ± 1.5; and ‐3.6 ‰ ± 5.9, respectively) of late blocky calcite cement suggest the incursion of meteoric water into the system. This study demonstrates that diagenetic processes in carbonates in the Fahliyan Formation, which exerted a significant control on the distribution of secondary porosity, can be related to the tectonic evolution of the central Zagros fold‐thrust belt. Thus, constraining the diagenetic history of carbonate successions within the context of their wider tectonic evolution is important for the prediction of the spatial and temporal distribution of reservoir quality. [ABSTRACT FROM AUTHOR]

This study analyzes the impact of injection condition design factors of (3-glycidoxypropyl)trimethoxysilane (GPTMS)–SiO2 nanofluid on improving wettability and oil recovery through flotation and core flooding tests, respectively. Flotation tests were conducted to assess improvements in wettability that resulted from varying nanoparticle concentration, reaction time, and treatment temperature. The test results demonstrated that the hydrophilic sample ratio increased by up to 97.75% based on the nanoparticle reaction, confirming significant wettability improvement in all samples. Additionally, time-dependent fluid-flow experiments were conducted to validate oil recovery and rock–fluid interactions. In these experiments, for a 24-h reaction time, nanofluid injection caused a decrease in the maximum contact angle (43.4° from 166.5°) and a remarkable enhancement in the oil recovery rate by over 25%. Moreover, variations in contact angle and sample permeability were observed as the reaction time increased. Subsequently, the core flooding test revealed a critical reaction time of 24 h, maximizing oil recovery while minimizing permeability. Below this point in time, wettability improvement did not significantly enhance oil recovery. Conversely, beyond this threshold, additional adsorption due to particle aggregation decreased permeability, causing reduced oil recovery. Therefore, GPTMS–SiO2 nanofluid can be utilized as an injection fluid to enhance oil recovery in high-temperature and high-salinity carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Water flooding has already been shown to be one of the most cost-effective ways to enhance oil recovery in carbonate reservoirs. The main obstacle of this type of reservoir is the low recovery rate due to the oil-wet rock surfaces and modifying the chemistry of water injection could significantly increase oil production. This article aimed at the optimization of salinity and composition of divalent ions in Smart water flooding in dolomite reservoir rocks. Contact angle measurements performed in two steps to screen and select the optimal composition among several types of waters. Core flooding experiments conducted to evaluate the performance of the chosen waters in two different scenarios; It was carried out in three steps including brine (FW) injection, followed by best water (RW) and finally smart water (RW2S) and the second scenario was applied in reverse. Maximum recovery of 59.65% original oil in place (OOIP) was recorded for the second scenario and a lower recovery of 50.72% OOIP was observed for the first. Experimental results confirms that a higher concentration of sulfate ions enhances the water-wetness of dolomite rocks and two main mechanisms behind the smart water injection are wettability alteration and pH increase. [ABSTRACT FROM AUTHOR]

Cementation exponent or factor is one of most crucial factors in the Archie's equations that should be estimated precisely in order to accurately determine relevant petrophysical characteristics of the reservoir. Inaccurate estimation of this factor leads to incorrect petrophysical analysis and inaccurate determination of water saturation which is highly important for the economic forecasting of hydrocarbon reservoirs. An alternative to the cementation factor precise estimation is to classify rocks based on a common petrophysical property such as permeability. This research aims to investigate the cementation factor in different rock types and eventually to provide a suitable model for estimating this parameter based on different approaches of rock classification. In this paper, first, conventional methods of rock classification (e.g., current zone indicator (CZI), flow zone indicator (FZI), permeability and electrical efficiency) have been used for cementation factor estimation. Then, the data, taken from Regnet et al. (J Geophys Res Solid Earth 120:790–811, 2015), have been analyzed by these methods in order to find the best way of rock classification. The analyzed data show that only electrical efficiency method is accurate enough to classify rocks into different groups as high values of determination coefficient (i.e., 0.9828 and 0.9725) are obtained as a result of classification by this method in which the data are classified into distinct groups. The obtained values of determination coefficient as a result of classification by permeability, FZI and CZI methods are 0.805, 0.809 and 0.7568 respectively. Due to this result and high scattering of the classified data, it can be concluded that these three methods have not been precise enough for rock classification of the data. In addition to the above-mentioned existing methods, a new rock classification method based on tortuosity coefficient or factor has also been proposed in this paper. This new method has been proven to be accurate due to low scattering of the data results and falling them into distinct groups in addition to obtaining high values of determination coefficient (i.e., 0.9996, 0.9986 and 0.9951) in the classification by this new method. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Mohr–Coulomb failure criterion is vastly employed to understand the risk of collapse of the highly stressed boreholes in oil and gas industries. It is, thus, important to measure the shear strength parameters of Mohr–Coulomb criterion for reservoir rocks in terms of simple input data to easily mitigate the risks of collapse. For this purpose, 59 core plugs from four carbonate oil fields located in Abadan Plain were tested under triaxial stress to measure shear strength parameters (internal friction angle and cohesion). Then, these parameters were estimated based on a novel approach using petrographic properties. Fuzzy clustering (FCM) were initially imployed to cluster the input data followed by developing the adaptive neuro-fuzzy inference system (ANFIS) and interconnecting ANFIS to particle swarm optimization algorithm (PSO-ANFIS) and genetic algorithm (GA-ANFIS). The input parameters of the developed models are petrographic features, including rock texture (Tex.), sedimentary environment (SE), quartz and pyrite content (QP), micrite index (MI), and porosity (Por.), obtained from optical microscopy and XRD analyses. To compare the performance of the models, some statistical metrics were measured. A credibility assessment of the prediction performances reveals that the combination of evolutionary algorithms with ANFIS can be a practical technique to reduce the uncertainties related to shear strength parameters approximation. Therefore, PSO-ANFIS is considered as a promising method for the prediction of shear strength parameters of the studied limestones with R2 > 0.93 and RMSE < 3.15. Finally, the estimated shear strength parameters are compared and validated with the literature results. Highlights: Extracting novel petrographic parameters of carbonate reservoir rocks. Measuring shear strength parameters under reservoir condition using multi-stage triaxial test. Estimating shear strength parameters using ANFIS based models including PSO and GA. PSO-ANFIS model showed higher accuracy and performance of the best. [ABSTRACT FROM AUTHOR]

