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This study investigates the natural gas hydrates within the Qiongdongnan Basin by integrating well-log and seismic data. Through pre-stack inversion and rock physics analysis, key parameters such as P-wave and S-wave impedances were utilized to distinguish hydrate-bearing formations from other geological bodies. A low-frequency model was constructed using the Inverse Distance Weighting (IDW) algorithm to improve the precision of parameter inversion. This study employs a multi-constraint inversion strategy, incorporating hard constraints from multiple wells and soft constraints from geological frameworks, ensuring reliable inversion results. Findings indicate that hydrate reservoirs are characterized by increased wave velocity and density due to hydrate accumulation, providing insights into the spatial distribution and characteristics of hydrates. This research enhances the understanding of hydrate reservoirs and offers valuable data for exploration in the Qiongdongnan Basin. [ABSTRACT FROM AUTHOR]

As a hydrocarbon reservoir rock, shale is generally composed of highly compacted clay particles with submicrometer sizes and includes nanometric porosity and different hard particles, like quartz, pyrite, etc. One of the key reasons for the formation of a complex fracture network via hydraulic fracturing is the multiscale heterogeneity of shale, especially heterogeneity on the microscale. This paper conducted on an experimental investigation of shale and explored the intrinsic relationship between the microstructure, the related mechanical properties at the micrometer level and the anisotropic failure mechanism. Small-scale specimens with micrometer dimensions in the form of cantilever beams with rectangular cross-section were fabricated by means of a focused ion beam (FIB) and tested via bending with a nanoindenter. The load–deflection curves of these bending beams were monitored up to failure, and the tensile strength of the shale composite was directly derived from the load–deflection curves at 474.5 MPa (parallel to the bedding plane) and 168.9 MPa (vertical to the bedding plane). The results show that the strength anisotropy of shale at the micrometer scale is driven by the clay particles and other minerals, and the bonds of these particles. The modulus anisotropy of the shale composite at the microscale is dominated by the orientation of clay particles. Moreover, the shale composite embedded with pyrite exhibited strong softening characteristics. [ABSTRACT FROM AUTHOR]

This study presents geochemical, petrophysical and seismic interpretation and modeling data of source and reservoir rocks of Eocene and Paleocene sequences of Balkassar oilfield, Potwar Basin, Pakistan. Integrated approaches were applied to evaluate structure and various rocks i.e., Patala, Lockhart and Chorgali formations. Grid of eleven seismic lines, well logs, well tops and ten fresh rock cutting samples were used. TOC content of Patala Formation ranges between 0.25 − 1.16 wt. %, with S2 values 0.11–0.63 mg HC/g rock, thus indicating poor to fair hydrocarbon potentialwhich issupported by no distinct presence of hydrocarbon peaks in pyrolysis-GC pyrograms. Petrographic analysis showed dominant presence of vitrinitic Type III and inertinitic Type IV kerogen phytoclasts with minor amount of AOM. High abundance of reworked vitrinite and inertinite phytoclasts appear to have influenced the vitrinite reflectance data. Basin modeling predicts Lockhart Formation began oil generation at 10.30Ma age at depth 1557 m and reached peak generation at 8.43Ma age at depth 1802 m. Patala formation began oil generation at 10.56Ma age at depth 1472 m and reached its peak generation at 8.43Ma age at depth of 1768 m. 3D horizon mapping depicts that Chorgali formation is uniformly distributed and faulted from northwest corner. [ABSTRACT FROM AUTHOR]

This study integrated palynological, geochemical, and petrophysical analysis that maybe used to analyze petroleum rocks. Shales and sediments rich in carbonate are essential in assessing the geological history of source rocks for the generation of petroleum. This emphasizes the important role of carbonate source rocks on a global level. This study evaluated the source and reservoir rocks of Meyal oilfield, Potwar Basin. Twenty-five well cutting samples from two wells and four fresh outcrop samples were studied. Results of TOC and Rock-Eval of Sakesar Formation samples showed fair to good TOC, Patala Formation in well had very good TOC contents in well both wells. S2 values of both formations' samples showed fair to good generative potential. Both formations lie in the maturity window having primarily mixed Type II/III and Type III kerogen with good oil/gas-generation potential. Palynological analysis also shows Type III kerogen in productive oil/gas window and in good agreement with pyrolysis data. Three forms of kerogen assemblages were identified: Structured and Bio-structured phytoclasts, opaque phytoclasts, and AOM. Petrophysical analysis of Chorgali formation showed average porosity ∼12.01%, average water saturation ∼37.71%, and average hydrocarbon saturation ∼62.28%, indicating average to good reservoir potential. Findings of this research will help and guide exploration and production companies. [ABSTRACT FROM AUTHOR]

During injection treatments, bottomhole pressure measurements may significantly mismatch modeling results. We devise a computationally effective technique for interpretation of fluid injection in a wellbore interval with multiple geological layers based on the bottomhole pressure measurements. The permeability, porosity and compressibility in each layer are initially setup, while the skin factor and partitioning of injected fluids among the zones during the injection are found as a solution of the problem. The problem takes into account Darcy flow and chemical interactions between the injected acids, diverter fluids and reservoir rock typical in modern matrix acidizing treatments. Using the synchronously recorded injection rate and bottomhole pressure, we evaluate skin factor changes in each layer and actual fluid placement into the reservoir during different pumping jobs: matrix acidizing, water control, sand control, scale squeezes and water flooding. The model is validated by comparison with a simulator used in industry. It gives opportunity to estimate efficiency of a matrix treatment job, role of every injection stage, and control fluid delivery to each layer in real time. The presented interpretation technique significantly improves accuracy of matrix treatments analysis by coupling the hydrodynamic model with records of pressure and injection rate during the treatment. [ABSTRACT FROM AUTHOR]

