The Clair Field is thought to contain the largest hydrocarbon accumulation on the UK continental shelf, with the principal reservoir comprising low matrix-permeability, naturally fractured, Devonian clastic red-beds of the Lower Clair Group (LCG). The pre-2020 development plan on Clair Ridge focused on achieving production rates via targeting natural fractures. However, recent challenges with open fracture prediction (from early-water-breakthrough to low productivity wells) has led to a renewed focus on understanding the matrix. This study summarises the predictability of matrix character across the LCG, specifically to (i) optimise well placement (matrix property trends), (ii) understand completion requirements (rock strength trends), and (iii) improve pre-drill deliverability predictions and well sequences. The study integrated a range of reservoir quality analysis with sedimentology, core observations, petrophysical log, and heavy minerals. Analysis unveiled a relationship between the resulting sedimentological characteristics (facies), diagenetic overprint, primarily calcite cement, and the contrasting styles of reservoir quality across the LCG units which denote fluctuating climatic conditions. Furthermore, constraining spatial trends in clay mineral volumes (source of calcite cement) within a resolved depositional model has produced a pre-drill predictive capability in cement volumes and facies (matrix character). The availability of a predictive model for matrix character has increased confidence in well performance prediction and impacted well sequencing, reservoir targeting and completionsstrategies. Together with a successful production-increasing drilling strategy, this has increased production on Clair Ridge from 40 mboed (thousand barrels of oil equivalent per day) to 80 mboed in 2021 alone.

Accurate porosity prediction is essential for reliable reservoir characterization in data-limited and heterogeneous formation. Traditional approaches generally have a difficulty handling the inherent complexities and uncertainties of well log data. This study applies and compares three machine learning (ML) approaches, including Artificial Neural Network optimized with Levenberg-Marquardt (ANN-LM), Random Forest (RF), Fuzzy Logic (FL) along with a baseline Multiple Linear Regression (MLR) model, to estimate total porosity from standard geophysical well-logs in three wells from the Mazalai Gas Field (MGF), Kohat Basin, Pakistan. The models utilize sonic, neutron porosity, bulk density, and gamma ray as input parameters. The ANN-LM model was trained using backpropagation and K-fold cross-validation. RF was implemented as an ensemble of decision trees with feature ranking, FL employed Gaussian membership functions in ten bins, and MLR served as a baseline linear method. Model performance was evaluated using the coefficient of determination (R²) and root mean square error (RMSE). ANN-LM showed the strongest generalizability and robustness, achieving R² = 0.99 and RMSE = 3.5 pu by effectively minimizing errors in complex, nonlinear and heterogenous data. RF and FL performed reasonably well achieving R 2 equal to 0.89 and 0.85 respectively, but showed reduced generalization to unseen data. MLR demonstrated the lowest performance acquiring R 2 =0.82. Additionally, A Taylor diagram analysis revealed that ANN-LM provided the most accurate and statistically consistent predictions, closely matching the reference data. These results show machine learning, especially well-optimised neural networks, greatly improves porosity prediction from logs, strengthening reservoir evaluation and development planning in MGF-like settings.

Significant progress has been achieved in Paleogene hydrocarbon exploration in the Pinghu Slope Belt of the Xihu Depression, but the mechanisms by which fault-caprock configurations control differential accumulation remain unclear. Using 3D seismic interpretation, geochemical data, fault activity analysis, and fluid-inclusion geochronology, this study investigates the multistage evolution of the Pinghu Fault (F1) and its coupling with caprock development in governing hydrocarbon migration. The results indicate that the Pinghu Slope Belt has excellent source rock conditions, and the geochemical characteristics of oil and gas suggest that hydrocarbon accumulation is characterized by near-source hydrocarbon charging. F1 evolved from multiple isolated segments into a unified fault plane through lateral and dip linkage, followed by late-stage segmented reactivation. Source rocks reached peak hydrocarbon generation by the end of the Miocene, with two key charging events at ∼15 Ma (local) and ∼5 Ma (regional). Pre-Late Miocene dip linkage and subsequent reactivation provided critical vertical migration pathways during peak generation. Although thick mudstone caprocks occur in the Pinghu Formation, faulting has disrupted their continuity. Analysis of fault-caprock configurations shows that seal integrity is lost when residual thickness falls below 63.6 m, while fault throws under 100 m reduce accumulation potential near faults. Under a multiphase tectonic background, the coupled fault-caprock sealing capacity plays a critical role in hydrocarbon migration and vertical distribution. This provides important insights for predicting exploration targets in faulted basins.

