This study evaluates the diagenetic characteristics of the Middle Marrat reservoir, a partially dolomitized carbonate with thin anhydrite layers and clay (Magwa Field, Kuwait). Six cored wells were described and facies identified. By integrating the new petrographic data with geochemical analyses (stable and clumped isotopes), XRD and 1D basin modeling, a diagenetic model is constructed showing the phases and timing of diagenesis and processes affecting reservoir quality. Our analyses suggest it underwent early marine, meteoric diagenesis and dissolution, developing secondary porosity. Burial compaction was accompanied by calcite cementation, dolomitization, and multiple phases of fracturing. Later dolomitizations included fracture-related Fe-rich dolomite precipitation. The late-stage Fe-rich calcite and dolomites precipitated from deeper-sourced hydrothermal fluids. Clumped isotope (CI) temperatures from matrix samples and calcite (vein) cements range from 45 to 130°C, which we interpret to have precipitated during three diagenetic phases. The first phase represents diagenesis during depositional and shallow burial (∼40-60°C), which is mostly seen in the micritic matrix samples. The second phase is related to compaction and moderate burial (80-100°C), mostly recorded by mesogenetic dolomites and calcite filling cements. The third phase, seen in calcite vein cements, is associated with deeper burial and upward migration of hydrothermal fluids along deep faults (∼100-130°C). Integrating CI data with basin modelling suggests that the main diagenetic phases occurred during the Lower Jurassic to mid-Upper Jurassic (phase 1), Lower Cretaceous (phase 2), and post-Cretaceous (phase 3).

The Termit Basin, a well-explored hydrocarbon-rich basin in West Africa, provides an excellent case study for investigating oil families, paleoenvironments and organic matter (OM) inputs in the Trans-Saharan epicontinental basins. This study examines nineteen newly discovered southeastern oils using gas chromatography, gas chromatography-mass spectrometry and stable carbon isotopic analysis. While three oil families (I, II and III) were previously identified in the basin based on discoveries made prior to 2020, this study identified, for the first time, family I oils in the far east of the basin, and first recognized two new families (IV and V) by chemometric analysis and correlations of fourteen biomarkers and carbon isotope compositions. Families I and IV show more terrigenous inputs than family V. Our results do not support previous work suggesting that family I was derived from algal-dominated OM. Compared with family I, a contribution of marine sources was defined for family IV, although terrigenous inputs remained significant. Family V originated from source rocks with more inputs of marine OM. Family V is divided into subfamilies V1 and V2, of which subfamily V2 is distinguished by greater algal inputs under more reducing conditions. The identification of family V proved the presence of a new petroleum system related to marine algal-rich source rocks in the Termit Basin. Our results suggest significant terrigenous OM influx and extensive marine algae blooms in the Trans-Saharan epicontinental seas during the Late Cretaceous, coinciding with sea-level changes.

Secondary migration is poorly understood and the generally favoured transport mechanisms fail to explain many of its apparent characteristics. Here, building on work originally developed in the1940's, I resurrect an old hypothesis of migration as a colloidal dispersion, but in more detail than hitherto. This contribution expands on this hypothesis of migration with a focus on its theoretical mechanisms limitations, and advantages. The aim is to develop a self-consistent model to demonstrate how this transport mechanism might work. A better understanding of secondary migration of petroleum has implications for conventional and unconventional plays, and for reservoir diagenesis.

The hypothetical model for colloidal secondary migration, presented in the previous paper, is tested here with numerical models to examine its viability and to determine the conditions under which it becomes ineffective. The main assumptions are that petroleum migrates as a Pickering emulsion of individual nanodroplets (a few tens of nanometers in size) and groups or ‘flocs’ of nanodroplets. These are nanodroplets are protected from coalescence by coatings of silica, asphaltenes and clay fines. Migration is achieved by diffusion (Brownian motion) of the nanodroplets, and advection of the flocs, working together cooperatively. The cases tested here with numerical models are: 1. Oil migration into an anticlinal structure (e.g., Ghawar Anticline, KSA) 2. Gas migration into an anticlinal structure (e.g., Ghasha Anticline, UAE) 3. Migration within a tight gas sandstone in a foreland basin (e.g. Niobrara gas field, Rock Island gas field, USA) 4. Migration within a tight oil sandstone in a foreland basin and its effects on a tight [shale] gas reservoir (e.g., Powder River Basin, USA) 5. Migration of heavy oil in a foreland basin (e.g., Western Canada Sedimentary Basin) 6. The role of colloidal migration in reservoir diagenesis The main implications of the model in these situations are: (1)&(2) Colloidal migration is highly efficient in the conventional oil and gas windows and is generally orders of magnitude faster than Darcy migration. (3) The mechanism breaks down rather abruptly in good carrier beds in the gas window, typically at a pore-throat size of around one µm. It provides a satisfactory explanation for the filling of unconventional tight gas sandstones and their low water saturations. (4) With less good quality carrier beds, the mechanism breaks down in the late oil window, leading to tight oil carrier bed plays. (5) The colloidal mechanism can migrate heavy oils relatively fast and easily, compared with Darcy flow, because the main resistance is the viscosity of the pore water rather than that of the petroleum. (6) Migrating Pickering emulsions provide an effective means of transporting inorganic matter long distances into traps. This has strong implications for reservoir diagenesis. For example, the mechanism can account for the observed trends of quartz cementation in petroleum traps and the timing of petroleum fluid inclusions in quartz overgrowth cements. If this hypothesis is substantiated by direct observation of the proposed petroleum nanodroplets, many traditional concepts of petroleum systems will have to be revised.