Lacustrine shale oil resources are essential for the maintenance of energy supply. Fluid types and contents play important roles in estimating resource potential and oil recovery from organic-rich shales. Precise identification of fluid types hosted in shale oil reservoir successions that are characterized by marked lithological heterogeneity from only a single well is a significant challenge. Although previous research has proposed a large number of methods for determining both porosity and fluid saturation, many can only be applied in limited situations, and several have limited accuracy. In this study, an advanced logging technique, combinable magnetic resonance logging (CMR-NG), is used to evaluate fluid types. Two-dimensional nuclear magnetic resonance (2D-NMR) experiments on reservoir rocks subject to different conditions (as received, after being dried at 105 ℃, and kerosene imbibed) were carried out to define the fluid types and classification criteria. Then, with the corresponding Rock–Eval pyrolysis parameters and various mineral contents from X-ray diffraction, the contribution of organic matter and mineral compositions was investigated. Subsequently, the content of different fluid types is calculated by CMR-NG (combinable magnetic resonance logging, viz. 2D NMR logging). According to the fluid classification criteria under experimental conditions and the production data, the most favorable model and optimal solution for logging evaluation was selected. Finally, fluid saturations of the Cretaceous Qingshankou Formation in the Gulong Sag were calculated for a single well. Results show that six fluid types (kerogen-bitumen-group OH, irreducible oil, movable oil, clay-bound water, irreducible water, and movable water) can be recognized through the applied 2D NMR test. The kerogen-bitumen-group OH was mostly affected by pyrolysis hydrocarbon (S2) and irreducible oil by soluble hydrocarbon (S1). However, kerogen-bitumen-group OH and clay-bound water cannot be detected by CMR-NG due to the effects of underground environmental conditions on the instruments. Strata Q8–Q9 of the Qing 2 member of the cretaceous Qingshankou Formation are the most favorable layers of shale oil. This research provides insights into the factors controlling fluid types and contents; it provides guidance in the exploration and development of unconventional resources, for example, for geothermal and carbon capture, utilization, and storage reservoirs. [ABSTRACT FROM AUTHOR]

Huff‐n‐puff (HnF) is a crucial technology for effectively enhancing the oil recovery (EOR) of tight oil reservoirs. Soaking period is the primary platform for injection medium interacting with formation fluid and reservoir rock in HnF. Elucidating the micro‐percolation mechanism of the soaking period is immensely significant for guiding oilfield production practices. The present study established a physical simulation method combining HnF experiments with nuclear magnetic resonance to reveal the microscopic percolation mechanisms, including water, fracturing fluid, and surfactant. Furthermore, the impacts of soaking time, HnF cycles, wettability, and pore structure on oil recovery degree were quantified. The results demonstrate the crucial significance of wettability and pore structure in the soaking period. The dominant mechanism during water HnF in reservoirs characterized by well‐connected pore networks and minimal clay pores is micropore imbibition, while conversely, macropore displacement plays a predominant role. The oil recovery degree of fracturing fluid HnF primarily relies on mitigating solid‐fluid forces within macropores. The surfactant HnF in preferential water‐ and oil‐wet reservoirs is primarily governed by oil films stripped from macropore walls and micropore imbibition, respectively. Specifically, water and fracturing fluid HnF are suitable for shorter soaking time and fewer HnF cycles, whereas the surfactant HnF exhibits an inverse relationship. [ABSTRACT FROM AUTHOR]

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]

Understanding polymer retention is a critical aspect in the field of chemical-enhanced oil recovery (cEOR). This article presents a comprehensive review of polymer retention in reservoir rocks, focusing on the underlying mechanisms, measurement techniques, and the factors influencing this phenomenon. Three main (proposed) mechanisms that contribute to polymer retention are discussed in detail. Polymer adsorption, hydrodynamic retention, and mechanical entrapment are identified as key factors affecting the overall retention of polymers during flow through porous media. Also, herein, we explore the details of these mechanisms, explaining how polymer characteristics and rock surface properties influence the degree of retention. Furthermore, we analyze the influencing factors that affect polymer retention. The rock surface properties, such as surface charge and wettability, play a vital role in determining the interaction between polymers and rocks. The interplay of these factors provides valuable insights into understanding and controlling polymer retention in cEOR applications. This review paper put in a nutshell a comprehensive understanding of the mechanisms, measurement techniques, and influencing factors involved. [ABSTRACT FROM AUTHOR]

In 1989, the first prolific hydrocarbon reservoirs were discovered by Saudi Aramco in the highly porous and permeable friable continental sandstones (Unayzah reservoirs) and shallow marine carbonates (Khuff reservoirs) of the Paleozoic successions in the south of Riyadh, central Arabia. Since 1989, Saudi Aramco has discovered new oil and gas fields in various stratigraphically and genetically different units of the Permo-Carboniferous and Permian successions. These successions were strongly affected by tectonic movements (Caledonian and Hercynian orogenesis) and Early and Late Paleozoic Gondwana glaciations. Therefore, the thickness of some sections was fully eroded or significantly reduced. The sequence stratigraphic interpretation of the Paleozoic successions allowed us to understand the depositional environments and regional distribution of the source, reservoir, and cap rock facies in improved palynologic studies. Hydrocarbons were discovered with the Late Permian continental sandstones of the Unayzah Formation, the glaciogenic sandstones of the Late Ordovician Sarah Formation in Saudi Arabia, Late Silurian Hazro reservoir in southeast Türkiye, and the cold desert eolian sandstones of the Permo-Carboniferous Haradh Formation. Potential source rock facies of the Qusaiba Shale Member in Saudi Arabia and the hot shale facies of the Dadaş Formation in southeast Türkiye were deposited at the base of the Early Silurian regional transgression (444 Ma) during the melting phase of the huge Gondwana ice mass. The hydrocarbons migrated downward into the glaciogenic reservoir sandstones due to the hydrostatic pressure provided a useful depositional environment model. The hydrocarbon discoveries have provided core and well log data for regional correlations. Every aspect of the sequence stratigraphy was investigated and various types of unconformities, sequence boundaries, glaciation periods, and maximum flooding surfaces were recognized and correlated between Middle East countries. The relationship between the sea-level fluctuations and sediment supply into the basin was established by the regressive (progradational) and transgressive parasequences and parasequence sets. This genetic sequence stratigraphic approach has significantly increased the hydrocarbon explorations and production in the entire Arabian Platform. [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]

