The Ouan Kasa shaly sand reservoir in the Ghadames Basin of Libya presents significant challenges to drilling operations, particularly due to wellbore instability. The absence of prior geomechanical studies in this area raises concerns about the risks associated with drilling future wells. This study aims to construct one-dimensional mechanical Earth models (1D MEMs) to evaluate formation stability and define an optimal mud-weight window, thereby improving drilling efficiency and reducing operational risks. Data from two wells were analysed, including gamma-ray, sonic and bulk density logs, along with formation micro-imager (FMI) logs. Rock mechanical properties were derived using empirical correlations, the shear-wave velocity was estimated using the Greenberg–Castagna relationship and pore pressure was calculated using Eaton's method, calibrated against modular dynamic tester (MDT) data. Horizontal stresses were estimated using the poroelastic horizontal strain model, while stress orientations were inferred from FMI analysis. Results indicate that the Ouan Kasa Formation has a reduced mechanical stability due to its high shale content and ductile nature. A recommended mud-weight range of 11.2–14.5 ppg was identified to mitigate shear failure and ensure borehole integrity. In addition, the Devonian system is characterized by a normal faulting stress regime ( σ v > σ H > σ h ), with the maximum horizontal stress orientated NW–SE (135°) and the minimum stress orientated NE–SW. This study provides the first integrated geomechanical evaluation of the Ouan Kasa reservoir and offers valuable insights for drilling optimization and the safe development of future wells in the area.

Northern Egypt and its Western Desert region are hydrocarbon provinces that record important Mesozoic extension, yet Jurassic and older synrift strata are still poorly characterized in these two areas, particularly in the onshore Shushan Basin. This work uses seismic-reflection data tied to borehole and geochemical data to investigate three main Jurassic synrift seismic and depositional megasequences in the Shushan Basin: (1) a Lower Jurassic retrogressive megasequence; (2) a Middle Jurassic prograding megasequence; and (3) an Upper Jurassic retrogressive megasequence. These megasequences, defined for the first time in this work, accompanied Late Triassic–Early Cretaceous tectonic extension, with deposition occurring in proximal environments such as rivers, lakes and deltas. Terrigenous organic matter was preserved over long periods of time within clay-rich source intervals, as confirmed via organic geochemical analyses. Significantly, the presence of Type II and Type III kerogen, and a total organic carbon content of up to 3.91% suggest good hydrocarbon source-rock potential in specific Jurassic intervals. One-dimensional burial models suggest that, with sufficient burial, these source intervals generated oil and gas with a recorded maximum yield in the Early Miocene. As a corollary, this work indicates that conventional and unconventional hydrocarbon exploration targets exist in the Shushan Basin. The results show Middle Jurassic shale-rich intervals to be prime tight-gas targets, while Upper Jurassic carbonate units are promising conventional reservoirs in both the central and southern parts of the basin. The high formation temperatures recorded show that geothermal options are also feasible for deep wells, expanding the economic importance of northern Egypt.

Located within the Subei Basin, Gaoyou Sag is abundant in hydrocarbon resources and exhibits significant potential for shale oil exploration and development. However, the organic matter enrichment patterns and paleoenvironmental evolution of the second member of Funing Formation (E₁f₂) in Huazhuang area remain poorly understood, particularly regarding the complex origins of organic matter and their coupling with sedimentary environments. To address these issues, representative shale and crude oil samples from E₁f₂ interval were systematically analyzed using gas chromatography–mass spectrometry (GC–MS), X-ray diffraction (XRD), and inductively coupled plasma mass spectrometry (ICP–MS). The results show that the average pristane/phytane (Pr/Ph) ratio is 0.58, V/Cr ratio is close to 1, and the average V/(V+Ni) ratio is approximately 0.7. The Sr/Cu ratio is significantly greater than 10 in the lower section but markedly less than 10 in the upper section. The Sr/Ba ratio ranges from 0.06 to 1.23, progressively decreasing from bottom to top. Comprehensive analysis indicates that the lower E₁f₂ was deposited in saline lacustrine anoxic environment, while the upper E₁f₂ transitioned to brackish water condition under a warm and humid climate. Based on the distribution of C₂₇–C₂₉ steranes, the organic matter is determined to be mainly derived from a mixture of lower aquatic organisms and terrestrial higher plants. The warm–humid climate, decreasing water salinity, and bottom-water anoxia jointly promoted the enrichment and preservation of organic matter. This study establishes an organic matter enrichment model co–controlled by paleoclimate and paleosalinity, providing a theoretical basis for shale oil exploration in similar lacustrine basins.

