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.

Due to the effects of sedimentation and diagenesis, the complexity and heterogeneity of carbonate ramp deposits pose significant challenges to 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 was 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 favorable reservoir distribution map revealing different stacking patterns of shoal bodies was generated. High-quality reservoir prediction was further achieved through the intersection of acoustic impedance (P-impedance) and gamma ray (GR) volumes derived from seismic waveform indicator inversion, which revealed the internal reservoir heterogeneity. 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.

Tight carbonate reservoirs exhibit more complex petrophysical parameters than conventional carbonate reservoirs, presenting unique challenges for characterization and hydrocarbon exploration. One crucial aspect of describing a tight carbonate reservoir is the accurate calculation of petrophysical properties (e.g. porosity and permeability) and rock characteristics. The proposed workflow has been implemented in the Ilam Formation, which is a tight carbonate reservoir. Applying an integrated methodology, including petrography, thin-section analysis, mercury injection capillary pressure (MICP), scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR), on reservoir rocks is a prerequisite to understanding the complexity of carbonate reservoirs, petrophysical properties and pore throat size distribution. As a result, combining the aforementioned parameters will reduce the amount of uncertainty associated with exploratory projects. Core measurements and the petrophysical rock typing (PRT) method were used to determine permeability, porosity and capillary pressure curves. Based on the PRT method, four rock types were determined when considering the geological attributes. The pore size distribution curves obtained from the NMR model show that NMR could be applied as a useful technique for estimating pore size distribution and correspond with the results from the MICP method, which reinforces the importance of integrating NMR–MICP to improve carbonate pore facies estimates. Moreover, the results of this study showed that the NMR log data, when calibrated with MICP, core data analysis, thin-section petrography and SEM images, can help to characterize the tight carbonate reservoir more accurately and reduce uncertainty in the reservoir rock typing.

Heterogeneity is an intrinsic property of shale reservoirs that exhibit long-standing puzzles that are difficult to optimize the hydraulic fracturing design and may render suboptimal performance. At present, the selection of a single influencing factor is not appropriate due to bias and upscaling problems. In this study, the multiple influencing factors were first selected from geophysical logging data to establish a structural hierarchy model. The heterogeneity index of single parameters was then obtained from the relationships between the intrinsic mode function (IMF) number decomposed by the empirical mode decomposition technique (EMDT) and its average wavenumber. In addition, the weighting coefficient of multiple influencing factors was determined based on the analytical hierarchy process (AHP). Finally, the composite heterogeneity index of the multi-stage process was calculated and combined with the weighting coefficient of multiple influencing factors. A shale gas well was analysed using this new quantification method. The results indicate that the multi-stage composite heterogeneity index is in good agreement with the fracture pressure derived from hydraulic fracturing data, and better than that from the coefficient of variation (CV) and the Lorentz coefficient method. Therefore, a quantification method for integrating the multiple influencing factors is of significant importance in order to comprehensively evaluate the degree of heterogeneity within a shale reservoir.

The perception of shallow gas accumulations has changed from one of ‘drilling hazards’ to ‘potential resources’ over the last few years. The Paso Anomaly, identified on seismic at a depth of c . 550 m true vertical depth subsea (TVDss), is a high-amplitude soft reflector that exists in the shallow overburden of the Catcher Field Area in the Central North Sea. This anomaly has previously been avoided during drilling as it could host gas. Amplitude v. offset (AVO) analysis has been undertaken that suggests a class 3 response, inferring that the anomaly is likely to be indicative of a gas-filled sand. Seismic indicators of gas presence, gas migration and potential migration pathways have been evaluated, and gas composition was analysed with reference to formation evaluation and gas ratio logs. This led to the interpretation that the Paso Anomaly represents biogenically altered thermogenic gas. It is further interpreted that the gas has migrated from depth due to faulting associated with Zechstein-aged salt diapirism, and subsequently has been biogenically altered once trapped at shallow depths. By utilizing facies-based seismic characterization, this work interprets the depositional environment of the anomalously high reservoirs as glaciogenic. Regional mapping supports an approximate Lower Pleistocene age for the deposits, which consists of two units; a Lower Unit that includes mega-scale glacial lineations, De Geer moraines and an esker; and an Upper Unit that comprises a sandur plain. Construction of a regional palaeogeographical model demonstrates that these deposits are the depositional record of an ice stream on the eastern edge of the British and Irish Ice Sheet. This ice stream advanced in a northeasterly direction into the Central North Sea before retreating, which has implications for the direction of Early Pleistocene ice flow within this area. This work lays the foundations for the Paso shallow gas accumulation to be viewed as a possible energy resource rather than a shallow gas drilling hazard, with a region of the sandur plain interpreted to be a potentially developable resource.

