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The Cambrian Terreneuvian Yuertusi Formation of the Tarim Basin, regarded as a potential hydrocarbon source rock (TOCmax = 29.8 wt%), preserves the record of the Ediacaran to Cambrian Series 2 transition. This study presents a highresolution multi-proxy investigation of the Sugaitebulake and Yutixi sections of the NW Tarim Basin. Evidence of hydrothermal activity and euxinic conditions in the earliest Cambrian has been delineated by samples from the lower part of the Yuertusi Formation group A, featured by weakly positive Ce anomalies (Ce/Ce*avg = 0.46), extremely positive Eu anomalies (Eu/Eu*avg = 26.39), Y/Ho ratios (Y/Hoavg = 40.48) and several barite layers. Mo and U covariation suggests that the Yuertusi Formation group A and Xiaoerbulake Formation were deposited under sulfidic conditions, whereas the Ediacaran Qigebulake Formation, and Yuertusi Formation groups B and C and D accumulated under suboxic to anoxic conditions. The basin has been weakly restricted and characterized by elevated productivity (Ba-excessavg = 6,410.42 ppm) during Terreneuvian time. Suboxic conditions in late Ediacaran time (Qigebulake Formation) became euxinic conditions in association with increased sea level and productivity sustained by hydrothermal activity and upwelling, which have been preserved in the organic-rich lower part of the Yuertusi Formation. Suboxic conditions were reestablished during the Cambrian Terreneuvian time as reflected in the geochemistry of the upper part of the Yuertusi Formation. Euxinic conditions were once again established early in Cambrian Series 2 Xiaoerbulake Formation. Euxinic conditions were coincident with transgressions of the South Tianshan Ocean during that interval. The accumulation and preservation of organic matter of the Early Cambrian northern Tarim Platform reflect the interaction of hydrothermal activity, coastal upwelling, and sea level change. [ABSTRACT FROM AUTHOR]

Wenchang A oilfield is a recently discovered low-permeability oilfield in the western South China Sea. The exploration target is the Zhuhai Formation, which reservoir lithology changes significantly, and the distribution of favorable reservoirs is unclear. In this study, the reservoir characteristics of the Zhuhai Formation in the Wenchang A oilfield, South China Sea, were analyzed through core identification, thin section identification, physical property testing, prestack geostatistical inversion, and frequency-based AVO inversion. Pre-stack geostatistical inversion is based on geostatistics and combines the seismic inversion algorithm with the stochastic sequential simulation algorithm. While the frequency-varying AVO inversion method is an extension of the conventional AVO inversion method, with its core technology being spectrum decomposition. After frequency division, multiple data sets directly participate in the calculation, which enhances the stability and accuracy of inversion.We also predict the favorable reservoir areas of six small layers in the Zhuhai Formation. The results show that 1) the reservoir lithology of the Zhuhai Formation mainly consists of feldspar quartz sandstone and feldspar quartz sandstone, indicating high compositional maturity. The porosity of the reservoir ranges from 14.0% to 19.0%, with an average value of 16.3%. The permeability of the reservoir ranges from 3.1 mD to 126.1 mD, with an average value of 22.4 mD, indicating a medium porosity and low permeability reservoir. The supporting structure of a sandstone reservoir is particle-supported, with the main contact being the "point-line" contact between particles. The main types of pores in sandstone are primary intergranular pores and secondary intergranular dissolved pores. Some pores are feldspar-dissolved pores, and occasionally there are hetero-based micropore. 2) The diagenesis of the Zhuhai Formation reservoir mainly includes compaction, cementation, and dissolution. Cementation and dissolution have minimal impact on the physical properties of reservoirs. The porosity loss of the reservoir after compaction ranges between 16.0% and 27.9%, and the compaction rate ranges between 40.0% and 69.8%, indicating a medium compaction diagenetic facies. 3) The favorable areas of each layer of the Zhuhai Formation are mainly concentrated in the southwest of the study area. The upper layer of ZH1I, the upper layer of ZH1II and the lower layer of ZH1II exhibit the best physical properties, the thickest favorable sand body, the strongest oil and gas display, the widest range of favorable areas, and the greatest exploration potential. The favorable exploration potential of layer 1 in the lower part of ZH1I and layer 2 in the upper part of ZH1II is moderate. The second layer in the lower part of ZH1II has the poorest properties and lower exploration potential. The main factors affecting the favorable area include physical properties, oil and gas display, sand body thickness, etc. [ABSTRACT FROM AUTHOR]

The identification of the origins of source rock palaeo-overpressure based on logging response parameters is frequently influenced by the presence of organic matter. To accurately identify the paleo-overpressure origin of source rocks and employ an appropriate method for paleo-pressure calculation, this study proposes a quantitative approach to assess the influence of organic matter content on overpressure analysis. The findings demonstrate that the presence of organic matter in Chang 7 shale leads to an increase in acoustic time difference and a decrease in density. After incorporating the multicomponent rock equivalent volume model correction, it is evident that the paleo-overpressure observed in the Chang 7 member is not attributed to undercompaction but rather to fluid expansion mechanisms. In conjunction with the acoustic velocity-density palte method, the paleo-overpressure of the Chang 7 member is attributed to undercompaction and expansion resulting from hydrocarbon generation. The pressure evolution of the Chang 7 member has been reconstructed based on the identification of its paleo-overpressure origin. The distribution characteristics of paleo-pressure recovered based on hydrocarbon generation expansion exhibit a strong correlation with the reservoir. The reliability of the correction method for organic matter influence is demonstrated. The proposed method is not only applicable for the investigation of paleo-pressure, but also holds significant implications for the assessment of pressure within organic-rich intervals. [ABSTRACT FROM AUTHOR]