The Late Triassic to Early Jurassic Minjur Formation is an unconformity-bound, transgressive-regressive sequence composed of channelized fluvial sandbodies and coastal floodplain/playa mudrocks, deposited along the northern margin of Gondwana. A comprehensive sedimentological, sequence stratigraphic, and seismic geomorphological analysis of the Minjur Formation in Abu Dhabi has significantly enhanced our understanding of its depositional environments, the controls on reservoir distribution, and its overall exploration potential. Reservoir distribution within the Minjur Formation has been interpreted through an integrated approach involving seismic geomorphology, core and wireline log analysis, and regional stratigraphic correlations. In the southwestern onshore region of Abu Dhabi, sinuous, potentially marine-influenced axial channel networks indicate persistent sediment transport toward the Neo-Tethys Ocean to the north. Conversely, the eastern onshore region exhibits a broader drainage system composed of smaller, north-eastward-flowing isolated and branching channels. These channels tend to narrow downstream, suggesting more intermittent flows that likely terminated inland within floodplain or playa settings. The deposition of the Minjur Formation was likely influenced by a combination of tectonic activity, localised halokinesis, eustatic sea-level changes, and climatic variability. From an exploration perspective, the pronounced lithological contrast between the channelized sandbodies and surrounding floodplain mudrocks, along with the presence of bounding unconformities and syn-depositional halokinesis, offers substantial potential for stratigraphic trapping throughout the region.

Mud leakage during workover can contaminate existing fractures and lead to significant deviations in refracturing treatment-pressure design. This study aims to characterize mud leakage behavior in fractured reservoirs and predict its impact on refracturing treatment pressure.A two-phase Darcy-flow framework was established to simulate mud leakage and to obtain the spatial distribution of mud saturation. Based on the simulated mud-retention geometry in existing fractures, a treatment-pressure prediction model was developed by partitioning the fracture into mud-occupied and un-leaked flow regions and incorporating permeability damage. The workflow was validated using field data from two mud-contaminated refracturing wells in the Tarim Basin, northwest China (Well A and Well B).Field data indicate leaked mud volumes of 13.0 m³ (Well A) and 9.6 m³ (Well B), accompanied by substantial productivity degradation (unrestricted flow rate decreased from 142.3×10⁴/d to 52.2×10⁴/d in Well A and from 38×10⁴/d to 1×10⁴/d in Well B) and residual permeability ratios of 0.366 and 0.026, respectively. A baseline pressure prediction that ignores mud impact underestimates the observed treatment-pressure window (110–120 MPa for Well A; 120–130 MPa for Well B) by 20.3–36.2 MPa and 14.6–42.2 MPa, respectively. After incorporating mud retention and permeability damage, the predicted pressure ranges shift to 109.6–117.4 MPa (Well A) and 122.4–146.9 MPa (Well B), yielding clear overlap with the measured pressure windows and substantially reducing the mismatch.This study provides an additive and practically applicable method for pressure-design correction and risk assessment in mud-contaminated refracturing operations.

The pre-salt Aptian reservoirs are responsible for close to 80% of Brazil oil production. The unusual in situ deposits, constituted by magnesian clays, calcite spherulites and fascicular shrubs, were precipitated in a huge alkaline lacustrine system, before the formation of the South Atlantic. The processes that generated the associated resedimented deposits are comparatively still poorly understood, although they correspond to important reservoirs in many pre-salt fields in the Santos, Campos and Kwanza basins. Systematic core and petrographic description provided detailed textural and compositional characterization of resedimented pre-salt deposits from the Santos Basin. They are composed mainly of carbonate intraclasts eroded from the in situ deposits. The predominant massive structure, widespread spatial distribution, and the lack of subaerial exposure indicate that gravitational flows, waves or surface currents cannot be ascribed as their main depositional processes. Internal waves produced by perturbation of the chemocline in the stratified lacustrine system are considered able to generate the observed subtle, recurrent and widespread intercalation of resedimented and in situ deposits. Construction of realistic depositional models for the significant occurrence of these deposits in the pre-salt system will contribute to minimize the exploration risks and optimize the hydrocarbon recovery efficiency from the producing fields.