The catalytic activity of metal oxides in the processes of low- and high-temperature oxidation (LTO and HTO, respectively) of oil was studied on model systems consisting of oil-saturated quartz sand with additives of Al2O3, Cr2O3 and MgO using thermal analysis methods. The used additives were shown to shift the LTO and HTO processes to the low-temperature region. The catalytic activity of a natural reservoir carbonate rock without and with water was studied. This study established that at room temperature in dry carbonate rock, the oil components undergo dealkylation and polycondensation of aromatic fragments for a week. In the presence of water, the polycondensation processes are suppressed, and the cracking of resin and asphaltene occurs. The cracking reactions lead to a decrease in the content of heteroatoms in resins and asphaltenes. [ABSTRACT FROM AUTHOR]

This study aims to improve rock-type classification by analyzing core data based on the water–oil primary drainage capillary pressure method. A modified empirical equation is proposed using permeability, porosity, and irreducible water saturation to classify rock types based on water–oil primary drainage capillary pressure. We used primary drainage capillary pressure data measured in carbonate and sandstone samples in the Ahvaz Asmari and Mansouri oilfields to evaluate the characterization number (Cn) method. This study consists of two main parts. First, the Cn method is introduced to rock typing, and the permeability is calculated from well log data. In the second part, we present rock-type classification when the water saturation of the formation is more than the irreducible water saturation. The novelty of this work is a simple and efficient technique to rock-type classification using the Cn method. In addition, we present a procedure to assign rock types for the transition zone using the Cn method. Moreover, this study systematically investigates the role of irreducible water saturation in rock typing. The innovation of this work lies in its ability to classify rocks in heterogeneous reservoirs for carbonate and sandstone lithology and allow for the calculation of permeability more accurately from well log data. The comparison results between the Cn method and the flow zone indicator method show the robust clustering ability of the Cn method. [ABSTRACT FROM AUTHOR]

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In deep karst reservoirs, the internal environment is complex, and thermal stratification isnot the only factor controlling the vertical distribution of the DIC concentration. Previous studies have not fully understood the migration and transformation of DIC in a deep-water reservoir. In this study, a deep-water reservoir in southwest China was chosen, and the spatial and temporal characteristics of the DIC concentration, pCO2, δ13CDIC value, and SIc were investigated. It was found that the Pingzhai Reservoir is a double temperature leapfrog reservoir. The DIC concentration, pCO2, Sic, and δ13CDICvalues showed annual cycle variation. During the thermal stratification phase, the DIC concentration, pCO2, Sic, and δ13CDICvalues were significantly different between the surface layer and the lower layer. However, during the mixing and mixed phases, the differences were not significant. The vertical divergence of the DIC in the Pingzhai Reservoir was influenced by the subtemperate layer, human activities, and sources. The formation of the subtemperate layer was due to the submerged flow formed when river water enteredthe reservoir, which provides a channel for DIC from the river to enter the lower layer of the reservoir. Human activities increased the solubility of carbonate rocks in the reservoir, and the source of DIC was one of the factors contributing to the concentration stratification of DIC in the reservoir. [ABSTRACT FROM AUTHOR]