This study presents a comprehensive reservoir geomechanical characterization of the Middle Jurassic Lower Safa sandstones from the Shushan Basin, Egypt. Petrographical thin sections, SEM, XRD, routine core analysis, wireline logs, downhole measurements and drilling data were integrated to characterize the studied reservoirs. The reservoir is composed of mesoporous quartz arenites with dominantly primary intergranular porosity, and exhibits an isotropic pore system with 7–14% effective porosity and ≤1 mD permeability. Cementation (silica and clay) and mechanical compaction were identified as the primary diagenetic factors reducing the reservoir quality. The reservoir exhibits a low shale volume, high hydrocarbon saturation and a hydrostatic pore pressure gradient. The relative gradients of in situ stresses indicate a normal to strike-slip faulting stress regime. Based on the ‘C-quality’ breakouts from multi-arm caliper log analysis, the maximum horizontal stress azimuth is interpreted as N140°E. Utilizing the stress-based model, the risks of wellbore instability, depletion-induced reservoir instability and sand production were assessed. The assessment indicated the possibility of production-induced shear failure at a depleted pore pressure magnitude of 1000 psi, which can be considered the abandonment pressure. The hydraulic fracturing simulation confirmed the presence of a stress barrier that would restrict the vertical propagation of fractures into the overburden/underburden during stimulation. The horizontal wells drilled along a NE–SW azimuth offer higher sand-free critical drawdown and therefore this is considered the preferred lateral azimuth to minimize sand production risk. The sensitivity of collapse pressure, fracture initiation pressure and sand-free critical drawdown pressure was assessed for various wellbore trajectories, rock-mechanical property and depletion magnitudes.

Biased forecasts lead to biased decisions. An essential pre-drill input in petroleum exploration is the geological probability of success (PoS). If the PoS is biased and lacks accuracy and reliability, the result is value erosion. We used the Brier score, skill score, bias and attribute diagram to assess the quality of PoS forecasts for prospects on the Norwegian Continental Shelf (NCS) from 1990 to 2022. Pre-drill and post-drill information about the prospects have been reported to the Norwegian Offshore Directory. As the reported PoS was obtained by multiplying the probability of source, reservoir and trap, verification measures were also applied to these three factors. Overall, NCS forecasts tend to exhibit pessimism and overconfidence, with some improvement in bias over time. The trap forecasts consistently exhibit a negative skill score over time, indicating a performance no better than the standard reference class. Furthermore, PoS forecasts are not reliable. Biased forecasts indicate that forecasters need to revise their judgements, while negative skill scores imply that a forecast may not add value. Poor reliability indicates that prospects estimated to have a high PoS may not be successful, and vice versa. These shortcomings can lead explorers to prioritize non-viable prospects while missing the more promising ones.

Thermal-compositional flow simulations are crucial for understanding the intricate interactions of subsurface heat and mass transfer for geo-energy development. A case in point is the Steam-Assisted Gravity Drainage (SAGD) processes, where accurate numerical simulation is essential to evaluate its efficiency and ensure environmentally sustainable oil development. However, representing the complex heat and mass transfer in SAGD requires fine-scale grids, leading to exceptionally high computational costs. To address this challenge, this study introduces a novel upscaling technique that enables efficient SAGD modeling with larger grid sizes while maintaining simulation accuracy. The proposed upscaling method employs scale factors, defined as the ratio of the coarse-scale grid sizes to the fine-scale grid sizes, to adjust the oil viscosity-temperature relationships in coarse-scale models. This method saves the need to modify the underlying source code of simulators, and thus favors the users of closed-source commercial modeling software, enabling more efficient and cost-effective field-scale SAGD simulations. The method is validated on the SAGD models of different dimensions, grid-block and overall model sizes and oil viscosity-temperature relationships. The results show that the upscaling method speeds up the fine-scale simulations to 3.6 and 7887 times faster for 1D and 2D SAGD models, respectively, while preserving reasonable accuracy compared to fine-scale results. The method's robust performance suggests strong potential for practical application to large-scale SAGD operations.