An analysis of the propagation behavior of Rayleigh wave has been conducted in an anisotropic layer, such as reservoir rocks overlying a sandy medium. The layer and lower half-space interface have been considered imperfect, whereas a corrugated upper boundary has been assumed. A closed relation of phase velocity and wave number has been obtained as a determinant form. For the numerical interpretation of results, reservoir rocks of triclinic type have been modeled. Some special cases are taken into account. The study examines the simultaneous simulated results of several physical parameters and illustrates the effects of thickness, sandiness parameter, phase velocity, corrugation amplitude, corrugation wavelength, and imperfect Rayleigh wave interface distribution in the structure under consideration, which was created using Mathematica 7. For variations in wave number and phase velocity, diagrams are drawn. [ABSTRACT FROM AUTHOR]

Considering the problems in the discrimination of fracture penetration and the evaluation of fracturing performance in the stimulation of thin sand-mud interbedded reservoirs in the eighth member of Shihezi Formation of Permian (He-8 Member) in the Sulige gas field, a geomechanical model of thin sand-mud interbedded reservoirs considering interlayer heterogeneity was established. The experiment of hydraulic fracture penetration was performed to reveal the mechanism of initiation-extension-interaction-penetration of hydraulic fractures in the thin sand-mud interbedded reservoirs. The unconventional fracture model was used to clarify the vertical initiation and extension characteristics of fractures in thin interbedded reservoirs through numerical simulation. The fracture penetration discrimination criterion and the fracturing performance evaluation method were developed. The results show that the interlayer stress difference is the main geological factor that directly affects the fracture morphology during hydraulic fracturing. When the interlayer stress difference coefficient is less than 0.4 in the Sulige gas field, the fractures can penetrate the barrier and extend in the target sandstone layer. When the interlayer stress difference coefficient is not less than 0.4 and less than 0.45, the factures can penetrate the barrier but cannot extend in the target sandstone layers. When the interlayer stress difference coefficient is greater than 0.45, the fractures only extend in the perforated reservoir, but not penetrate the layers. Increasing the viscosity and pump rates of the fracturing fluid can compensate for the energy loss and break through the barrier limit. The injection of high viscosity (50-100 mPa·s) fracturing fluid at high pump rates (12-18 m3/min) is conducive to fracture penetration in the thin sand-mud interbedded reservoirs in the Sulige gas field. [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]

The oil reservoirs of the metamorphic rocks in Bohai Bay have geological characteristics such as low matrix porosity and permeability, developed natural microfractures, which result in the injection water rapidly advancing along fractures, a fast increase in the water content, and difficulties in extracting the remaining oil. In order to reveal water channeling and the residual oil formation mechanisms in fractured low-permeability reservoirs and solve the water channeling problem, we first analyzed the reservoir development status, then studied the formation mechanism of residual oil using a microfluidic chip device, and formed a method of hierarchical control to effectively control the water channeling problem of fractured reservoirs and maximize the displacement of residual oil. The results show that (1) Due to the low permeability of the reservoir matrix, a large amount of injected water flows along the fracture channel, which leads to the long-term high water cut of some oil wells and the retention of a large amount of crude oil in the matrix. (2) The results of microfluidic experiments show that the distribution of residual oil after water flooding mainly includes five types: blind end of the pore throat, columnar, cluster, flake and film, and residual oil. Among them, sheet-like and clustered residual oil are dominant, accounting for 75~85% and 10~13%, respectively. (3) Based on the characteristics of fracture development in buried-hill reservoirs, a hierarchical control technology of "gel particle + liquid crosslinked gel system" is established. The field application effect predicted that the input–output ratio was 1:3. This study provides a reference for the comprehensive treatment of water channeling in the same type of offshore fractured low-permeability metamorphic rock reservoirs. [ABSTRACT FROM AUTHOR]

To study the oil and gas enrichment characteristics of the reservoir rocks in the second Member of the Nantun Formation (N2) of the F1 fault in the Beier Depression, this research focuses on the mechanism of shortening the sealing time of the regional mudstone cap due to faults and the factors influencing the sealing duration. The period during which the regional mudstone cap seal began is determined by analyzing the relationship between the diagenetic index of the regional mudstone cap and its underlying reservoir rocks and time. This relationship between the rock-formation index and time helps establish the onset of regional mudstone cap seal, and from this, the index of shortening time due to faults is derived. A research framework to study the sealing time shortening of regional mudstone cap seal caused by a fault was developed, which was further applied to analyze the relationship between the fault-induced shortening time of the seal in the lower of the first Member of the Damoguaihe Formation section ( D 1 x ) of the Beier Depression and hydrocarbon concentrations in the N2 Formation. The results show that the F1 fault at measurement points 1–4, 6, and 9–11 reduced the blocking time of the regional mudstone cap in  D 1 x  to 100%, hindering hydrocarbon accumulation and preservation in the N2. Conversely, the F1 fault at measurement points 5, 7, 8, and 12–15 reduces the blocking time of the regional mudstone cap in the  D 1 x  by 37–99%, which is more conducive to hydrocarbon accumulation and preservation in N2, resulting in positive oil and gas shows. Based on the test results, a discussion on the feasibility, applicability, and limitations of the new method is conducted, yielding the following conclusions: (1) The relationship between oil and gas indications in the reservoir rocks of the Nan'er Member confirms the feasibility of the new method. The research findings of the new method on the F1 fault align with current oil and gas exploration realities, indicating its potential use in studying the degree to which faults shorten the sealing time of regional mudstone caprocks. (2) The new method is primarily applicable to the study of the modification effects of tensile normal faults on regional mudstone caprocks and their impact on oil and gas sealing capacities. However, its application to other types of faults may have limitations. (3) The new method is mainly suitable for caprocks dominated by mudstone. When studying other types of caprocks, such as carbonate rocks, evaporites, igneous rocks, and metamorphic rocks, different research methods and technical means are required. These findings provide valuable insights for oil and gas exploration efforts near fault zones. [ABSTRACT FROM AUTHOR]

