In this review, we propose a hypothesis to explain the contrasting petroleum exploration success rates of four structural domains within the Eastern Cordillera and eastern foothills plays of Colombia. Recently published case studies suggest that the observation regarding the central eastern foothills plays (Nunchia syncline) being the most prolific trend, is not related to exploration well density. Instead, it is a function of the Nunchia syncline having the most complete Neogene depositional record which resulted in an almost continuous overburden during deformation. The result is that the producing structures in the southern segment of the Nunchía syncline and the similar, yet unexplored trend in the northern segment of the Nunchia syncline are associated with pods of active source rocks in the backlimbs of those structures. In contrast, the early (Late Paleogene) maturation due to thicker Paleogene overburden caused most of the hydrocarbon generation in the Axial Zone of the Eastern Cordillera to occur before the Late Oligocene-Early Miocene formation of the structures. Nevertheless, further petroleum systems modelling may help identify areas where pods of active source rocks could exist adjacent to major structures. In all scenarios, the remaining prospectivity of the Axial Zone of the Eastern Cordillera is much lower than in the northern segment of the Nunchia syncline. Finally, the presence of thick overburden and even the potential seismic expression of the trap, are not sufficient to reduce uncertainties regarding future discoveries. We document a case study where a sub-thrust pull-up led to failure of a prospect . After years of exploration, we consider that all successful discoveries in the foothills of the Eastern Cordillera are related to the surface expression of the deeper subsurface structural traps.

Thinly bedded reservoirs are hard to characterize due to heterogeneity and subtle lithological changes that hinder the identification of productive zones. To overcome these challenges, this study integrates seismic data, well logs, core samples and sedimentology to achieve precise reservoir characterization. Structural interpretation revealed a complex graben system bounded by major listric normal faults trending predominantly NW–SE and WNW–ESE. These faults dip to the NE and SW, creating a series of horsts and graben that control sediment deposition and compartmentalizing the reservoir. The analysis identified four distinct lithofacies associations within the Abu Roash ‘G’ (ARG) reservoir, which are key to understanding the reservoir's heterogeneity and potential for hydrocarbon accumulation: bioturbated mudstones, lenticular-bedded siltstone, flaser-bedded sandstone and massive sandstone. The sandstones, deposited in tidal mixed flat or channel environments, represent the primary hydrocarbon-bearing units, while the siltstone and mudstone facies reflect a tidal-dominated shoreline environment. Petrophysical evaluation identified key reservoir zones in oilfields such as Gharibon and Sohba, with oil-bearing intervals ranging from 2 to 9 ft. Despite their thin nature, these zones exhibit excellent reservoir properties, including low shale volume (<15%), high porosity (15–22%) and high hydrocarbon saturation (40–70%). The reservoir is classified into four types (1–4). Types 1 and 2, which comprise massive faintly laminated and flaser-bedded sandstones, demonstrate a superior reservoir quality, with average permeability values of 7.1 and 3.5 mD, porosity of 20.25 and 16%, and oil saturation of 15.8 and 15.3%, respectively. Conversely, Type 3 (siltstones) is considered to consist of fair-quality reservoirs, while Type 4 (mudstones) consists of non-reservoir facies. Data integration boosts recovery development in thinly bedded formations like ARG, with global relevance.

The Sequoia Pliocene channel reservoirs within the West Delta Deep Marine (WDDM) concession, located offshore of the Nile Delta, pose significant challenges due to their complex stratigraphy and variable reservoir properties. This study employs an integrated approach, combining seismic data interpretation with comprehensive petrophysical analysis, to characterize these reservoirs and assess their hydrocarbon potential. Seismic data interpretation revealed a complex depositional environment, characterized by an upward-fining sequence of sandstones and mudstones. High seismic amplitudes were associated with gas sands, while lower amplitudes indicated background shale. The seismic stratigraphy indicates that the Sequoia channel system evolved from an initial high-energy erosional phase to a more subdued depositional environment, leading to significant heterogeneity in the reservoir quality. Petrophysical analysis demonstrated that effective porosity values within the reservoir range from 18 to 30%, with water-saturation levels of between 38 and 68%, reflecting the variability in reservoir properties across different zones. The calculated gas initially in place (GIIP) for the Sequoia channel ranges from 724.1 to 4158.71 Bcf, highlighting the substantial hydrocarbon potential within this complex system. This study underscores the importance of integrating seismic and petrophysical data to develop a comprehensive understanding of the Sequoia channel reservoirs. The results provide a robust framework for optimizing field development strategies, which is crucial for maximizing hydrocarbon recovery. The findings also offer valuable insights into the geological complexities of the WDDM concession, serving as a reference for future exploration and production efforts in similar deep-water environments.