Oil in the Jarvis structure underlying the main Upper Jurassic reservoir at the Ettrick oilfield (Outer Moray Firth, UK northern North Sea) is present in Upper Permian (Zechstein) carbonates. The origin of this "Jarvis oil" is investigated in this paper using a multidisciplinary approach based on data from well‐logs and cores from wells 20/02‐2 and 20/02‐3. Reservoirs at the Jarvis structure consist of carbonates in the upper part of the Halibut Carbonate Formation (Ca2) and in the Carbonate Member of the Turbot Anhydrite Formation (Ca3). These carbonates are typical Zechstein dolomites composed of a range of facies from mudpackstones with storm beds deposited at moderate water depths to shoreface bioclastic‐oolitic packstones to shallow‐subtidal and intertidal microbial laminites. Interbedded anhydrites replace sabkha and lagoonal selenitic gypsum. Several shallowing‐upward units are recognised. Molecular analysis of the Jarvis oil, and comparisons with biomarker and other geochemical data from extracts of Zechstein cores and published data from different source rocks from the North Sea area, suggest that the oil was generated by marine, OM‐rich shales in the Upper Jurassic Kimmeridge Clay Formation. The oil was generated at peak oil window maturity and is characterised by high Pr/Ph, BNH/H and DBT/P ratios, and abundant C28 steranes and C28+29 monoaromatic and C26R + C27S triaromatic steroids. The molecular composition of organic material in extracts of core samples of Zechstein carbonates from wells in the Jarvis structure differs significantly from that of the Jarvis oil. Biomarkers such as BNH are absent in the core extracts, and there are different distributions and abundances of saturated and aromatic hydrocarbons, likely controlled by thermal maturity. [ABSTRACT FROM AUTHOR]

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In this work, geochemical modelling using PhreeqC was carried out to evaluate the effects of geochemical reactions on the performance of underground hydrogen storage (UHS). Equilibrium, exchange, and mineral reactions were considered in the model. Moreover, reaction kinetics were considered to evaluate the geochemical effect on underground hydrogen storage over an extended period of 30 years. The developed model was first validated against experimental data adopted from the published literature by comparing the modelling and literature values of H2 and CO2 solubility in water at varying conditions. Furthermore, the effects of pressure, temperature, salinity, and CO2% on the H2 and CO2 inventory and rock properties in a typical sandstone reservoir were evaluated over 30 years. Results show that H2 loss over 30 years is negligible (maximum 2%) through the studied range of conditions. The relative loss of CO2 is much more pronounced compared to H2 gas, with losses of up to 72%. Therefore, the role of CO2 as a cushion gas will be affected by the CO2 gas losses as time passes. Hence, remedial CO2 gas injections should be considered to maintain the reservoir pressure throughout the injection and withdrawal processes. Moreover, the relative volume of CO2 increases with the increase in temperature and decrease in pressure. Furthermore, the reservoir rock properties, porosity, and permeability, are affected by the underground hydrogen storage process and, more specifically, by the presence of CO2 gas. CO2 dissolves carbonate minerals inside the reservoir rock, causing an increase in the rock's porosity and permeability. Consequently, the rock's gas storage capacity and flow properties are enhanced. [ABSTRACT FROM AUTHOR]

Geochemical modeling along with chemical reactions is one of the challenges in modeling of low salinity water injection. The most important issue in the geochemical model is to determine the correct electrical charge distribution model and its tuning parameters. The composition of the rock as well as the candidate water used is effective in determining the type of model and its parameters, so that the tuning parameters are determined based on the history of zeta potential experiments. In this study, in order to determine the correct model of electrical charge distribution and its tuning parameters in carbonate rock samples, first, equilibrium samples of Candidate water with crushed rock are subjected to static zeta potential tests. Then, the diffuse electrical double layer model is used to determine the electrical charge of the rock/water and water/oil surfaces and to predict the zeta potential. In the following, by adjusting the tuning parameters of the model to match the prediction results of the model with the history of the laboratory data, the density of the carbonate rock surface, the equilibrium constants and the kinetics of the governing reactions are determined. The obtained results show that the range of error in zeta potential prediction by the model compared to the laboratory data is from 2 to 20%, which is within the acceptable range of the performance of electrical charge distribution models. Moreover, it could be observed that the error of prediction using DLM model is significantly less than the conventional models (CD-MUSIC and BSM) for different candidate water. Finally, the effect of calculated zeta potential changes is used to calculate the contact angle changes of low salinity water injection based on the coupling of DLVO theory and geochemical model. The results of the study prove that the prediction error is less than 5% compared to the results of the static wettability tests. Based on this, according to the good match between the model and the laboratory results, it is possible to determine the properties of surface sites in surface complexation models of carbonate samples using the proposed approach and the subsequent tuning data of the geochemical model. [ABSTRACT FROM AUTHOR]