Organic-rich shale facies of the Lower Jurassic Datta Formation in the Upper Indus Basin, Pakistan was studied using geological and geochemical investigation for assessment the unconventional oil shale reservoir potential. The Datta shale facies is a promising oil-prone stratum, consisting of total organic carbon (TOC) exceeding 2 wt.%, and primarily comprising Type II and II/III kerogens, with a hydrogen index (HI) exceeding 250 mg HC/g TOC. The Datta shale facies is also characterized by higher free hydrocarbon (S 1 ) than TOC, resulting in a high oil saturation index (OSI) between 30.81 mg HC/g TOC and 298.7 mg HC/g TOC, wherein the high OSI of more than 100 mg HC/g TOC indicates a strong potential for oil production. This finding consistent with the current thermally mature of oil window, ranging between early-mature and peak-mature, as supported by vitrinite reflectance (%VRo) values of up to 0.82. This main oil generation window leads to convert extensive of the hydrogen-rich kerogen for commercial oil generation, with a transformation ratio (TR) of up to 65%, as demonstrated in the 1-D basin modeling. The maximum oil generation, with TR values exceeding 50%, leads to high pressure and results in micro-fracture pores in the Datta shale facies. The presence of the non-fabric fracture pores is confirmed by the high-resolution petrographic scanning electron microscopy (SEM). Consequently, these findings highlight that the Datta shale facies is considered for use as an unconventional shale oil reservoir with the suggestion of hydraulic fracturing techniques for production purposes.

This study investigates the mineralogical and textural controls on coke deposition during in situ combustion in reservoir sandstones, with implications for low-carbon energy recovery applications. Experimental simulations using feldspar-bearing, quartz-cemented Penrith Sandstone demonstrate that coke formation, the key requirement of high-temperature combustion, occurs heterogeneously, primarily at grain contacts, along dissolved feldspar cleavage planes and on rough detrital surfaces, but is largely absent from the flat faces of quartz cement. Quantitative X-ray computed tomography and scanning electron microscopy reveal that feldspar-rich zones experience greater porosity reduction through coke deposition, which is influenced by the local specific surface area and mineral–fluid interactions. These findings indicate that feldspathic, poorly cemented and fine-grained sandstones are more favourable substrates for coke formation, enhancing the thermal output potential during in situ combustion and supporting the stable propagation of combustion fronts. The results provide a petrographical framework for reservoir screening aimed at optimizing the selection of lithologies for geothermal energy recovery and related low-carbon strategies.

The seismic interpretation of very thin to thin turbiditic sandstones, particularly when intercalated with siltstones and shales, presents challenges, complicating the exploration and production of hydrocarbons. One of the most significant issues in this environment arises from seismic resolution, which typically cannot resolve thicknesses below 10 to 20 meters. This was observed in the post-salt section of the Brazilian offshore basins. To address this challenge, we improved seismic resolution by applying the TT Transform and combining local frequency, phase, and magnitude components. Compared to conventional seismic attributes, the attributes derived from the TT Transform allowed us to identify depositional turbiditic elements within the turbidite system as outlined in the literature and used as a conceptual model. By adopting this combination, we developed reliable architectural models that respected wellbore information. From these outputs, it is feasible to build robust geological models, providing enhanced information for better project decision-making, enabling project specialists to manage inherent uncertainty and increase the project's profitability.

This study provides a comprehensive review of the petroleum systems in the Iranian Zagros and Persian Gulf regions, spanning the Phanerozoic, with the objective of synthesizing geological, geochemical and basin-modelling data to enhance exploration strategies. Three primary petroleum systems are identified: Paleozoic–Triassic, Jurassic–Cretaceous and Cenozoic, each characterized by distinct source rocks, reservoirs and seals. The methodology integrates extensive literature reviews and original geochemical analyses, including Rock-Eval pyrolysis, vitrinite reflectance, biomarker studies, carbon isotope and kinetic modelling, to assess source-rock maturity, kerogen type and oil-source correlations. The main results highlight the Paleozoic–Triassic system, driven by Silurian Sarchahan ‘hot shales’, feeding gas-rich Permian–Triassic Dalan and Kangan reservoirs, sealed by Triassic Dashtak evaporites, but challenged by deep burial and high non-hydrocarbon content. The Jurassic–Cretaceous system, which contributes more than 50% of Iran's oil, features the oil-prone Sargelu, Garau and Kazhdumi source rocks, with reservoirs in the Khami and Bangestan groups, sealed by the Hith/Gotnia and Gurpi formations. The Cenozoic system, centred in the Dezful Embayment, relies on the Pabdeh source rock, Asmari reservoir and Gachsaran seal, with significant vertical migration from underlying Mesozoic systems. Chemometric classification of 21 oil samples revealed three distinct oil families that are genetically linked to these petroleum systems. Family A oils are attributed to Upper Jurassic–Miocene source rocks, characterized by a high C 28 /C 29 regular sterane ratio. Family B oils correlate to Jurassic or older source rocks, and are classified as high-maturity oils. Family C oils sourced from the Aptian–Albian Kazhdumi Formation and display biomarker parameters indicative of anoxic marine conditions.