Journal of Petroleum Geology最新文献

{"title":"Geological and Petrophysical Characterization of the Triassic Sedimentary Succession of Benkahla Field in the Oued Mya Basin, Central Sahara Platform, Algeria","authors":"Nassira Mebrouki,&nbsp;Bassem S. Nabawy,&nbsp;Messaoud Hacini,&nbsp;Saad Mogren,&nbsp;Elkhedr Ibrahim,&nbsp;Leila Sahri","doi":"10.1111/jpg.70053","DOIUrl":"https://doi.org/10.1111/jpg.70053","url":null,"abstract":"<div>\u0000 \u0000 <p>The Triassic clastic sequence in the Oued Mya Basin is one of the most prolific ones in the central Sahara platform of Algeria. However, no detailed petrophysical study has been published on the Triassic sequence in the Oued Mya Basin. Therefore, this study aims to examine the structural setting and petrophysical properties of the Triassic sequence in Benkahla Field within the Oued Mya Basin. A set of well log data, including the gamma-ray, density, neutron, and resistivity logs, was available from 21 wells to study the petrophysical properties of the Triassic sequence in Benkahla Field to estimate the total and effective porosity, shale volume, water saturation, and the net-pay thickness. In addition to the well log data, a set of core data was available, including density, porosity, and permeability that have been used to calibrate the well log data and estimate the reservoir quality parameters. This helped in defining the prolific zones in the Triassic reservoir. With the present data, some <i>X</i>–<i>Y</i> plots, iso-parametric maps, and facies models were prepared. The prepared plots, maps, and models indicated that the Benkahla Field is primarily controlled by a complex geometry configured by a set of NE–SW faults, along with another subsidiary set oriented N–S. From the well log data, the average values of porosity, water saturation, shale volume, and net-pay thickness of this sequence in the various wells are promising. Considering the core data, it is achieved that the Triassic sequence can be divided into seven petrophysical static rock types (PSRTs), with the best reservoir quality measured for the PSRT1. The unusually high flow zone indicator (FZI), effective pore radius of Winland (<i>R</i>₃₅), and permeability (<i>k</i>) values, along with relatively fair porosity values, indicate the presence of a microfracture system that has improved the reservoir quality of this rock type. On the other hand, the PSRT7 is characterized by the lowest reservoir quality. The applied workflow for this case study is applicable to other highly fractured clastic reservoirs in North Africa and elsewhere that are characterized by unusually high FZI and <i>R</i>₃₅.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"741-771"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215140","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Petroleum Systems in the Geisum Area, South Gulf of Suez, Egypt: Insights from 1D Basin Modeling and Fluid Geochemistry","authors":"Sherif Farouk,&nbsp;Ahmed Y. Tawfik,&nbsp;Naira Magdy Lotfy,&nbsp;Ahmed K. El-Behery,&nbsp;Mostafa Monged","doi":"10.1111/jpg.70040","DOIUrl":"https://doi.org/10.1111/jpg.70040","url":null,"abstract":"<div>\u0000 \u0000 <p>This study aims to unravel the petroleum system(s) of the Geisum area within Egypt's prolific Gulf of Suez rift basin through investigating the hydrocarbon potential of source rocks and genetic origin of petroleum plays. A total of 135 cutting samples were analyzed using organic geochemical procedures, including Rock-Eval pyrolysis and vitrinite reflectance (%Ro), whereas 1D basin models were applied to simulate the basin's burial and thermal histories. Gas chromatography-flame ionization detector (GC–FID), GC–mass spectrometry (GC–MS), and GC-combustion–isotope ratio mass spectrometry (GC–C–IRMS) were conducted on 12 crude oils and six source rock extracts to assess bulk geochemical characteristics, biomarkers, and isotopic compositions of parent source rocks. The 1D-modeling results along the NW–SW profile suggest that the Geisum area is a productive province, including Brown Limestone as the primary source (TR = 85%–95%), whereas Matulla/Wata contributed moderately (TR = 25%–44%), and Rudeis only expelled hydrocarbons in the southern compartment. Furthermore, heat flow (HF) rather than erosion predominantly controls thermal maturity, with peak generation occurring during the Late Miocene (7–5 Ma) in the northern and southern sectors. Structurally, the area is divided into three compartments due to Oligocene rifting, which influenced hydrocarbon migration pathways. The multivariate chemometric analysis reveals three genetically distinct oil families distributed across different oilfields in the Gulf of Suez. Family I, in the Geisum oilfield, likely derives from carbonate-rich Sudr/Brown Limestone (high gammacerane, C₂₉ sterane dominance, depleted δ¹³C). Family II, from the same oilfield, is attributed to marine Matulla shales (moderate gammacerane, C₂₇ steranes, similar δ¹³C). Family III, from the Tawila oilfield, appears sourced from mixed marine/lacustrine Rudeis sediments (low gammacerane, C₂₈ steranes, enriched δ¹³C).</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"549-577"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215117","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrating Geochemical and Petrophysical Data to Constrain Source Rock Potential in the Abu Roash Formation, Silah Field, Egypt","authors":"Mohamed Osman Ebraheem,&nbsp;Ahmed Hosny Senosy,&nbsp;Hamza Ahmed Ibrahim","doi":"10.1111/jpg.70044","DOIUrl":"https://doi.org/10.1111/jpg.70044","url":null,"abstract":"<div>\u0000 \u0000 <p>This study presents an integrated geochemical and petrophysical dataset to constrain the source rock potential of the Abu Roash (A/R) within the Silah. Lithological, geochemical, and petrophysical data were integrated to assess their hydrocarbon generation potential. Analyses were performed on cutting samples from three drilled wells by applying total organic carbon (TOC), Rock-Eval pyrolysis, and wireline logging. The results reveal a significant contrast in the source rock between F and E members within the A/R formation. The F member exhibits good to excellent organic richness, with TOC varying between 1.68 and 4.21 wt% and a high Hydrogen Index (HI) (452–722 mg HC/g TOC), pointing to oil-prone Type I/II kerogen. In contrast, the E member shows fair to good richness, having low TOC (0.58–1.50 wt%) and HI (62–131 mg HC/g TOC), displaying gas-prone Type III kerogen. Thermal maturity assessment indicates that the A/R F predominantly exhibits immature to early mature characteristics, while the A/R E member has entered the main oil window. Well logging analyses corroborate the geochemical findings, showing characteristic responses for organic-rich intervals. The study concludes that the F member is the primary, high-quality source rock with significant oil generation, while the E member possesses fair potential for gas generation. These findings critically de-risk exploration and delineate prospective zones for future hydrocarbon development in the Silah field.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"622-634"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215126","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Machine Learning–Based Real-Time Lithology Identification From Drilling Data in the Ca Tam Offshore Field","authors":"Hung Tien Nguyen,&nbsp;Duong Hong Vu,&nbsp;Hoa Minh Nguyen","doi":"10.1111/jpg.70062","DOIUrl":"https://doi.org/10.1111/jpg.70062","url":null,"abstract":"<div>\u0000 \u0000 <p>Accurate real-time identification of lithological layers during drilling is essential for optimizing borehole stability, reducing operational risks, and improving reservoir characterization. This study develops a data-driven approach for immediate lithology classification using standard drilling parameters combined with supervised machine learning (ML) techniques. The method was applied to time-series datasets from wells in the Ca Tam oil field, offshore Vietnam—an area characterized by complex and heterogeneous stratigraphy. Four drilling parameters were selected as model inputs: weight on bit (WOB), torque, standpipe pressure (SPP), and rate of penetration (ROP). After preprocessing, including noise and outlier removal using the modified <i>Z</i>-score method, four ML algorithms were trained and evaluated to classify lithology into three categories: sand, claystone, and shale. The tested models included Random Forest (RF), Extreme Gradient Boosting (XGBoost), support vector machine (SVM), and artificial neural network (ANN). Among these algorithms, the RF model delivered the highest and most consistent performance, achieving an accuracy of 0.873 on the test