The chief source of the oilfield scale is the mixing of incompatible waters. This study demonstrated that mixing the reservoir of Mishrif formation (Halfaya oilfield) with six types of injection water sources, including Tigris River water, producing water formation, Gulf seawater, Marshes water, Middle Kirkuk formation water, and Main Outfall Drain water (AL-Masab AL-Aam Channel), leads to the formation of salt crusts that cause the reduction of reservoir rock permeability. According to the Piper diagram, the Mishrif formation water of all extant water samples was of the sodium chloride type (NaCl), except for HF-81, which was between (NaCl) and mix (CaMgCl) type. A geochemical simulation model of water alignment (PHREEQC) was used to simulate this problem, and it revealed the mineral scaling from mixing processes. These minerals precipitate in rock pores and clog them, which then cause damage to the petrophysical properties of the reservoir and prevent the passage of liquids. Results showed that the best water types used for injection are Middle Kirkuk formation water, followed by the general downstream, then Gulf seawater, but treatment before injection is needed. The study of geochemical modeling method can help to better understand scaling issues by efficiently identifying the best injection water from various selected types with the lowest possible cost, which in turn improves oil production. [ABSTRACT FROM AUTHOR]

Understanding the fracture patterns of hydrocarbon reservoirs is vital in the Zagros area of southwest of Iran as they are strongly affected by the collision of the Arabian and Iranian plates. It is essential to evaluate both primary and secondary (fracture) porosity and permeability to understand the fluid dynamics of the reservoirs. In this study, we adopted an integrated workflow to assess the influence of various fracture sets on the heterogeneous carbonate reservoir rocks of the Cenomanian–Santonian Bangestan group, including Ilam and upper Sarvak Formations. For this purpose, a combination of field data was used including seismic data, core data, open-hole well-logs, petrophysical interpretations, and reservoir dynamic data. FMI interpretation revealed that a substantial amount of secondary porosity exists in the Ilam and Sarvak Formations. The upper interval of Sarvak 1-2 (3491 m to 3510 m), Sarvak 1-3 (3530 m to 3550 m), and the base of Sarvak 2-1 are the most fractured intervals in the formation. The dominant stress regime in the study area is a combination of compressional and strike-slip system featuring reverse faults with a NW–SE orientation. From the depositional setting point of view, mid-ramp and inner-ramp show a higher concentration of fractures compared to open marine environment. Fracture permeability was modeled iteratively to establish a realistic match with production log data. The results indicate that secondary permeability has a significant influence on the productivity of wells in the study area. [ABSTRACT FROM AUTHOR]

Low-salinity surfactant nanofluids have recently shown promising results in the wettability alteration of reservoir rocks from oil-wet state towards more water-wet state. However, the investigation of pore-level interactions of nanofluids injection in real oil carbonate rocks at reservoir conditions, which determines the overall fluid dynamics, is lacking. Therefore, in this work, we studied the effect of nanoparticles augmented low-salinity surfactant flooding on the wettability alteration of hydrophobic carbonate rocks with harsh reservoir conditions via X-ray micro-tomography. The designed experiment scheme involved core flooding with an X-ray transparent core-holder developed for studying the flow properties of fluids at the micro level (pore scale). The wettability was quantified by measuring the differences in contact angles after the injection of low salinity, low-salinity surfactant, and low-salinity surfactant nanofluid. The findings illustrate that surfactant flooding with silica nanoparticles had a more pronounced influence on the contact angle among other injected fluids. The contact angle of the rock fell from 144° to 49°, corresponding to the water-wet conditions of carbonate rocks. The results show that the addition of a low concentration (0.005 wt.%) of SiO2 nanoparticles was enough for wettability changes in oil carbonate rocks. This study illustrates that a combination of surfactant, low-salinity, and nanoparticle features has a more pronounced effect on the three-phase contact angle than if applied separately. [ABSTRACT FROM AUTHOR]

Rock physics modelling in deeply buried tight carbonate reservoirs is more challenging than the clastic reservoir because of its complex pore systems. Therefore, modelling complex pore geometries in carbonates reservoir plays an important role in the geophysical measurements to infer pore‐type distribution and their volume fraction, which control the fluid flow properties governed by their complex geological history. This paper presents the use of a robust and practical integrated and iterative seismic petrophysics, and rock physics modelling workflow for the characterization of a deep tight mixed (carbonate and clastic) sedimentary reservoir of a recently discovered oil field located in the Potwar Basin onshore Pakistan. The case study incorporates a careful assessment of well‐log data quality, workflow used for well data conditioning and consequent improvement in data quality, seismic petrophysics and rock physics modelling results. Rock physics diagnostics identified data quality issues and rectified them using appropriate measures to ensure that the rock physics modelling scheme reliably predicts elastic logs honouring different pore types (reference, soft, stiff and cracks) distribution validating from the well observations. Two inclusion‐based rock physics models (Xu and Payne for carbonate and Keys and Xu for clastic) are used to predict rock elastic (P‐sonic, S‐sonic and density) properties responses. Utmost care is exercised to integrate all available data/information, such as Formation Micro‐Imager, mud‐log, testing data and calibrated pore‐type inversion results from well‐log data with the pore geometry revealed by Formation Micro‐Imager and core information. The rock physics modelling provided consistency between elastic and petrophysical properties by calibrating the estimated properties with the measure logs and improved understanding in terms of lithology and fluid separation in the tight carbonate interval. Finally, rock physics‐modelled elastic logs (P‐sonic, S‐sonic and density) are used along with seismic data (partial stacks) and horizons interpretation model to compute pre‐stack synthetic seismograms to calibrate with the preconditioned seismic data. A significant improvement in the well‐to‐seismic calibration is achieved from rock physics modelled logs compared with the original (measured) elastic logs at well location using pre‐stack seismic data, which, further, can help produce reliable reservoir rock properties of interest from the inversion of seismic data. [ABSTRACT FROM AUTHOR]