The Middle and Upper Permian is an important succession in the Arabian Peninsula due to its economic value, with it containing oilfields, the supergiant Khuff gas reservoir and new carbon dioxide storage opportunities. Until now this succession has had no public domain palynostratigraphic scheme. The Oman and Saudi Arabia Palynological Zonation (OSPZ) scheme for the Cisuralian and Guadalupian was established in 2003 but its six zones terminated within the Guadalupian because in central and southern Arabia the succession above is carbonate-dominated with poor palynomorph preservation. The Lopingian clastic-dominated succession of the Levant now provides further palynostratigraphic information to allow a tentative interval palynozonation. Thus, the base of the new OSPZ7 interval biozone is defined at the first appearance datum (FAD) of Protohaploxypinus uttingii ; the base of OSPZ8 by the FAD of Falcisporites stabilis ; and OSPZ9 by the FAD of Pretricolpipollenites bharadwajii . Foraminiferal dates from the marine parts of the Saad, Arqov and Sheizaf formations in boreholes in Israel allow tentative ages to be suggested: OSPZ8 mid-Wuchiapingian and OSPZ9 late Wuchiapingian–Changhsingian. Correlation with Australian, South American and Chinese successions broadly supports these ages. Marine units in Jordan contain foraminifera and conodonts that give an upper age limit of early Induan for OSPZ9.

The Junggar Basin, a major hydrocarbon province in China, contains more than 3 Bt of petroleum and 150 Bcm of natural gas. Within its Central Depression, the Shixi–Mobei Uplift is a key area for oil and gas exploration. This study examines the geological and depositional characteristics of the Sangonghe Formation using cores, microscopy, mineral analysis and seismic profiles. The Sangonghe Formation represents the peak of lacustrine transgression, transitioning to regression in the overlying Xishanyao and Toutunhe formations. It features diverse sedimentary facies, including braided river deltas and lacustrine fans, reflecting a progression from shallow- to deep-lake environments. Palaeogeomorphology, controlled by secondary structural slope-break zones, influenced facies distribution, with braided river deltas above and delta front/lacustrine fans below these zones. Provenance analysis has identified two main sediment sources: a northwestern source affecting the Shixi region's west and north, and a northeastern source impacting the Mobei region's east and NE. Reservoirs are characterized by residual, secondary and primary intergranular pores, with porosity positively correlated with permeability. The diagenetic stage of mesogenetic A2–B is observed, particularly in the Mobei region's east and SE. 2D seismic profiles and well-logging data estimate the areal extent of the lacustrine-fan reservoirs at 25–30 km 2 , with a gross rock volume of 15–20 km 3 and hydrocarbon volumes of 50–100 MMbbl of oil equivalent. Exploration should focus on areas near wells QS and M171 with significant potential identified around wells QS1, QS404, QS403, QS204, QS9, M14, M20, M27, F003 and M171 as priority targets.

Due to the variability in depositional cycles and the active nature of the constituent minerals, carbonate rocks are commonly strongly modified by diagenetic processes that alter their original rock fabric and petrophysical properties. Conventional petrophysical models do not reliably assess these complexities, requiring extensive calibration efforts or pore-scale image analysis. We introduce a calibration-free method that enables the assessment of pore-network properties such as constriction factor, pore-body and pore-throat size distributions, as well as permeability and capillary pressure based on joint interpretation of nuclear magnetic resonance (NMR) transverse relaxation time ( T 2 ) distribution and electrical conductivity measurements. We successfully applied the introduced method to pre-salt carbonates of the Barra Velha Formation in the Santos Basin of Brazil. The applications of the introduced method for assessing throat-size distribution in the core- and the well-log-scale domains have proven successful in 87 and 73% of the cases, respectively. The permeability estimates from the new method showed more than 42% improvement when compared against those obtained from NMR-based permeability assessment methods. The new method provides real-time and depth-by-depth assessments of the pore-throat size distribution and capillary pressure, minimizing the need for core-based calibration efforts and eliminating the need for detecting cutoff values in NMR-based permeability models.