set, slightly outperforming XGBoost (0.87). The small gap between RF's training and testing accuracy indicates strong generalization ability with minimal overfitting. Importantly, when independently validated on the blind well CT-108, the RF model maintained high reliability with an accuracy of 84.23%, confirming its robustness under real drilling conditions. The results demonstrate that the RF model is highly suitable for deployment in real-time lithology prediction systems. Such a predictive framework enables drilling operators to proactively adjust key parameters (e.g., WOB and rotary speed [RPM]), improving operational efficiency, enhancing borehole stability, mitigating risks such as stuck pipe incidents, and significantly reducing drilling time and costs in the Cuu Long Basin.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"840-856"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215157","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Subsurface Imaging of the Jurassic–Cretaceous Reservoir Sequence in Pepi Field Using Seismic Attributes","authors":"Sara El Ghareeb,&nbsp;Mohamed A. Elbastawesy,&nbsp;Mohamed S. El-Sadek,&nbsp;Abdelaziz L. Abdeldayem,&nbsp;Shadia A. Mohamed,&nbsp;Neamat Aboelhassan,&nbsp;Saad Mogren,&nbsp;Elkhedr Ibrahim,&nbsp;Bassem S. Nabawy","doi":"10.1111/jpg.70045","DOIUrl":"https://doi.org/10.1111/jpg.70045","url":null,"abstract":"<div>\u0000 \u0000 <p>The main target of the present study is to map the subsurface structure and elucidate trapped hydrocarbon accumulation. This has been achieved in terms of structure and stratigraphy using 2D seismic data in SEG-Y format with velocity and some borehole information of the Jurassic–Cretaceous reservoirs in the Pepi Field. The Pepi Field is a main hydrocarbon-producing field lying in the Shushan Basin, which is among the largest coastal sedimentary basins in the Northwestern Desert of Egypt. The present study was carried out primarily by interpreting seismic profiles, transforming them into time and depth structural contour maps, and after that building 3D structural models and profiles. Interpreting the resulted maps, model, and computed seismic attributes shows the presence of three master faults. The first major fault extends from NE to SW, and the second major fault extends E–W at the eastern portion of the studied area, resulting probably from Jurassic rifting associated with plate motions. The third main fault is an anti-master fault extending from NW to SE, probably associated with the Cretaceous rifting of North Africa. Interpreting the computed seismic attributes (second derivative and tuning effect) shows the presence of a large channel sand lens in the Lower Safa reservoir, which appeared in the central portion of the study area. Three-way dip structural closure around faults and horst blocks represents the most productive sites for new prospect wells in the Pepi Field and similar settings elsewhere to increase the production. The applied workflow can be extended to other analogous prolific structures in the Northwestern Desert and to other structural analogues in similar basins elsewhere, particularly in NE African basins.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"635-654"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215192","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Enhanced Oil Recovery Using Nanofluid Injection in Marginal Wells: A Techno-Economic Evaluation for Prolonged Field Life and Job Retention in Oil-Dependent Regions","authors":"Balasubramanian Ragunathan,&nbsp;Lakshmana Rao Jeeru","doi":"10.1111/jpg.70061","DOIUrl":"https://doi.org/10.1111/jpg.70061","url":null,"abstract":"<div>\u0000 \u0000 <p>Marginal oil wells, often abandoned due to low pressure and declining productivity, still contain significant untapped reserves that could support energy security and local economies. This study investigates nanofluid-enhanced oil recovery (EOR) as a cost-effective and scalable solution for revitalizing such wells. Silica- and cobalt ferrite (CoFe₂O₄)-based nanofluids, stabilized with sodium dodecyl sulfate (SDS), were synthesized and tested on sandstone and carbonate cores under simulated reservoir conditions. Core flooding experiments demonstrated an incremental oil recovery of 14%–18% at an optimal concentration of 0.05 wt%, driven by interfacial tension reduction (32 to 6 mN/m) and wettability alteration (115°–45°). Economic analysis showed a recovery cost of $5.30/barrel and a breakeven oil price of $34, with a return on investment up to 2.4×. A Techno-Socio-Economic Viability Index (TSEVI) indicated strong socio-economic benefits, including 60%–75% employment retention and positive net present value. Overall, nanofluid EOR presents a technically efficient, economically viable, and socially beneficial approach for extending the productive life of marginal oilfields.