Matrix acidizing has been developed in the petroleum industry for improving petroleum well productivity and minimizing near-wellbore damage. Mud acid (HF: HCl) has gained attractiveness in improving the porosity and permeability of reservoir formation. However, there are several challenges facing the use of mud acid, comprising its corrosive nature, high pH value, formation of precipitates, high reaction rate and quick consumption. Therefore, different acids have been developed to solve these problems, including organic-HF or HCl acids. Some of these acid combinations proved their effectiveness in being alternatives to mud acid in reservoir rock acidizing. The current research deals with a new acid combination based on Hydrochloric–Oxalic acids for acidizing carbonate core samples recovered from Qamchuqa Formation in Kirkuk oilfield, northern Iraq. A new in-situ micro-model adopted laboratory technique is utilized to study the microscale alteration and evolution of pore spaces, dissolved grains and identification of matrix acidizing characteristics. The in-situ micro-model is based on the injection of an identical dose of different concentrations of the new acid combination into thin section samples under an optical light microscope. The adopted procedure aims to provide unique and rapid information regarding the potential for texture and porosity modification that can be caused by the acidizing stimulation procedure. In connection, solubility tests for the untreated and treated reservoir core samples and the density of the combined acids after treatment are conducted based on designed experiments using response surface methodology (RSM). The effect of acid concentration [12% HCl: Oxalic acid (3.8–8.8%)] and acidizing temperature (from ambient to 78.8 °C) on the solubility percentage of the samples and percentage increase in the combined acid density after acidizing were optimized and modeled. The obtained results confirm that the optimum dissolution of the core samples took place using 12% HCl:3.2% Oxalic acid with an optimum solubility (%) of the carbonate core rock of 53.78% at 21.7 °C, while the optimum increase in density (%) of the combined acids was 1.54% at 78.3 °C. The promising results could be employed for matrix acidizing of carbonate reservoir rocks for other oilfields. [ABSTRACT FROM AUTHOR]

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Carbonate rocks of the Triassic deposits of the South Mangyshlak basin are investigated in this paper for their boundary values, which are important for interpretation of field geophysical data as well as perforation and blasting. Based on their lithological composition, Triassic deposits are classified as either terrigenous or carbonate reservoirs. Carbonate reservoirs are found in the Middle Triassic strata containing volcanogenic dolomite and volcanogenic limestone rocks. A complex type of reservoir characterizes these rocks: porous-fractured, porouscavernous, and fractured. Upper Triassic sediments are formed by the intercalation of tuffaceous, siltstone-sandy, and mudstone rocks overlying Middle Triassic sedimentary rocks. Oil deposits are confined to polymictic sandstones, which are oil-saturated to varying degrees. In order to substantiate the quantitative criteria of the reservoir, experimental studies of the core samples were carried out in the laboratory. Fluid flow studies were performed where physical and hydrodynamic characteristics were determined when oil was displaced by displacing reagents. On the basis of the parameters obtained, correlations between reservoirs and non-reservoirs were constructed. Based on relationships between reservoir properties such as porosity and permeability versus residual water content, as well as effective porosity and permeability versus dynamic porosity, the boundary values were determined. Using these results, the porosity limit for the Middle and Upper Triassic strata has been determined to be 7%, the permeability limit for the Middle Triassic has been determined to be 0.02 X 10-3 µm², and the permeability limit for the Upper Triassic has been determined to be 0.3 X 10-3 µm² . [ABSTRACT FROM AUTHOR]