The relevance of the technical and economic evaluation of the application of enhanced oil recovery methods at oil fields at the final stage of development is related to the need to recover the remaining reserves, including hard-to-recover (HTR) reserves, the share of which is growing annually. Currently, there are many effective enhanced oil recovery (EOR) methods for different process conditions, but their application has different effects based on the combination of methods, techniques and production conditions. The aim of this study was to approach the scaling of the effect of the application of modern EOR using the methodology of the clustering of wells with similar technological characteristics. This paper proposes a methodology for the selection of candidate wells to form clusters based on a set of indicators that determine the choice of enhanced oil recovery technology in oil fields at the final stage. The technological efficiency of sidetracking and multistage hydraulic fracturing application was evaluated based on the analytical method of well flow rate estimation. By applying cluster analysis to selected wells, three clusters were formed, each including three wells, united by the geological properties of their reservoir rocks and the filtration–capacitive properties of the oil. After this, the optimal technologies were selected for two clusters—hydraulic fracturing and sidetracking. The accumulated oil production, recovered due to the application of the technologies, from six wells for the first 7 years after the operation was estimated at 306.92 thousand tons of oil. Due to the achieved technological effect, the economic efficiency of the development of the studied oil field will increase due to the proceeds from the sales of the extracted additional oil. The results of this study can be used in the calculation of technical and economic efficiency at oil fields with similar conditions. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Engineering (17264073) 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.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience 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.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience 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.)

Over the past three decades, advancements in computational power and numerical methods have significantly enhanced the role of structural analyses in the design and safety assessment of dams. Simulating concrete dam behavior, particularly in interactions with reservoir water and rock foundations, poses formidable computational challenges. Additionally, the need to define uncertainties related to material parameters, loading conditions, and modeling strategy adds complexity to the modeling process, therefore, quantifying sources of uncertainty is crucial for maintaining credibility and confidence in analysis results. This paper provides a synthesis and an overview of existing research and presents a generic framework for evaluating the credibility of advanced structural analysis methods for concrete dams, with a focus on their limitations and associated uncertainties. The methodology includes a comprehensive process for structural analysis, verification, validation, and uncertainty quantification, aiming to facilitate condition assessments of concrete dams. [ABSTRACT FROM AUTHOR]

Wide azimuth seismic data play an important role in deep reservoir prediction. According to the Paleogene clastic rock reservoir prediction, the high‐density and wide azimuth 3D seismic data acquisition of ocean bottom nodes was first carried out in a Chinese offshore oilfield in 2019. After high precision amplitude‐preserving processing, we obtained the high‐quality wide azimuth gathers. However, the research on anisotropy and reservoir prediction using wide azimuth seismic data mainly focuses on carbonate and bedrock intervals, which is not suitable for clastic rock reservoir prediction. Therefore, this paper innovatively proposes a clastic rock reservoir prediction method, which studies prestack reservoir prediction in the ray parameter domain based on wide azimuth ocean bottom node seismic data. Based on the azimuth gathers, we can obtain elastic parameters through prestack amplitude versus offset inversion, which is used to characterize the reservoir, so it is significant to obtain high precision elastic parameters in order to get highly reliable reservoir prediction results. In this paper, we develop an amplitude versus offset inversion method based on the Bayesian theory in ray parameter domain, the output of which is density, P‐wave impedance and Vp/Vs. These elastic parameters have high precision, and density data are valuable input for reservoir characterization because they are sensitive to the lithology of clastic rock reservoir at different orientations. In ray parameter domain inversion, the ray path of seismic wave propagation is considered polyline, which is more consistent with the actual situation; thus, extracted amplitudes of P gathers used in inversion are more accurate. In addition, the reflection coefficient formula in ray parameter domain has higher precision when the incident angle is large. The inversion based on the Bayesian theory can improve the stability of the inversion. Test on the actual data shows that the result of ray parameter domain inversion with a Bayesian scheme is more accurate, stable and reliable. Based on the above high precision density inversion results, an innovative wide azimuth data reservoir prediction technology based on elliptical short‐axis fitting was proposed. The actual prediction of the deep reservoir in the Bohai oilfield shows that sand thickness fitting prediction results in the short axis can best match the actual drilling sandstone thickness. The coincidence rate is 86% and the short‐axis fitting results are more in agreement with geological laws. Theoretical research and practical applications have shown that this method is feasible and effective, with high prediction accuracy, computational efficiency and strong application value. [ABSTRACT FROM AUTHOR]

Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office 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.)