This study investigates the impact of basal anhydrite variability in the lower salt section of the Santos Basin, in Brazil, through seismic modelling of geological scenarios. Using 2D full-wave equation modelling, we simulated various geological configurations based on well data to evaluate the effects of vertical and lateral resolution, fault displacement, overburden influence, and basal anhydrite slope on seismic imaging. The results demonstrate that typical thin basal anhydrite layers – such as those with a thickness of c . 10 m – fall below the limits of vertical seismic resolution. Similarly, other configurations of anhydrite within the basal 50 m of the salt package are not reliably resolved, potentially leading to misinterpretation of the reservoir top. However, integrated analysis of seismic thickness and amplitude has proven effective in reducing interpretational discrepancies and enhancing reservoir characterization. The findings underscore the significant influence of overburden and lateral heterogeneities on seismic responses, reinforcing the need to incorporate detailed geological elements in seismic modelling. This approach contributes to reducing uncertainty in reservoir assessment and supports more effective well placement and drilling decisions in pre-salt exploration.

Formation damage poses significant challenges in numerous carbonate oil and gas fields, often impeding hydrocarbon recovery. A widely adopted solution to mitigate these issues is the application of acid treatment, specifically matrix acidizing, which enhances permeability and repairs formation damage in carbonate reservoirs. Understanding the influence of fractures on fluid flow behaviour in naturally fractured carbonate reservoirs is both a critical and complex endeavour. Previous studies have inadequately characterized the mechanisms and effects of fractures on acidizing processes. This study introduces a novel model to quantitatively and qualitatively assess the impact of individual fractures under varying injection rates, as well as the influence of key fracture parameters on acidizing efficiency. The proposed model integrates a two-scale approach with a pseudo-fracture methodology to simulate acidizing in fractured carbonate media. Fluid transport equations were resolved at the Darcy scale and coupled with structural relationships at the pore scale. The findings demonstrate the distinct effects of horizontal and vertical fractures on dissolution patterns compared to fracture-free media. Specifically, the presence of a horizontal fracture reduces the pore volume to breakthrough (PV bt ) by 35% relative to homogeneous conditions, and also promotes the range of optimal injection rates rather than pinpointing a single rate. Conversely, a vertical fracture increases the PV bt by 18%, disperses acidic fluid and diminishes the dominant wormhole length. Adjustments to fracture parameters, such as reducing fracture permeability or increasing the distance from the wellbore, further influences the PV bt . Notably, extending the length and narrowing the aperture of horizontal fractures accelerates acidic fluid transfer, thereby reducing the dominant wormhole diameter. This study concludes that horizontal fractures generally facilitate the achievement of optimal acidizing conditions more rapidly. These findings provide the first comprehensive and quantitative analysis of the effects of critical fracture parameters on acidizing efficiency in fractured carbonate reservoirs, offering valuable insights for optimizing stimulation strategies in such complex formations.