This study investigates the sedimentology and ichnology of the Asmari Formation's mixed siliciclastic-carbonate unit in Shadegan oilfield, southwestern Iran. The Asmari Basin evolved significantly due to siliciclastic influx, climatic and sea-level fluctuations, and tectonic movements. It transitioned from unmixed carbonate-dominated ramp to siliciclastic-dominated delta system, then to mixed siliciclastic-carbonate shoreface-offshore complex, and finally to mixed carbonate-siliciclastic ramp with a barrier island-lagoon complex. This evolution highlights the dynamic nature of the environment, illustrating the transition from an unmixed carbonate ramp to a siliciclastic-dominated system, and mixed unit with both coeval and reciprocal sedimentation of siliciclastic and carbonate components. The recorded sedimentological heterogeneity, characterized by a variety of sediment types in the Asmari Formation's mixed deposits, has resulted in high ecological diversity and ichnological complexity shown by nine distinct ichnofabrics. This connection underscores the intricate interplay between sedimentological heterogeneity and ichnological complexity. The highest bioturbation and ichnodiversity is observed in the wave-dominated shoreface-offshore complex and middle ramp facies. The abundance of domiciles of suspension- and detritus-feeding polychaetes, suspension- and deposit-feeder bivalves, decapod crustaceans, and scavenging organisms with sophisticated feeding strategies and stable/mature populations indicates that the tracemakers in marine ichnofabrics were balanced with their environment. In contrast, the freshwater-influenced ecosystems, including the tidal flat and back barrier facies of the barrier-island complex and deltaic system, are dominated by opportunistic euryhaline species that thrive in varying environmental conditions. Ichnological insights from this study enhance our understanding of depositional conditions and reservoir quality of the Asmari Formation and its equivalents in neighboring regions.

Low-velocity nonlinear flow is the basic form of fluid movement in low-permeability reservoirs; however, most of the current well-test methodologies are developed based on Darcy's flow, which leads to inaccurate interpretation results. In addition, water injection development and hydraulic fracturing technology are considered the most effective methods for the development of low-permeability reservoirs, whereas the traditional single well testing model ignores the interference effect of adjacent wells on observation wells, leading to a deviation between the interpretation results and actual reservoir properties. Therefore, research on interference well testing models based on nonlinear flow for vertical fractured wells (VFW) is necessary. In this paper, a new interference well-test model is proposed to study the transient pressure behavior of a VFW surrounded by multiple adjacent injection wells. The fluid in the matrix system moves in the form of a nonlinear flow, but it conforms to Darcy's flow in the fracture system. Hydraulic fractures are unique channels wherein fluid flows from the matrix system into the wellbore. The simulation results reveal that nonlinear flow exhibits 20–30% slower pressure propagation and 15–25% lower bottomhole pressure (BHP) during unsteady flow compared to Darcy flow. In steady-state flow, it generates 30–50% broader low-pressure zones and requires up to 3.1 MPa greater pressure drops. Typical curves identify four distinct flow regimes (wellbore storage, fracture flow, pore flow, interference flow), with nonlinear flow elevating pressure derivatives by 30% in pore-flow and interference stages. Sensitivity analyses demonstrate that increasing fracture half-length (0–90 m) or fracture count (1–4) reduces BHP by 15–25%. Higher production rates (4–10 m³/d) intensify drawdown and suppress interference effects. Expanding well spacing (150–300 m) delays interference onset by 40% and halves its amplitude. These findings demonstrate that neglecting nonlinear effects in low-permeability reservoirs systematically underestimates permeability and overpredicts energy replenishment efficiency. For practical applications, the model advocates optimizing fracture parameters and production strategies to achieve rational field development.

Sahabi ‘B’ Reef is one of several pinnacle reefs located in the southern part of the Ajdabiya Trough. The Sahabi 'B' Reef is vague for several reasons: only four wells have penetrated the reef, resulting in limited subsurface information; two wells were abandoned as dry wells, while the other two have produced from different oil pay zones, indicating strong lateral facies variation in and around the reef. Utilizing seismic and well data, the distinct depositional architecture of the carbonate Late Paleocene successions and their potential as petroleum reservoirs are examined. The study aims to explain why some wells in the Sahabi ‘B’ Reef complex are producing while others are not, and to identify facies changes that facilitate an understanding of their evolution over geological time. Four developments of the lithofacies in the Upper Sabil Carbonate have been distinguished from bottom to top: (1) open shallow marine packstone/grainstone, (2) bioclastic grainstone/packstone with tidal effect, (3) coral floatstone/boundstone, and (4) bio-lithoclastic talus. The Sahabi "B" Reef consists of two reefs (older and younger parts). During the Middle Eocene, the area generally dipped towards the location of the younger reef. A tilt is attributed to bending rather than faulting, causing minor saddles and humps between these two reefs. This could plausibly explain the presence of oil accumulation in the younger part of the Sahabi 'B' reef, while its absence is noted in the older part. The reef complex is seismically divided into major lateral facies, which vary in terms of deposition and age; these include: (1) older reef, (2) shoal, (3) younger reef, and (4) talus. During the Paleocene, Upper Sabil carbonates exhibited an aggrading build-up that kept pace with relative sea-level rise, marking the first Sahabi 'B' Reef formation. Subsidence and relative sea-level rise resulted in the backstepping of the second Sahabi 'B' Reef within the pre-existing topography. By the end of the Paleocene, this stage marks the conclusion of the Sahabi 'B' Reef complex, when the reef was drowned due to rapid sea-level rise, leading to a basin dominated by shale deposition.