The drilling engineers favor a quantifiable understanding of the subsurface overpressure zones to avoid drilling hazards. The conventional pore pressure estimation techniques in carbonate reservoirs are prone to uncertainties that affect the calculated pore pressure model resolution and are still far from satisfactory. Basically, in carbonate reservoirs, the effect of chemical process and cementation on porosity is more important than the mechanical compaction, so the conventional pore pressure prediction methods based on the normal compaction trend mostly do not provide acceptable results. Using the conventional methods for carbonate reservoirs can yield large errors, even suggesting a reduction in abnormal pressure in overpressure zones where considerable attention must be paid. Conventional methods need to model density and velocity to calculate the effective and overburden pressures. Converting acoustic impedance to density and velocity is always associated with errors and generally provides low resolution, which adds substantial uncertainties to the pressure prediction. Although pore pressure measurements are usually associated with low resolution, additional error-prone steps can be dropped if used directly. This research outlines the pore pressure estimation of a famous Iranian carbonate reservoir using direct acoustic impedance without inverting it to density and velocity. Finally, this method gives acceptable results in carbonate formations compared to the results of the Repeat Formation Test (RFT) in this region. The results show a zone of overpressure between the two low-pressure intervals of the carbonate reservoir. This result can be of great help in determining reservoir boundaries as well as in planning for drilling trajectory for new wells. Furthermore, the pore pressure estimation results also show pressure reduction in the central part of the seismic section. The proposed approach is a viable alternative to the conventional method and is in line with the geological field report, where the ratio of hydrocarbon potential of total rock on the reservoir sides is higher than its middle part. In this study, we want to emphasize that the calibrated function obtained in our area can be used in similar basins with carbonate reservoirs. [ABSTRACT FROM AUTHOR]

• Pore-network model used to calculate residually trapped hydrogen. • Land's trapping coefficient of 25 distinct rock samples calculated. • Positive correlation between porosity, permeability, and Land's trapping coefficient. • Field-scale numerical simulations quantify trapped hydrogen using heterogeneous models. • Approximately 48–62 % of injected hydrogen is residually trapped in reservoir conditions. This study aims to evaluate the impact of microscopic pore structures and networks on capillary trapping in underground hydrogen storage (UHS). UHS in subsurface porous media has gained significant interest as a large-scale energy storage system to support the goal of net-zero emissions. However, selecting suitable geological sites for UHS requires a thorough understanding of the interactions among reservoir rock, in-situ fluid, and injected hydrogen. As UHS involves intermittent injection and production of the injected gas, the wettability and pore network of the reservoir rock plays a crucial role in determining the fraction of unrecoverable gas due to capillary trapping. Laboratory-based core flooding tests are required to quantify the fraction of unrecoverable gas due to capillary trapping, but as core flooding analyses are complex, costly, and time-consuming, only limited analysis has been done in the literature. Hence, this study presents a novel systematic workflow that evaluates the impact of microscopic pore structures and networks on capillary trapping using several rock samples with different pore properties, which is then extended to the reservoir-scale observation. The trapped fraction of the non-wetting phase is calculated from a pore-network model and then analyzed using Land's model. The Land constant showed a wide variation in the model constant, ranging from 0.2 to 2.7, depending on the pore properties of the rock sample. Compared to most of the sandstones, we observed that the Land's trapping coefficients for carbonate rock samples are higher, meaning less hydrogen will be trapped in carbonate reservoirs by capillary trapping. Moreover, we also investigated the correlation between the petrophysical properties like porosity and permeability of the rock and its impact on capillary trapping. Finally, field scale numeric reservoir simulation was conducted using an ensemble of heterogeneous models using the derived Land constants to quantify the fraction of injected gas trapped in various rock types. The results presented in this study provide a better understanding of hydrogen loss due to capillary trapping by connecting the pore-scale properties with reservoir-scale behavior, which is critical for safe and economical UHS site selection. [ABSTRACT FROM AUTHOR]

This study investigates the geophysical properties of the Abu Roash F Member (AR/F) as a potential unconventional oil reservoir in Heba Field, located in the eastern region of the Abu Gharadig Basin (Egypt). Analysis of seismic data reveals the influence of Late Cretaceous dextral wrenching tectonic activity, evidenced by the presence of ENE-WSW anticlinal folds and intersecting NW-SE as well as WNW-ESE extensional faults throughout the study area. This tectonic regime is believed to have played a significant role in the formation of micro-fractures within the AR/F carbonate, which can enhance the reservoir's potential by improving its permeability and porosity. Petrophysical assessment identifies favorable reservoir zones within specific depth intervals across multiple wells. These zones exhibit promising reservoir quality, characterized by low shale volume (below 0.20), which indicates a cleaner reservoir rock with less clay content. Additionally, the high total porosity (ranging from 0.20 to 0.25) and moderate effective porosity (ranging from 0.15 to 0.20) suggest that a substantial portion of the rock's pore space is available for storing hydrocarbons. The low water saturation (between 0.40 and 0.50) further supports the presence of hydrocarbons, as it indicates that the pores are not predominantly filled with water. Furthermore, the high hydrocarbon saturation (ranging from 0.50 to 0.60) confirms the significant presence of hydrocarbons within the reservoir. The quantitative assessment of these petrophysical properties across all analyzed wells further confirms the good reservoir quality and potential of the AR/F Member. The integration of seismic and petrophysical data provides a comprehensive understanding of the reservoir characteristics, highlighting the AR/F Member as a significant oil reservoir in the eastern border of the Abu Gharadig Basin, particularly in Heba Field. This study's findings complement the existing knowledge of oil-bearing formations in the region, suggesting that the AR/F Member could be a valuable addition to the basin's hydrocarbon resources. The results underscore the importance of further exploration and development of the AR/F Member to fully realize its potential as a major contributor to the area's oil production. • Petrophysical assessment of the Abu Roash "F" Member in Abu Gharadig Basin. • Unconventional oil reservoir in Heba Field. • Integration between seismic and well logs data in appraising oil reservoirs. • Qualitative and quantitative well logging evaluation. [ABSTRACT FROM AUTHOR]