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"827-839"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215230","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Formation Mechanism, Reservoir Characteristics, and Identification of Low-Efficiency Oil Layers: A Case Study of the Chang 6 Reservoir, Ordos Basin","authors":"Wenbo Zhang,&nbsp;Jie Zhu,&nbsp;Meiling Fan,&nbsp;Tao Gu,&nbsp;Xing Bai","doi":"10.1111/jpg.70049","DOIUrl":"https://doi.org/10.1111/jpg.70049","url":null,"abstract":"<div>\u0000 \u0000 <p>This study presents a comprehensive characterization of the low-efficiency reservoirs within the Chang 6 member of the Ordos Basin, elucidating their formation mechanisms and establishing quantitative identification standards. These reservoirs typically develop in low-energy sedimentary microfacies, specifically the margins of underwater distributary channels and inter-distributary bays. Petrological analysis reveals that the reservoirs consist of fine-grained feldspar sandstones rich in plastic interstitial materials and carbonate cements (&gt;5%), exhibiting ultralow physical properties (average porosity 7.12%, average permeability 0.27 mD) and a restricted pore structure (average displacement pressure 1.79 MPa, median throat radius 0.03 µm). The genesis of these low-efficiency zones is governed by a sedimentary-diagenetic coupling mechanism: Fine-grained sedimentation facilitated intense mechanical compaction, whereas late-stage carbonate cementation caused substantial porosity loss, solidifying the tight nature of the formation. Hydrocarbon accumulation follows a “densification before accumulation” model, driven by an overpressure difference of 6–7 MPa generated by the underlying Chang 7 source rocks, which facilitated migration through microfractures into the tight sand bodies. To address the challenge of identifying thin, low-resistivity oil layers, Walsh inversion and resolution matching techniques were employed to enhance logging signal precision. On the basis of core-log calibration, a quantitative identification standard was established, defining low-efficiency oil layers by an acoustic transit time <span></span><math></math> and deep resistivity <span></span><math></math>. Despite their marginal petrophysical properties, the reservoirs exhibit a high brittleness index (&gt;60%) and low horizontal stress difference, indicating that large-scale volume fracturing is a viable strategy for commercial development.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"702-715"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215096","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Production Performance Evaluation of Multilateral Wells Using Inflow Control Valves: Managing Inter-Lateral Interference and Enhancing Zonal Contribution","authors":"Abdulfattah Yousif Yaqoob,&nbsp;Ibrahim Fatih Rasul,&nbsp;Ahmed Salih Mohammed","doi":"10.1111/jpg.70059","DOIUrl":"https://doi.org/10.1111/jpg.70059","url":null,"abstract":"<div>\u0000 \u0000 <p>This study quantifies the effectiveness of inflow control valves (ICVs) in mitigating inter-lateral interference and optimizing production performance in multilateral wells (MLWs). A detailed MLW model is developed in PIPESIM to investigate how ICV opening sizes (25%, 50%, and 75%) affect zonal contribution, total production rate, and flow balance across heterogeneous formations. The analysis identifies the best-performing ICV configuration among the evaluated scenarios, maximizing overall well-deliverability while preventing dominance by high-mobility zones. Additional sensitivity analyses assess the robustness of the selected ICV setting under variations in reservoir pressure, water cut, gas–oil ratio, and permeability anisotropy. The results provide practical guidance for designing and optimizing ICV-controlled MLW completions.