High-quality source rocks exert primary control on hydrocarbon accumulation in continental lacustrine basins, particularly for tight sandstone oil reservoirs. The identity of the principal source rocks for Chang 7 tight oil in the Yanchang Formation, Ordos Basin, and their control mechanisms on accumulation and enrichment remain uncertain. This study integrates gas chromatography–mass spectrometry (GC–MS) analysis of mudstones, oil shales, and crude oils with hydrocarbon generation–expulsion simulations, abnormal pressure calculations, and fluid inclusion trapping pressure reconstruction to establish oil–source correlations, characterize primary source rocks, and define controlling accumulation mechanisms. Results demonstrate that: (1) Chang 7 tight oil was sourced predominantly from Chang 7 oil shales in a "lower generation–upper reservoir" configuration. (2) These oil shales are laterally extensive with substantial thickness (>15 m), high organic matter abundance (average TOC 11.36 wt.%), excellent kerogen quality (Types I and II₁), and moderate thermal maturity (average Ro 0.85%). (3) Cumulative hydrocarbon generation intensity averaged 159.46 × 10⁴ t/km², providing abundant material for tight oil accumulation. (4) Source–reservoir pressure differentials (SRPD) averaging 15.58 MPa provided the necessary driving force for efficient oil charging into tight reservoirs. (5) High-quality oil shale distribution directly governs tight oil distribution, with transitional zones between hydrocarbon generation centers and high-pressure domains representing optimal enrichment fairways. These findings clarify the fundamental role of lacustrine oil shales in tight oil systems and provide practical guidance for exploration in analogous continental basins.

Hydrogen sulfide (H 2 S) is a relatively common component in hydrocarbon fields, where it may be mixed with hydrocarbon oil or gas in proportions up to 50% or more. Such hydrocarbons are often described as ‘sour’. The H 2 S primarily originates from thermochemical sulfate reduction associated with evaporites, though biogenic pathways may apply in some cases. Hydrocarbon fields with the highest concentrations of H 2 S often remain undeveloped, representing already-discovered resources that could support the transition towards a lower-carbon economy. Meanwhile, hydrogen — recognized as a critical element of the energy transition — can be obtained from H 2 S currently by several energy consuming processes. A new subsurface engineering concept introduced here combines the rehabilitation of stranded sour hydrocarbon resources via H 2 S removal with the production of potentially economic amounts of hydrogen. The proposed approach removes H 2 S from the hydrocarbons as they are passed through a subsurface iron-rich ‘scavenging’ reservoir. Reactions between the sour hydrocarbons and the iron minerals in this reservoir convert H 2 S to solid iron sulfide (pyrite) releasing hydrogen gas during the process. Sweetened hydrocarbons, hydrogen, or both, can then be produced. Subsurface removal of H 2 S and sequestering of sulfur from known stranded hydrocarbons avoids the cost and risk of surface-based H 2 S facilities as well as exploration costs for new hydrocarbons in pristine locations. Hydrogen produced from H 2 S in this way is called here ‘amber hydrogen’, an addition to the hydrogen color spectrum that can also be applied to hydrogen produced from H 2 S by any method.

Shale gas, a clean energy source with large reserves and wide distribution, is gaining global attention. The Nanpanjiang Basin, in the southern part of Yangtze Block, is a strategic area for marine shale-gas exploration, with the Tian'e region as a key target. Field investigations and previous studies have confirmed the distribution of Lower Devonian Tangding shale in the Nanpanjiang Basin. This study, using organic geochemistry, X-ray diffraction and scanning electron microscopy, analysed the geochemical characteristics of source rocks, shale reservoir properties, gas content and preservation conditions. The Tangding shale is 100–250 m thick, with burial depths of 2100–4200 m. The total organic carbon (TOC) values of the shales exceed 2.0 wt%, comprising mainly kerogen types Type II 1 –II 2 and high- to over-mature organic matter, indicating excellent source-rock potential. The shales contain a high percentage of brittle minerals, with well-developed pore spaces and adsorption capacities, suggesting a good shale-gas reservoir. A relatively high clay mineral content, along with strong compaction and cementation, enhances the shale's self-sealing capacity, ensuring good preservation conditions for shale gas. The gas content is relatively high, indicating significant shale-gas accumulation. Multi-episode tectonic movements have significantly influenced shale-gas preservation. Compared with typical shale-gas accumulation conditions in other basins, the Tangding shales in the Tian'e area offer favourable conditions for shale-gas accumulation, making the northwestern part of the Tian'e area an important target zone for shale-gas exploration in the Nanpanjiang Basin.

Dielectric permittivity mixture models often assume simplified rock geometries, limiting their accuracy in rocks with complex pore structures. Systematically evaluating the influence of pore geometry, grain shape and grain size on model performance for water-saturation assessment is experimentally challenging and thus largely untested. Frequency-domain dielectric permittivity simulations, however, provide a means to effectively model these geometrical influences at the pore scale. Therefore, this paper aims to: (1) investigate the influence of grain geometry (size, shape and alignment) on dielectric permittivity using synthetic samples; and (2) evaluate the mixture model performance in assessing water saturation in synthetic and actual rocks. We performed frequency-domain simulations in the frequency range of 10 Hz–5 GHz. The dielectric permittivity dispersion significantly increased as grains flattened (i.e. the aspect ratio increased). The frequency-domain simulations conducted over the range of 10 MHz–5 GHz showed that grain size had a negligible impact on permittivity above 10 MHz. We observed that the relative permittivity in the z direction decreased with an increased aspect ratio of the grains. Simulations suggested that directional permittivity measurements can enhance grain-shape characterization. The unique contribution of this paper is the comprehensive quantification of the impacts of grain size, shape and alignment on the dielectric permittivity. Conducting such an investigation is challenging and almost impossible in the core-scale domain.

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.