• Present work study 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 part of the world. • The predicted temperature of the five 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 lithology in a geothermal reservoir. • Na-K geothermometer provides the highest accuracy for the basaltic and sandstone reservoir rocks. The best result for a granitic reservoir rock is obtained by Na-K-Ca geothermometer. • The study shows that the reservoir lithology must be considered to select a geothermometer. 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. [ABSTRACT FROM AUTHOR]

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. • Bioturbated strata in the Aruma Formation display extensive burrowing and fractures. • Fractures are influenced by burrow attributes, composition and diagenesis. • Two fractures categories are identified: burrow and non-burrow-related fractures. • The burrows, fractures, and the host rock matrix forms a triple-porosity system. [ABSTRACT FROM AUTHOR]

Heterogeneity analysis in carbonate reservoirs is of great importance for the interpretation of their characteristics. This study focuses on the evaluation of pore‐type heterogeneity by means of the sonic wave velocities in the carbonate–evaporite series of Permian–Triassic sequences in the Persian Gulf. Thin section petrography and laboratory measured the porosity and permeability of 1576 samples, as well as routine wire‐line logs, were employed. To manage heterogeneity, six electrofacies (EF) were determined based on an integrated analysis of compressional, shear and Stoneley waves as well as three routine logs (gamma, neutron and density). The frequency of pore types in each electrofacies was calculated. Then, the heterogeneity of pore‐type distribution in each electrofacies was measured by standard error and coefficient of variation. Sonic velocity has been compared with the geological properties of electrofacies. Results indicated that velocity is affected by factors other than the amount of porosity, facies or lithology. The standard error values in all electrofacies were close to zero. The coefficient of variation values ranges from 1.08 to 4.60. The lowest amount of coefficient of variation was observed in EF6 in the Khuff (K) 4 zone for moldic porosity. This value for intercrystalline porosity distribution in EF1 in the K1 zone was low, too. These results indicate the lowest standard deviation and the highest homogeneity in the distribution of intercrystalline and moldic porosities in K1 and K4. Also, comparing the mean values of sonic logs in each electrofacies with the total mean value in the whole sequence indicated that there is a relationship between sonic velocity logs and the type of porosity. High values of sonic velocity correspond to intercrystalline porosity in K1 and low values of velocity correspond to moldic porosity in K4. Results show that integrated pore‐type studies should be carried out to understand the sonic velocities in carbonate reservoir rocks. [ABSTRACT FROM AUTHOR]

The underdeveloped carbonate reservoirs in the Tahe Oilfield have fractures and vugs that are small scaled and production through a single well generally cannot realize its expected economy. Use multi-target well to penetrate multiple fractured reservoirs or reservoirs with vugs through one well, the production potential of a single well can be economically increased. The problem with the multi-target well drilling is mud losses in the complex fracture structures, which restrict the realization of fast and high efficiency drilling. By analyzing the characteristics of the mud losses taking place in fractured reservoirs and the difficulties encountered during drilling, an acid-soluble gel particle lost circulation material (LCM) was developed to solve the mud losses in reservoir drilling. Percent acid solubility of this LCM is 86%. After swelling, the volume of the LCM can be 3-5 times of its original volume, and the swollen LCM has good toughness and deformability. The acid soluble gel particle LCM, through orthogonal test, was mixed with an acid soluble flexible fiber and a flaky material to form a compound acid soluble LCM based on the mechanisms of mud loss control with gel particles. The compound LCM can be used at temperatures up to 150 ℃ and has percent acid solubility of 85%. It can used to stop mud losses through fractures of 0.1-3.0 mm in width and pores of 4-10 mesh. The pressure bearing capacity of the LCM layer is 9 MPa on the front side and 5 MPa on the opposite. Field application has shown that this compound acid soluble LCM can be used to solve mud losses into the complex fractures developed in carbonate rock reservoirs and should have broad application prospects. [ABSTRACT FROM AUTHOR]