Externally applied stress on the rock matrix plays a crucial role in oil recovery from naturally fractured tight reservoirs, as local variations in pore pressure and in-situ tension are expected. The published literature severely lacks in evaluations of the characteristics of hydrocarbons, displaced by water, in fractured reservoirs under the action of externally applied stress. This study intends to overcome this knowledge gap by resolving complex time- and stress-dependent multiphase flow by employing a coupled Finite Element Method (FEM) and Computational Fluid Dynamics (CFD) solver. Extensive three-dimensional numerical investigations have been carried out to estimate the effects of externally applied stress on the multiphase flow characteristics at the fracture–matrix interface by adding a viscous loss term to the momentum conservation equations. The well-validated numerical predictions show that as the stress loading increases, the porosity and permeability of the rock matrix and capillary pressure at the fracture–matrix interface decrease. Specifically, matrix porosity decreases by 0.13% and permeability reduces by 1.3% as stress increases 1.5-fold. Additionally, stress loading causes a decrease in fracture permeability by up to 29%. The fracture–matrix interface becomes more water-soaked as the stress loading on the rock matrix increases, and thus, the relative permeability curves shift to the right. [ABSTRACT FROM AUTHOR]

The buried hills of the Archean metamorphic rocks in the Bozhong Depression of the Bohai Bay Basin are the main gas-bearing strata, with burial depths ranging from 4000 m to 5500 m. However, metamorphic rocks have internal structural characteristics, such as diverse mineral components, oriented arrangement of mineral particles, complex pore connectivity, variable crystal structures, orthogonal development of multiple sets of fractures, and uneven fluid filling. Compared with conventional reservoirs, they have obvious heterogeneity and anisotropy characteristics. Traditional rock physics modeling methods are no longer suitable for predicting the elastic and anisotropic parameters of metamorphic reservoirs. Therefore, we introduced a vector mixed random medium model to calculate the effect of the oriented arrangement of metamorphic rock minerals on the modulus of the rock matrix and introduced a metamorphic factor to describe the impact of metamorphic recrystallization and alteration metasomatism on the elastic modulus of the rock matrix. Practical applications have shown that the new, improved rock physics modeling method can better estimate the S-wave velocity and anisotropy parameters in wells compared to traditional rock physics modeling methods, providing a reliable basis for predicting fractured reservoirs in metamorphic rock at buried hills. [ABSTRACT FROM AUTHOR]

Highlights: The spatial distribution pattern, DSGSD characteristics and influence of the controlling factors of reservoir rock landslides were analyzed in Southwest China. The contribution of DSGSD to sliding deformation of a rock slope with landslide potential in the reservoir area was obtained. The mode of DSGSD evolution into landslides was summarized considering different combinations of bedding dip and slope angles. [ABSTRACT FROM AUTHOR]

Reservoir impoundment and water level fluctuations often trigger landslides and their secondary disasters, such as potential impulse waves, posing a serious threat to the safety of people along the reservoir and dam areas, causing economic losses and even catastrophic consequences. This study delves into a comprehensive field investigation and monitoring of the engineering geological conditions and deformation mechanisms of the Mogu rock landslide. The impoundment is identified as the primary factor inducing slope deformation, with the cumulative displacement of the sliding body showing no signs of convergence, indicating potential instability. By coupling the elasto-visco-plasticity model and the RNG turbulence model in FLOW-3D, an actual impulse wave disaster near the Lianghekou reservoir dam area is replicated to validate the reliability of the numerical method. Building upon this, a three-dimensional model is established to calculate potential impulse waves generated by the Mogu rock landslide, and the risk to the dam is evaluated. Under different water level conditions, the simulated run-ups of impulse waves do not surpass the dam elevation, demonstrating a satisfactory safety margin. Given the inherent danger of landslide-induced wave disasters, continuous attention is warranted, and preventive measures and suggestions are proposed to address these concerns. Additionally, the study explores the contributions of water level fluctuations to the primary tsunami amplitude, the maximum run-up on the opposite bank and the dam, and the attenuation rate of the tsunami amplitude along the river channel. The results provide significant reference values for the early warning and prevention of comparable reservoir landslides and potential landslide-induced waves worldwide. [ABSTRACT FROM AUTHOR]

Tianjin possesses abundant geothermal resources, and geothermal reinjection is an effective strategy for maintaining the sustainable development and utilization of these resources. However, several issues have arisen in the reinjection of sandstone geothermal reservoirs in the Tianjin area, including a mismatch between the reinjection capacity and effluent capacity, as well as challenges related to continuous reinjection. Therefore, it is crucial to investigate the reinjection of exogenous water into sandstone pore-type geothermal reservoirs. This study focuses on the geothermal reservoir of the Guantao Formation in the Binhai New Area. The surface water treatment process for reinjection into sandstone geothermal reservoirs was determined through water treatment simulation experiments. Additionally, experiments examining the interaction between the reinjected water and reservoir rock were conducted to assess the feasibility of using treated surface water for reinjection into sandstone geothermal reservoirs. The hydrogeochemical response mechanisms and the impact on the reservoir under reinjection conditions were also investigated. The results indicate that a nanofiltration module and tubular microfiltration membrane are essential to ensure the stability of the system. The pH and TDS of water samples decreased after reinjecting mixed water (HHS) into the sandstone reservoir. The hydrochemical type consistently remained Cl-Na. The conventional water chemistry components and trace elements were influenced by the corresponding water–rock reactions. The reservoir minerals exhibited minimal precipitation, primarily consisting of K-feldspar and Fe-dolomite. The minerals produced during the experiment accounted for only 0.08% of the total cuttings' mass, indicating a negligible impact on the reservoir structure. PHREEQC was employed to simulate the changes in mineral saturation index before and after the reinjection of mixed water and geothermal water, respectively. Notably, similar hydrogeochemical changes were observed in the geothermal fluids. Thus, this study demonstrates the feasibility of reinjecting treated surface water into sandstone geothermal reservoirs from a hydrogeochemical perspective. This research provides valuable insights for the development of external water reinjection projects in hot spring health care units, contributing effectively to the achievement of carbon peaking and carbon neutrality goals. [ABSTRACT FROM AUTHOR]