To enhance the oil recovery of the Ha-34 fault block reservoir in the A'nan depression of the Erlian Basin (a low-permeability heavy oil reservoir), a novel composite nano-oil-displacing agent (CNODA) was formulated, several indoor experiments (stability, wettability, interfacial tension, emulsion state, oxygen-17 nuclear magnetic resonance (¹⁷O NMR), dynamic light scattering, zeta ( ζ ) potential and core flooding) were performed and outdoor well group flooding projects were conducted. The following results were obtained: (1) visual observations (no precipitation) and a higher ζ potential (>±30 mV) demonstrated the exceptional stability of the nanofluid system; (2) the CNODA increased the contact angle of the oil droplets on the glutenite surface from 29.3° to 151.1°; (3) the CNODA had a solid capacity to reduce the oil–water interfacial tension (IFT) (0.065 mN m −1 , ultralow IFT) and could let the oil pass through the capillary throats; (4) the CNODA increased the sweep efficiency of the reservoir and decreased the mobility ratio of the injection fluid to the formation fluid; (5) the SiO 2 nanoparticles dispersed in the fluid, weakened the hydrogen bonds and formed small water clusters, which is the essence of oil-displacement agents entering low porosity; (6) the CNODA could detach the oil droplets from rock surfaces through structural disjoining pressure; and (7) outdoor two-well and five-well group flooding projects increased oil production by 1269.55 t (enhanced oil recovery (EOR) of 59.1%) and 3376.22 t (EOR of 53.3%), respectively. In other words, the CNODA could peel off the oil droplets in the Ha-34 fault block reservoir by creating stronger oil‒rock (water) interactions, a higher sweep coefficient, a reduced pore throat limit for oil-displacement agents to enter and a greater structural disjoining pressure.

Carbonate mudrocks contain substantial reserves of organic matter, but their exploitation is hindered by the complexities of their pore networks. This study explores and models the heterogeneity of pore structures in immature, organic-rich carbonate source rocks. To achieve this, we employed digital rock analysis and nuclear magnetic resonance (NMR) techniques to gain a deeper understanding of the pore structures and their spatial distribution. Representative samples were collected carefully from a vertically cored well drilled through the Upper Cretaceous source-rock succession in central Jordan. Results show that the studied interval is divided into six distinct microfacies: one in the top unit of the Al-Hisa Phosphorite (AHP) Formation, and five within the overlying Muwaqqar Chalk Marl (MCM) Formation. Each microfacies displays unique porosity and kerogen content characteristics, with higher total organic carbon (TOC) values within the MCM Formation (18 wt% on average) compared with the samples collected from the AHP Formation (TOC of 4.34 wt%). NMR analysis revealed a trend where the formations shifted vertically from mud-dominated microfacies of lower porosity and lower pore sizes in the middle of the MCM Formation, to a transitional zone at the base of the MCM Formation and then to grain-dominated microfacies of higher porosity and pore sizes in the AHP Formation. Micro-computed tomography (micro-CT) imaging provided a deeper insight into the structure and distribution of pore/kerogen bodies in the MCM Formation. The findings emphasize the significant variations in the porosity and kerogen distribution across the different microfacies, highlighting the impact of both the depositional environment and diagenetic changes on the pore structures.

Available data and interpretations (gravity grids, line-drawing interpretations on published 2D seismic examples, elaborated published geological transects, and well-log data and information) have been used to assess the tectonostratigraphic evolution of the Ogaden Basin in Ethiopia, and to account for prospective exploration plays and imposed implications on the petroleum system. The gravity data used delineate the extent of the basin. Four main upper Paleozoic–lower Mesozoic reservoirs (Calub, Gumburo, Adigrat and Hamanlei formations) can be recognized through petrophysical analysis; and porosity and sonic velocity burial trends reveal aspects of the missing overburden at the present time. A type profile was utilized for 2D structural restoration, and two main phases of extension at 247 Ma (early Triassic) and 206 Ma (late Triassic) were denoted. The estimated crustal beta/stretching factor and the horizontal extension percentage along the modelled profile were both found to be moderately low, and depth-dependent stretching has been invoked to account for these observations. Decompaction analysis and restoration of the individual stratigraphic units showed an increase in their thickness. This is due to them experiencing a greater overburden load that was later removed (1.8–2 km late Cenozoic erosion), resulting in the current presence of a deeper stratigraphy at shallower burial depths. Spatial and temporal depositional models have been constructed and account for the exploration plays. The estimates of obtained Cenozoic erosion obtained have concrete implications for the petroleum system in the prospectivity of the defined exploration plays that impact the source-rock maturity, migration/charging, and the effectiveness of the reservoir and seal.