Lower Cretaceous carbonates in the pre‐salt succession in the Santos Basin, eastern Brazil, are highly heterogeneous in terms of their reservoir characteristics as a result of depositional and diagenetic factors. Electrofacies have widely been used for reservoir zonation and, when allied with computer‐based methods such as neural networks, may help with the study of such complex reservoir rocks and with the identification of high‐quality reservoir zones. In this work, an unsupervised artificial neural network known as a self‐organizing map (SOM) was used to carry out a zonation of the pre‐salt carbonates in the Aptian Barra Velha Formation, the main reservoir unit in the Santos Basin. Available data included gramma‐ray, neutron porosity, resistivity deep, sonic, density, photoelectric factor, total porosity and effective porosity profiles from 21 wells together with mineralogical models. Core descriptions and thin section images were used as additional data for the lithological characterization of the electrofacies and consequently for reservoir zonation. A total of four electrofacies were defined from the SOM application, and five reservoir zones were identified. The characterization of the reservoir zones also considered the structural locations of the wells based on the relative depth to top‐ Barra Velha Formation; well locations were classified as structurally high, intermediate or low. Based on the reservoir zone characteristics, the results could be correlated with zonations in previous studies. A general tendency was noted for there to be an increase of finer‐grained sediments in the formation in wells located in structural lows; packstone and mudstone facies were prevalent in these wells and were in general characterized as poor‐quality reservoir rocks. By contrast, the shrubstones and grainstones which were more frequent in structurally high wells comprised higher quality reservoir rocks. The basal reservoir zone showed wide lithological variation compared to the overlying reservoir zones. Grainstone‐dominated facies were identified in the middle of the formation, and the uppermost reservoir zones were characterized by an upward increase in shrubstones and reworked grainstones which in general pointed to better quality reservoirs. [ABSTRACT FROM AUTHOR]

Acid fracturing has been performed with difficulties in the high temperature high pressure carbonate rock hydrocarbon reservoirs in the Shunbei block. The main problem is the dramatic reduction of the effect of acid fracturing resulted from the losses of the flow conductivity of the acid-etched fractures under the long-term action of the closure stresses. In laboratory experiment, the flow conductivity of acid-etched fractures is evaluated to study the changing patterns of the flow conductivity of the acid-etched fractures under different mass fractions of acid, temperatures and closure time. Based on the equations of the flow conductivity of acid-etched fractures under various conditions, a method for predicting the conductivity of long-term acid-etched fractures in Shunbei carbonate reservoir is established and verified. Use this method, the changing pattern of the flow conductivity of the acid-etched fractures at different lengths of time and flow rates is simulated. The simulation results show that at low closure stresses, the reaction rate of the acid is the dominant factor affecting the flow conductivity of the acid-etched fractures. At high closure stresses, however, the dominant factors affecting the flow conductivity of the acid-etched fractures include closure stress, rock characteristics and the nonuniformity of the rock surfaces. The closure stress, on the other hand, is the dominant factor controlling the deformation of the surfaces of the rocks and is also the decisive factor affecting the flow conductivity of the long-term acid-etched fractures. Under long-term action of closure stress, the flow conductivity of a fracture at the deep part of the fracture is decreased in an amplitude larger than the decrease in the flow conductivity of the fracture at its mouth. The distribution of the flow conductivity of artificial fractures produced under mid-term and long-term acid-etching is controlled by the rate of reaction between the acid and the rock. [ABSTRACT FROM AUTHOR]

The Upper Ediacaran microbial carbonates of the Tarim Basin are potential reservoir geobodies for future hydrocarbon exploration with rising interest in exploration for deeply‐buried reserves. However, little knowledge has been acquired on the types of microbial carbonates that are present, the properties of the reservoir and the pore evolution, hampering predictions of high‐quality reservoirs in these carbonates. Integrated with petrography and in‐situ U‐Pb dating geochronology analyses, this study aims to clarify the types of microbial carbonates present and to reconstruct the pore evolution processes of the potential reservoir rocks. The Upper Ediacaran microbial carbonates of the Tarim Basin can be divided into four types, based on their features in terms of different scales (macro‐ to micro‐): microbial laminite, stromatolite, spongiomicrobialite and microbial‐peloidal wackestone/mudstone. Petrophysical properties show that all these microbial carbonates have low porosity and very low permeability with poor connectivity. These carbonates were subject to long‐term and complex diagenetic processes, mainly consisting of dissolution, compaction, pervasive dolomitization, cementation and fracturing. The most important reservoir spaces are contributed by vugs and dissolution‐enlarged pores, which are likely to have been associated with the widespread uplift of the Aksu area in the terminal Ediacaran. In contrast, the cementation of the fine‐to‐medium crystalline dolomite greatly reduced the pre‐existing pores. Pore types are closely related to different microbial fabrics, which played an important role in the pore evolution of the microbial carbonates. [ABSTRACT FROM AUTHOR]