The Lower Ordovician Tongzi Formation containing abundant shoal sediments is the most promising stratum for the petroleum exploration in the Sichuan Basin. However, the current studies mainly focus on the central part of the Basin, the systematic analysis of the southeastern part with well-developed shoal facies is lacking. This paper aims to clarify the characteristics and genesis of the Tongzi Formation reservoir in Southeastern Sichuan Basin, following an analysis of sedimentary facies within the sequence stratigraphic framework. The research shows that the main types of reservoir rocks are oolitic, intraclastic and bioclastic dolostones. And the reservoir spaces consist mainly of intergranular (dissolved) pores, inter-crystalline (dissolved) pores, intragranular dissolved pores and fractures. Among them, intergranular pores account for the highest proportion, which is followed by intragranular dissolved pores. In addition, most throats are necking and flaky which mainly connect intergranular and inter-crystalline pores, respectively. The diagenetic sequence shows that penecontemporaneous karst well improved the porosity of the reservoir in the early-stage although the cementation and compaction reduced parts of pores. The reservoir formation is associated with the tectonic-depositional settings, diageneses and terrigenous contamination. Paleohighlands and submerged uplifts, forming in the early Ordovician amalgamation between Yangtze and Cathaysia blocks, accumulated shoal sediments as the material basis for the reservoir formation. Penecontemporaneous karst forming intragranular dissolved pores and the dolomitization aiding grainstones to resist the pressure solution are the key to increasing porosity and preserving pores. The absence of terrigenous contamination prevented intergranular pores from being strongly cemented, which resulted in the reservoir difference between the central and southeastern Sichuan Basin. The study can be used as a reference for the further exploration of Ordovician petroleum in the Sichuan Basin and other regions owning similar geological settings. [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.)

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.)

The exploration and development of conventional oil and gas resources are becoming more difficult, and the proportion of low-permeability reservoirs in newly discovered reservoir resources has expanded to 45%. As the main focus of the oil industry, the global average recovery rate of low-permeability reservoir resources is only 20%, and most crude oil is still unavailable, so our understanding of such reservoirs needs to be deepened. The microscopic pore structure of low-permeability reservoir rocks exhibits significant complexity and variability; reservoir evaluation is more difficult. For elucidating the internal distribution of storage space and the mechanisms influencing seepage, we focus on the low-permeability sandstone reservoir of the Shahejie Formation, located on the northern slope of the Chenjiazhuang uplift, Bohai Bay. Employing a suite of advanced analytical techniques, including helium expansion, pressure pulse, high-pressure mercury intrusion (HPMI), and micro-computed tomography (micro-CT) scanning, we examined the main pore–throat size affecting reservoir storage and seepage in the reservoir at both the micrometer and nanometer scales. The results reveal that pores with diameters exceeding 40 μm are sparsely developed within the low-permeability reservoir rocks of the study area. However, pores ranging from 0 to 20 μm predominate, exhibiting an uneven distribution and a clustered structure in the three-dimensional pore structure model. The pore volume showed a unimodal and bimodal distribution, thus significantly contributing to the storage space. The main sizes of the reservoir in this study area are 40–80 μm and 200–400 μm. Micron-sized pores, while present, are not the primary determinants of the reservoir's seepage capacity. Instead, coarser submicron and nano-pores exert a more substantial influence on the permeability of the rock. Additionally, the presence of micro-fractures is found to enhance the reservoir's seepage capacity markedly. The critical pore–throat size range impacting the permeability of the reservoir in the study area is identified to be between 0.025 and 0.4 μm. [ABSTRACT FROM AUTHOR]

Proper characterization of the unsaturated hydraulic properties in rocks is significant for predicting fluid flow in soil, hydrogeologic, and petroleum science and engineering problems. In this study, we contributed rigorous analysis of the unsaturated hydraulic properties of three reservoir rock samples (Berea Sandstone, Guelph Dolomite, and Indiana Limestone). An improved version of the standard evaporation method (HYPROP) was developed to cater specifically to rock samples. The improved HYPROP setup enables measurements of local water pressures within rock samples without disturbing the upper portion of the samples. The obtained results were compared with those obtained using the conventional pressure plate method and a state-of-the-art nuclear magnetic resonance (NMR) method. Observed data were analyzed in terms of four different unimodal and bimodal hydraulic functions. The HYPROP data were found to be relatively close to the pressure plate data of two carbonate rocks. The NMR-based data were reasonably consistent with the HYPROP data, with differences likely due in part to the fact that they were obtained using two different 5-cm long plugs taken from the same core. Heterogeneity along the rock cores from which the samples were taken could be a major reason for the observed differences, and hence should be considered in reservoir analyses. [ABSTRACT FROM AUTHOR]

Reservoir water sensitivity damage means that the contact between the external fluid and reservoir rock lead to the hydration, expansion, dispersion, and migration of clay minerals, thereby reducing the formation permeability and causing damage to the reservoir. In this study, the transformation of smectite to illite (S-I) is promoted by endogenous microorganisms to achieve anti-swelling of the clay minerals and reduce the water sensitivity damage of the reservoir. The microbial community reducing Fe(III) was enriched from the samples of Karamay Oilfield, Xinjiang, and microbial community diversity was analyzed by the 16S rRNA gene sequencing. The Fe(II) ion concentration in the interaction medium was monitored, and the maximum iron reduction rates reached 60.2%. The structural changes of smectite before and after microbial treatment were observed by Fourier transform infrared spectroscopy, X-ray diffraction, and scanning electron microscopy. The result demonstrated that the reduction of Fe(III) was accompanied by the transformation of S-I. There may be some endogenous microorganisms that transform S-I in low permeability reservoirs. This study is of great significance for oilfields to realize clay mineral anti-swelling and eliminate reservoir water sensitivity damage by endogenous microorganisms. [ABSTRACT FROM AUTHOR]

