Petroleum Geoscience - Volume 31, Issue 4, 2025

Low-velocity non-linear 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 non-linear flow for vertical fractured wells (VFW) is necessary. In this paper, a new interference well-test model is proposed to study the transient pressure behaviour of a VFW surrounded by multiple adjacent injection wells. The fluid in the matrix system moves in the form of a non-linear 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 non-linear flow exhibits 20–30% slower pressure propagation and 15–25% lower bottomhole pressure (BHP) during unsteady flow compared with Darcy flow. In steady-state flow, it generates low-pressure zones that are 30–50% broader and requires up to 3.1 MPa greater pressure drops. Typical curves identify four distinct flow regimes (wellbore storage, fracture flow, pore flow and interference flow), with non-linear flow elevating pressure derivatives by 30% in the pore flow and interference stages. Sensitivity analyses demonstrate that increasing the fracture half-length (0–90 m) or fracture count (one–four) reduces the BHP by 15–25%. Higher production rates (4–10 m3/day) 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 non-linear 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.

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.

Owing to the effects of sedimentation and diagenesis, the complexity and heterogeneity of carbonate ramp deposits pose significant challenges to the seismic prediction of high-quality reservoirs. Conventional seismic prediction workflows for carbonate reservoirs typically rely on horizon flattening, seismic coherent bodies and seismic attributes to delineate geological boundaries, complemented by seismic inversion to convert seismic data into petrophysical properties. However, the low vertical resolution of seismic data has hindered studies on the stacking patterns of shoal bodies and corresponding variations in reservoir quality. In this study, an architecture analysis-based seismic prediction workflow is proposed for carbonate ramp shoal reservoirs in the Upper Cretaceous Hartha Formation of the M Oilfield (Mesopotamia Basin). It integrates reservoir architecture analysis with seismic waveform characteristics, aiming to overcome the limitations of low-resolution seismic data under geological constraints. Specifically, we adapted the architecture analysis method originally developed for fluvial sedimentary systems to carbonate ramp shoal reservoir prediction and identified three ramp shoal facies associations at the fifth-level architecture. Their corresponding seismic waveform features were determined by integrating seismic forward modelling. Subsequently, a favourable reservoir distribution map revealing different shoal-body stacking patterns was generated. High-quality reservoir prediction was further achieved through the intersection of acoustic impedance (P-impedance) and gamma-ray volumes derived from seismic waveform indicator inversion, which revealed the internal reservoir heterogeneity. A total of 90.2% of log-interpreted high-quality reservoirs with thicknesses below the seismic resolution limit were successfully predicted. The research results have been verified by the production performance of development wells, demonstrating their effectiveness in reducing uncertainties associated with reservoir heterogeneity. This study provides a replicable geology–seismic integration workflow for the efficient development of similar carbonate ramp shoal reservoirs.

The Oligo-Miocene Asmari Formation is the most important reservoir unit in onshore SW Iran. It is more than 500 m thick in the central Zagros fold-and-thrust belt, decreasing in thickness southwards towards the offshore to less than 200 m in oil fields to the SE and NW of the Persian Gulf, and it does not extend over the Qatar Arch in the central area. Despite its reduced thickness offshore, the formation serves as the primary reservoir unit in a number of important structurally trapped fields, producing natural gas to the SE and oil in the NW. The formation also has stratigraphic potential because of its lithological heterogeneity.

The Asmari succession in the Gavarzin gas field to the SE and the Abouzar oil field in the NW part of the Persian Gulf was cored, and the sedimentology and palaeontology of each section was recorded in detail.

The Gavarzin core section consisted of 160 m of limestones comprising 10 sedimentary facies, with Ruplian–Chattian index foraminifera. The lower half of the formation is dominated by coralgal limestones of Rupelian age, whereas the upper half comprises Chattian-aged foraminiferal limestones with interbedded shales and marls. Deposition is interpreted to have occurred on a carbonate ramp with coral and red algal patch reefs representing a proximal mid-ramp area. Two third-order sedimentary sequences were identified: the RuS (Rupelian) and the ChS-1 (early Chattian) sequences.

The Abouzar core section to the NW is 135 m thick and comprises three members: lower Asmari carbonates, Ghar Member sandstones and upper Asmari carbonates. The 90 m-thick Ghar Member is the main oil reservoir and is roughly twice the thickness of the two carbonate sections combined. The lower Asmari carbonates contain Chattian index foraminifera and, in the absence of Burdigalian microfossils, the Ghar Member and upper Asmari carbonates were assigned to the Aquitanian. The succession comprises eight microfacies and petrofacies, interpreted to have been deposited on a shallow-water carbonate ramp with a significant influx of clastics. Three third-order sequences have been defined of late Chattian (Ch-S sequence) and Aquitanian (AqS-1 and AqS-2 sequences) age.

The regional stratigraphy and depositional history of the Asmari was assessed by correlating the Gavarzin and Abouzar sequences with equivalent sequences in 10 additional fields, along two offshore transects to the SE (transect A) and NW (transect B). Seismic reflector profiles highlight a clinoforming sequence on the SE transect, prograding towards the Lengeh Trough during the Rupelian and early Chattian. This is onlapped by Fars salt. The salt unit is barren of microfossils but is probably Chattian and Aquitanian in age. The NW transect suggests that the Asmari Formation and Ghar Member sandstones were largely confined to the Binak Trough.

Thermal-compositional flow simulations are crucial for understanding the intricate interactions of subsurface heat and mass transfer for geoenergy development. A case in point is the steam-assisted gravity drainage (SAGD) process, 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 modelling 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 favours the users of closed-source commercial modelling 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 a strong potential for the practical application to large-scale SAGD operations.

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.

Sahabi ‘B’ Reef is one of several pinnacle reefs located in the southern part of the Ajdabiya Trough. The Sahabi ‘B’ Reef is ambiguous 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 differentiated 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.