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"809-826"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215156","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Geochemical Characteristics and Accumulation Processes of Crude Oils in the Penyijingxi Sag, Junggar Basin, NW China","authors":"Wenlong Jiang,&nbsp;Ablimit Imin,&nbsp;Zhenyu Cui,&nbsp;Yang Han,&nbsp;Hailei Liu,&nbsp;Maoguo Hou","doi":"10.1111/jpg.70054","DOIUrl":"https://doi.org/10.1111/jpg.70054","url":null,"abstract":"<div>\u0000 \u0000 <p>Multiple oil and gas fields have been discovered in the deep strata of the Penyijingxi Sag's surrounding tectonic belts. However, the origin and accumulation process of crude oils remain controversial or unclear. Geochemistry, basin modeling, and geological analysis were comprehensively employed to address these issues. The result shows that crude oils of the study area can be categorized into two types. Type 1 oils, derived from P₁<i>f</i> source rocks, are primarily distributed in the Dinan Uplift, the southern area of the Mosuowan Uplift, and Mobei Uplift. Type 2 oils, sourced from P2w source rocks, are mainly found in the Qianshao Slope and the northern area of the Mosuowan Uplift, with discovered oils dominated by high-maturity hydrocarbons from late-stage charging. The study area had two hydrocarbon charging periods and two migration periods: P₁<i>f</i>-sourced hydrocarbons charged reservoirs in the Middle-Late Jurassic, then Yanshan tectonism destroyed paleo-oil reservoirs in the Late Jurassic-Early Cretaceous; P₂<i>w</i> source rocks generated hydrocarbons extensively in the Late Cretaceous (mixing with earlier P₁<i>f</i> secondary reservoirs), and finally Himalayan tectonism drove northward oil-gas migration at the end of the Paleogene, leading to mixing, re-accumulation in new traps, and the current distribution pattern.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"772-788"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215079","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reservoir Properties of Fluvial-Lacustrine Triassic Sandstones in the Newark Basin","authors":"T. H. Shaw,&nbsp;S. Misner","doi":"10.1111/jpg.70046","DOIUrl":"https://doi.org/10.1111/jpg.70046","url":null,"abstract":"<div>\u0000 \u0000 <p>Reservoir quality of Stockton Formation (Triassic) fluvial-lacustrine arenites was investigated by calibrating a porosity petrophysical model for the Princeton 1 core hole, drilled on the hinged limb of the basin half-graben, and then applying the model to two deep wells drilled on rider blocks downthrown to the basin-bounding escarpment fault in the axial depocenter. Core plug measurements of porosity, permeability, and grain density were used to calibrate a petrophysical model of effective porosity for the Princeton core hole using sonic and density logs. Neutron log measured porosity is typically 2–3× core-measured porosity, so this study relied on the sonic and density logs to derive in situ porosity. Some density log measurements may be high due to tool error. Core porosity and permeability have a strong exponential correlation, and arkosic and lithic arenites with porosity greater than 13.5% are likely to have permeability greater than 10 mD. In the Princeton 1, 126 ft. of net reservoir is present in the Stockton Formation gross interval (1528 ft.). Although no core data are available for the deep wells, and wireline log quality is poor to fair, no arenites in either of the deep wells exceeded the 13.5% net reservoir cutoff. The low permeability of the fluvial sandstones in the basin axis is confirmed by analysis of the Cabot 1 Drill Stem Test. The data from all three wells are consistent with progressive occlusion of porosity with burial, due to quartz overgrowth cementation. Secondary porosity, resulting from grain dissolution, offsets some of the porosity loss, but there is a net reduction of porosity with burial. Given the lack of evidence for porosity preservation at depth or development of significant secondary porosity, Stockton Formation reservoirs capable of injection, of either fluids or CO₂, are likely limited to the hinge limb of the Newark Basin.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"49 3","pages":"655-670"},"PeriodicalIF":1.7,"publicationDate":"2026-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148215151","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}