The Chang 8 formation of the Yanchang Group, located in Yuancheng area of the Ordos Basin, is a typical tight oil reservoir in China. This reservoir is characterized by low porosity, low permeability, strong non-homogeneity, and significant difficulty in evaluating the reservoir parameters. To examine and investigate the microscopic pore structure characteristics of the Chang 8 formation, cast thin section and scanning electron microscopy techniques were utilized in this study, Moreover, tests on the core physical properties were conducted and the data from these tests were integrated into the analysis of basic characteristics of the reservoir rock mineralogy, pore permeability, and other fundamental characteristics. The shapes of piezomercury curves were systematically examined to study the characteristics and features of pore structures for the 17 samples. In accordance with the fractal dimension of the NMR T2 spectrum, the reservoir was classified into four categories, and a conversion model delineating the correlation between the NMR T2 spectrum and the capillary pressure curve was formulated through the application of the segmented power function method. This model was then implemented in the interpretation of NMR logging, facilitating the acquisition of a seamless pseudo-capillary pressure curve spanning the entire well section. Three essential parameters reflecting the microscopic pore structure, namely the expulsion pressure, median pressure, and sorting coefficient of the core samples, were extracted. The association between reservoir parameters and reservoir categorization was then determined through the application of a generalized regression neural network. The pseudo-capillary pressure curve reservoir parameters of the whole well section were processed to derive the classification profile of the reservoir, and the classification results demonstrated a strong alignment with those of the mercury injection experiments. This study highlights that the proposed method can provide crucial foundation for the investigations on pore structures in tight oil reservoirs and the evaluation of reservoir classification. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing 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.)

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing 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.)

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]

The Rongchang–Dazu region in western Chongqing (eastern Sichuan Basin, China), known for its seismic activity, is a promising area for deep geothermal resource development; however, practical development is limited. Key geological understandings, such as heat flux, geothermal gradients, the nature of heat sources, thermal reservoir rock characteristics, and the classification of geothermal resources, remain in need of further study. In this work, the targeted area is surrounded by Sinian–Cambrian carbonate gas fields. An analysis of the deep geothermal prospects was conducted using exploration and development data from the Gaoshiti–Moxi gas fields within the Longwangmiao and Dengying Formations. The results indicate that the Rongchang–Dazu area has relatively high heat flow values and geothermal gradients within the Sichuan Basin, correlating with fault structure and seismic activity. Gas test data confirm that the Longwangmiao Formation in the study area reaches depths of 4000 to 4500 metres and exhibits anomalous pressures and temperatures exceeding 140 °C. Meanwhile, the Dengying Formation of the Sinian system lies at depths of 5000 to 5500 metres, with normal pressure, minimal water production, and temperatures exceeding 150 °C, characterising it as a dry-hot rock resource. Adjacent to western Chongqing, the Gaoshiti area within the Longwangmiao Formation, with an estimated flow rate of 100 kg/s, shows that the dynamic investment payback period is significantly shorter than the estimated 30-year life of a geothermal power plant, indicating strong economic viability. Deep geothermal resource development aids in conserving gas resources and enhancing the energy mix in western Chongqing. Future research should prioritise understanding the links between basement faults, seismic activity, and heat flow dynamics. [ABSTRACT FROM AUTHOR]

Enhanced geothermal systems (EGSs) developed by hydraulic stimulation are promising for exploiting petrothermal heat by improving fluid pathways in low-permeable geothermal reservoir rocks. However, fluid injection into the subsurface can potentially cause large seismic events by reactivating pre-existing faults, which is a significant barrier to EGSs. The management of injection-induced seismicity is, therefore, essential for the success of EGSs. During the hydraulic stimulation of an EGS, fluid can be injected into a fault zone or into the rock matrix containing pre-existing faults adjacent to the injection well. The differences in hydromechanical responses between fluid injection into and adjacent to a fault have not been investigated in detail. Here, we performed triaxial fluid injection experiments involving injecting fluid directly and indirectly into a fault in granite rock samples to analyse the distinct hydromechanical responses and estimate the injection-induced seismicity in both cases. Our results suggest that in addition to directly injecting fluid into a critically stressed fault, injecting into nearly intact granite adjacent to the fault could also cause injection-induced seismic hazards owing to the high fluid pressure required to create new fractures in the granite matrix. It is, therefore, important to carefully identify pre-existing faults within tight reservoirs to avoid injecting fluid adjacent to them. Additionally, once prior unknown faults are delineated during hydraulic stimulation, appropriate shut-in strategies should be implemented immediately to mitigate seismic risks. This article is part of the theme issue 'Induced seismicity in coupled subsurface systems'. [ABSTRACT FROM AUTHOR]

Petrophysical evaluation of well logging data is crucial for exploring and improving oil and gas reservoirs. This involves obtaining reliable information about the rocks and fluids in the reservoir to estimate reserves and make informed decisions about drilling, production, and development strategies. In this study, data from six wells in the Matruh-Shushan Basin were evaluated using Log Quality Control procedures. Two zones of interest, Lower and Upper Safa members, were identified, and quantitative interpretation was conducted to determine the most effective parameters defining reservoir quality: Shale Volume, Effective Porosity, and Water Saturation. Results were positive, with promising net pay for both reservoirs. Numerical models and statistical methods were used to account for data uncertainties and provide reliable estimates of reservoir properties. The study highlights the significance of correct interpretation in successfully exploring and producing hydrocarbons. [ABSTRACT FROM AUTHOR]

The incorporation and application of SAGD rapid preheating technology effectively solve the problem of the long preheating cycle in the SAGD steam cycle. The thermal properties of reservoir rocks are an important factor affecting the heat transfer law governing their formation during the rapid preheating process of SAGD. During the rapid preheating process of SAGD, the expansion of the reservoir and the steam cycle process will cause changes in the pore permeability, oil-water saturation, and temperature of the reservoir rocks, which will inevitably lead to differences in the changes that occur in the thermal properties of the reservoir rocks, compared to those under the influence of a single factor. In this study, experiments were conducted to determine the thermal properties of reservoir rocks under the combined influence of pore permeability, oil-water saturation, and temperature, quantitatively characterizing the changes in the thermal properties of reservoir rocks. Using the orthogonal method to design and carry out experiments for determining the thermal properties of reservoir rocks, the main factors affecting the thermal properties of reservoir rocks and the significance of each factor's impact on the thermal properties of reservoir rocks were determined through intuitive analysis and variance analysis of the experimental results. Finally, a regression equation that can characterize changes in the thermal properties of reservoir rocks under the influence of multiple factors was obtained through multiple nonlinear regressions of the experimental results. [ABSTRACT FROM AUTHOR]