The Rovuma Basin, once overlooked for oil and gas exploration, emerged from 2020 as one of the world's most prolific hydrocarbon provinces following the discovery of c . 200 trillion cubic feet (Tcf) of gas in 5 years. Among the most significant discoveries were the supergiant Mamba Field and the giant Coral Field, discovered in 2011–12 by a joint venture led by Eni. Eni was one of the few companies to initiate exploration in the Rovuma Basin in 2006, when the area was regarded as non-attractive. The Mamba and Coral prospects were initially identified in 2009 using 2D seismic data and were subsequently confirmed in 2010 using 3D seismic imaging. These discoveries are in structural–stratigraphic traps supported by direct hydrocarbon indicators (DHIs). Drilling revealed the presence of multiple high-permeability Paleogene sandstones gas pools, with six of these exceeding the 500 million barrels of oil equivalent (MMboe) threshold, classifying them as giants. Several of the Mamba Field reservoirs extend into the adjacent Area 1, where exploration has been conducted by an Anadarko-led joint venture. Both fields exhibit exceptional reservoir quality, with reservoir units exceeding 100 m in gross thickness and with extremely high net-to-gross ratios (up to 80–90%). The superior reservoir quality is attributed to the synchronous interaction of turbidite gravity flows and sea-bottom currents, which have redistributed finer sediments and concentrated thick, clean sandstone deposits along the system's depositional axes. The Coral project represents the first gas production from the Rovuma Basin's deep-water discoveries. Production commenced in November 2022 via the Coral Sul, a floating liquefied natural gas (FLNG) system.

The Lajas Formation (Middle Jurassic) of the Neuquén Basin in Argentina is a renowned unconventional tight gas sandstone reservoir. It has been studied widely from multidiscipline approaches; however, only a few petrophysical studies have been published. The objective of this study is to examine correlations between various porosity measurements obtained through petrographic optical and scanning electron microscopy (SEM), combined with quantitative X-ray diffraction (XRD) mineralogy, and petrophysical laboratory measurements, including nuclear magnetic resonance (NMR at 2 MHz) and gas-filled porosity (GFP). The analysed samples cover a wide compositional spectrum ranging from lithic feldsarenites to feldspathic litharenites, the clay fraction is dominated by chlorite or mixed illite/smectite (I/S) with less than 20% of expandable layers (I/S), and the total porosity ranges from 5 to 13%. Intercrystalline pores, which are associated with clay minerals, are a key component controlling the pore system of the unit. SEM images and a strong correlation between XRD data and the clay-bound water derived from NMR T 1 – T 2 maps are clear evidence of this. The analysed reservoir shows a high variability and complexity in the pore structure related to other textural pores (e.g. non-clay intergranular and intragranular pores), thus reflecting the importance of multidisciplinary and multiscale studies that aim to understand the heterogeneous porosity network of tight sandstone reservoirs.

Quantitative characterization of the heterogeneity of shale nanopores and its influencing factors have a significant impact on the occurrence quantity, pore size and mobility of shale oil. Twenty-five Chang 7 shale samples were analysed for their geochemical properties and mineral composition, along with field emission scanning electron microscopy and nuclear magnetic resonance. Combined with multifractal theory, the heterogeneity characteristics and influencing factors of the shale pore structure were studied, and a reservoir classification was carried out. The results show that the pore types include microfracture, intercrystalline pores, intergranular pores, intragranular dissolved pores and organic matter shrinkage pores. The pore size distribution of shale samples was divided into four groups according to the geometric mean value of T 2 spectrum ( T 2,gm ) and T 2 value corresponding to 50% of the cumulative curve of T 2 relaxation time ( T 2, 50 ), in which the pore-scale composition gradually transitions to micropores (<100 nm), while the heterogeneity gradually diminishes. The total organic carbon (TOC), clay matrix and pyrite content were positively correlated with multifractal parameters, while the maximum pyrolysis yield temperature ( T max ) and content of quartz, feldspar and carbonate content show opposite trends. The T 2 spectrum parameter T 2,gm and multifractal parameters Δ α and D 1 / D 2 can effectively classify shale oil reservoir quality. This study provides insights into and reference for the characterization of pore heterogeneity and the classification of shale oil reservoirs.

The Aptian Dariyan (Shuaiba) Formation, a major Cretaceous reservoir in the Middle East, remains poorly understood regarding the influence of depositional facies and diagenetic processes on reservoir quality. This research addresses the gap through an integrated analysis of facies, petrophysics and geochemistry on a continuous, 104.5 m-long core from the Salman oil/gas field in the eastern Persian Gulf. Employing fully automated techniques, we identified hydraulic flow units (HFUs). We classified nine carbonate facies into three distinct facies associations, arranged from shallowest to deepest: inner ramp (lagoon and shoals), shallow open-marine mid-ramp and deep open-marine (outer ramp and intrashelf basin). These facies associations exhibit a stacking pattern delineating five third-order transgressive–regressive sequences. The identified HFUs include the barrier unit (HFU1), the baffle unit (HFU2) and the normal unit (HFU3), assessed based on lithological and petrophysical attributes. The normal unit, characterized by good storage capacity but poor to moderate flow capacity, highlights the complexity of reservoir quality. The Dariyan Formation is predominantly composed of mud-supported textures formed in warm, tropical waters. Additionally, late diagenetic cementation severely obstructed pore spaces, altered primary rock characteristics and reduced effective flow capacity.