Mixed siliciclastic-carbonate systems are regulated interactively by factors such as siliciclastic sediment supply, carbonate production, sea-level change, tectonism, and climate conditions. These systems record vital information that aids in understanding ancient environments. This study used a merged 3D seismic volume, in conjunction with over 100 industrial wells, to systematically investigate the stratigraphic-sedimentary evolution of such a system within the Huizhou Sag of the Pearl River Mouth Basin, located on the northern continental shelf of the South China Sea. In total, six major sequence boundaries were identified for the Zhujiang Formation within the area, thus subdividing the interval into five typical third-order depositional sequences. Each of these sequences can be divided into a transgressive and a highstand systems tract. Lowstand or falling stage systems tracts were also recognized, the deposition of which was potentially in response to the uplifting process of the Dongsha Rise. During the deposition of the Zhujiang Formation, the Huizhou Sag may have undergone a sequential evolutionary history from delta-shore, to delta-shore-tidal-lagoon, to delta-shore-carbonate, and finally to delta-shore-shallow marine systems. This evolution responded to a varying degree of mixing processes, which was mainly regulated by siliciclastic sediment supply, confined paleomorphology, and local oceanic currents. Furthermore, the deposition of the Zhujiang Formation in the Huizhou Area was time-equivalent with the spreading process after the ridge jump of the South China Sea (23-16.5 Ma), providing valuable insights into sea-level fluctuations, provenance changes, and tectonic evolution. Our results may also shed light on the evaluation of lithologic traps and hydrocarbon sweet spots within mixed siliciclastic-carbonate systems. [ABSTRACT FROM AUTHOR]

Reservoir heterogeneity is one of the key factors affecting the exploration and development of oil and gas reservoirs. The Kh2 layer in the A field of Central Iraq is a major pay zone with strong longitudinal and lateral heterogeneity. The heterogeneity, controlled by geological factors, has not yet been confirmed, which seriously restricts the development of this pay zone. This study aims to establish a geological pattern for the reservoir heterogeneity of bioclastic limestone, providing a geological basis for heterogeneity evaluation. Based on the core observation, thin-section identification, and physical property analysis, the microfacies are classified, and the diagenetic sequences and the pore structure of the Kh2 layer are analyzed. Seven types of microfacies are developed in the Kh2 layer, namely, planktic foraminiferal wackestone (MFT1), lamellar bioclastic wackestone (MFT2), intraclastic-bioclastic packstone (MFT3), green algal packstone (MFT4), green alga-pelletoid packstone (MFT5), bioclastic-intraclastic packstone (MFT6), and intraclastic grainstone (MFT7). The heterogeneity of the different microfacies and heterogeneity within the same microfacies were evaluated using the variation coefficient of permeability tested from cores collected from wells and calculated by well- logging at different intervals. The highest heterogeneity was observed in the lamellar bioclastic wackestone (MFT2), with an average variation coefficient of 0.72. The lowest heterogeneity was observed in the green algal packstone (MFT4), with an average variation coefficient of 0.11. The vertical heterogeneity of the permeability is mainly controlled by sedimentation, while the lateral heterogeneity is mainly influenced by cementation, bioturbation, and the distribution of green algae. Finally, a micro-scale geological pattern for determining the reservoir heterogeneity of bioclastic limestone reservoirs is established. This study can guide the current injection development and remaining oil prediction in oilfields with similar backgrounds. [ABSTRACT FROM AUTHOR]

This document is an editorial for a special issue of the journal Minerals, focusing on the heterogeneities of carbonate reservoirs. The editorial emphasizes the importance of understanding these heterogeneities for optimizing exploration and production strategies, as they influence fluid flow behavior and the recoverable reserves within the reservoir. The editorial also highlights the need for further research to explore the implications of heterogeneities at a broader scale and recommends the use of advanced technologies and multidisciplinary approaches. The document provides a summary of five papers included in the special issue, which cover topics such as the genetic mechanism of dolomite reservoirs, diagenetic alterations in the Chiltan Formation, the formation mechanism of dolomite-mottled limestone reservoirs, characteristics of crystalline dolomites in the Sanshanzi Formation, and facies variations in the Sarvak Formation. The research presented in this special issue contributes to our understanding of ancient carbonate platforms and dolomite reservoirs and provides a framework for future studies in oil and gas exploration. [Extracted from the article]

The effects of overburden pressure on porosity and permeability are often neglected in formation evaluation, while it has important influences on reservoir storage and flow capacities. The present work focuses on the effects of overburden pressures on porosity changes in carbonate Mishrif Formation, Iraq. The porosities of 73 core plug samples have been measured under 4 overburden pressures. Winland Equation was reconstructed using the pore throat size of 165 samples which were measured by mercury injection. The Winland, FZI, Lorenz, and porosity data ranges rock typing methods have been used to manage the heterogeneity. Winland recognized as the most suitable method, because porosity, permeability and pore throat sizes are considerably affected by overburden pressures. Two factors of porosity and permeability are affected by overburden pressures in FZI method. In data grouping using ranges of porosity, the effective factors reduce to one. Lorenz method groups successive data and so is not effective for grouping the samples. Results showed that the best methods of managing heterogeneity for overburden tests are Winland, FZI, porosity data range, and Lorenz method, respectively. These new findings can help for better understanding of porosity–pressure relationships with respect to the reservoir heterogeneity. [ABSTRACT FROM AUTHOR]