Deep oil and gas reservoirs are under high-temperature conditions, but traditional coring methods do not consider temperature-preserved measures and ignore the influence of temperature on rock porosity and permeability, resulting in distorted resource assessments. The development of in situ temperature-preserved coring (ITP-Coring) technology for deep reservoir rock is urgent, and thermal insulation materials are key. Therefore, hollow glass microsphere/epoxy resin thermal insulation materials (HGM/EP materials) were proposed as thermal insulation materials. The materials properties under coupled hightemperature and high-pressure (HTHP) conditions were tested. The results indicated that high pressures led to HGM destruction and that the materials water absorption significantly increased; additionally, increasing temperature accelerated the process. High temperatures directly caused the thermal conductivity of the materials to increase; additionally, the thermal conduction and convection of water caused by high pressures led to an exponential increase in the thermal conductivity. High temperatures weakened the matrix, and high pressures destroyed the HGM, which resulted in a decrease in the tensile mechanical properties of the materials. The materials entered the high elastic state at 150 °C, and the mechanical properties were weakened more obviously, while the pressure led to a significant effect when the water absorption was above 10%. Meanwhile, the tensile strength/strain were 13.62 MPa/1.3% and 6.09 MPa/0.86% at 100 °C and 100 MPa, respectively, which meet the application requirements of the self-designed coring device. Finally, K46-f40 and K46-f50 HGM/EP materials were proven to be suitable for ITP-Coring under coupled conditions below 100 °C and 100 MPa. To further improve the materials properties, the interface layer and EP matrix should be optimized. The results can provide references for the optimization and engineering application of materials and thus technical support for deep oil and gas resource development. [ABSTRACT FROM AUTHOR]

This study used seismic and petrophysics data to identify potential subsurface facies that are viable hydrocarbon productive areas in the southern part of the Orange basin of South Africa. Two target areas were identified as target areas 1 and 2. In Target Area 1, three facies were identified: sand, silt and shale. The sand facies has the best reservoir quality (volume of shale between 20 to 30%; porosity from 9 to 17%; permeability from 5 to 15 mD, and water saturation from 40 to 60%), while the shale facies present the lowest reservoir quality rock (volume of shale greater than 40%; porosity from 0 to 5%; permeability from 0 to 0.5 mD, and water saturation from 80 to 100%). Target Area 1 mainly consisted of silty shale and shaly silt. However, Target Area 2 had the same facies as Target Area 1, except with additional basement facies comprising well-sorted fine to medium-grain sands. Target Area 2 had considerably thicker sand layers; thus, the petrophysical properties are slightly better, with the basement facies having a volume of shale less than 20%, porosity between 20 and 23%, permeability greater than 15mD, and water saturation between 30 and 45%. The overall reservoir rock quality in the triangulated area is generally poor because of a high concentration of clay in the matrix in sandstone layers. Regarding economic potential, Target Area 2 was identified as the most productive area with better reservoir qualities due to the basement facies. The recoverable gas in Target Area 1 is 95 057 cubic metres, while area 2 has a volume of 151 923 cubic metres. This study has shown for the first time that the southern part of the Orange Basin is not economically viable. [ABSTRACT FROM AUTHOR]

Horizontal principal stress is a fundamental parameter for reservoir reconstruction. For improving single well productivity, accurate evaluation of reservoir stress characteristics is of great importance. One of the main challenges in predicting the magnitude of the in situ stress is how to obtain the rock mechanical parameters accurately. An intelligent fusion model was proposed to predict rock mechanical parameters to address the issue that traditional approaches are not very reliable at predicting the rock mechanical parameters of complex lithology reservoirs, using transitional shale reservoir rocks as the research object. Machine learning algorithms such as nearest neighbor regression, support vector machine, and random forest were selected to construct intelligent fusion models of different rock mechanics parameters based on the laboratory test data. Finally, the logging profile of transitional shale reservoir horizontal principal stress in the study area was obtained under the constraints of the empirical physical model and measured in situ stress data. The results showed that the fusion models outperformed the single model on rock mechanics parameters and had higher accuracy in both training and test sets, meeting the engineering requirements for predicting the horizontal principal stress in the study area. [ABSTRACT FROM AUTHOR]

The structural complexities of hydrocarbon reservoirs make it difficult to correlate geological and petrophysical properties. A successful field development depends on accurately mapping the spatial distributions of reservoir key parameters. In this study, we present results on rock type analysis, estimation, and uncertainty evaluation of geological and petrophysical data of 33 wells in one of the south Iranian gas fields. This paper is divided into two parts. In the first part, we used a reservoir rock classification theme based on identifying electrofacies (EFs) and hydraulic flow units by analyzing both log and core data. In the second part of the paper, we performed estimation, uncertainty evaluation, and assessment of the porosity–thickness relationship of the high-quality EFs using geostatistical techniques. We used sequential simulation schemes to map the spatial distributions of porosity and thickness of the high-quality EFs across the field. Using probabilistic approaches, the generated multiple realizations were used to quantify the local and spatial uncertainties. Variogram analysis showed that property distributions had a higher continuity and minimum variance in the NW–SE direction. Based on spatial uncertainty analysis, we found that the indicator-based sequential simulated maps exhibited less spatial uncertainty. Furthermore, the obtained probability maps indicated that the SE part of the study area is more suitable for drilling and production scenarios. [ABSTRACT FROM AUTHOR]

Copyright of Rudarsko-Geolosko-Naftni Zbornik is the property of Faculty of Mining, Geology & Petroleum Engineering 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.)

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]