The Middle Permian to Lower Triassic Khuff Formation is one of the most important reservoir intervals in the Middle East. This study presents a sequence stratigraphic analysis of the Khuff Formation of a well-exposed outcrop in the Oman Mountains, which may provide a reference section for correlations across the entire Middle East. On the Saiq Plateau of the Al Jabal al-Akhdar, the Permian Upper Saiq Formation is time-equivalent to the Lower and Middle Khuff Formation (K5–K3 reservoir units in Oman). The Permian section is dominated by graded skeletal and peloidal packstones and cross-bedded grainstones with a diverse marine fauna. The Lower Mahil Member (Induan Stage), time-equivalent to the Upper Khuff Formation (K2–K1 reservoir units in Oman), is dominated by grainstones composed of microbially-coated intra-clasts and ooids. In general, the studied outcrop is characterized by a very high percentage of grain-dominated textures representing storm-dominated shoal to foreshoal deposits of a paleogeographically more distal portion of the Khuff carbonate ramp. A sequence-stratigraphic analysis was carried out by integrating lithostratigraphic marker beds, facies cycles, bio- and chemostratigraphy. The investigated outcrop section was subdivided into six third-order sequences, named KS 6 to KS 1. KS 6–KS 5 are interpreted to correspond to the Murgabian to Midian (ca. Wordian to Capitanian) stages. KS 4-Lower KS 2 correspond to the Dzhulfian (Wuchiapingian) to Dorashamian (Changhsingian) stages. Upper KS 2–KS 1 represent the Triassic Induan stage. Each of the six sequences was further subdivided into fourth-order cycle sets and fifth-order cycles. The documentation of this outcrop may contribute to a better regional understanding of the Khuff Formation on the Arabian Platform.

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High energy, lake‐shoreline carbonate sequences are rarely documented in the geological record. However, one example occurs in the Upper Triassic Mercia Mudstone Group (MMG) of southern Britain. The MMG is one of a number of thick, non‐fossiliferous mudstone deposits associated with North Atlantic Mesozoic rift basins. The origin of the MMG mudstones is the subject of current debate, with marine, playa‐lacustrine and alluvial–aeolian models having been proposed. Shoreline features have been documented from the northern margin of the basin, but the rarity of such features elsewhere in the MMG has led many workers to doubt a lacustrine origin for the mudstones. Wave‐dominated, lake‐shoreline deposits have been recognized in several sections from the southern basin margin in the Clevedon area of the Bristol Channel in south‐west England. These deposits provide evidence for the development of a sizeable perennial to semi‐perennial hypersaline lake in which the MMG mudstones accumulated. Shoreline sediments overlie alluvial stream and sheet‐flood deposits, and pass from transgressive gravel–conglomerate beach units with bioclasts, influenced by shore‐normal waves (deposited under semi‐humid conditions), to lower gradient, highstand oolitic sands affected by more varied wave approach (deposited under progressively more arid conditions), which culminated in lowstand, oolitic strand‐plain deposits overlain by a playa‐mudflat unit. Shoreline deposits record a simple shallowing‐upward transgressive–highstand–lowstand sequence. However, a change from a reflective (transgressive) to dissipative (highstand) shoreline is believed to represent a climatically induced change in prevailing wind direction. Shoreline features recognized in the MMG are similar to those of recent playa‐lacustrine basins of the western United States. Ooids display a variety of size, fracture and dissolution features in addition to beachrock fabrics, suggesting that they were originally composed of radial aragonite, similar to modern ooids from the Great Salt Lake, Utah.

Field X comprises a giant Palaeogene limestone reservoir with a long production history. An original geomodel used for history matching employed a permeability transform derived directly from core data. However, the resulting permeability model required major modifications, such as horizontal and vertical permeability multipliers, in order to match the historic data. The rationale behind these multipliers is not well understood and not based on geological constraints. Our study employs an integrated near-wellbore upscaling workflow to identify and evaluate the geological heterogeneities that enhanced reservoir permeability. Key among these heterogeneities are mechanically weak zones of solution-enhanced porosity, leached stylolites and associated tension-gashes, which were developed during late-stage diagenetic corrosion. The results of this investigation confirmed the key role of diagenetic corrosion in enhancing the permeability of the reservoir. Insights gained from the available production history, in conjunction with petrophysical data analysis, substantiated the characterization of this solution-enhanced permeability. This study provided valuable insights into the means by which a satisfactory field-level history match for a giant carbonate reservoir can be achieved. Instead of applying artificial permeability multipliers that do not necessarily capture the impacts of geological heterogeneities, our method incorporates representations of fine-scale heterogeneities. Improving the characterization of permeability distribution in the field provided an updated and geologically consistent permeability model that could contribute to the ongoing development plans to maximize incremental oil recovery. Field X is a giant offshore oil and gas field with a long production history from a limestone reservoir. Permeability has been identified as one of the biggest uncertainties associated with the reservoir simulation model during field optimization studies that have been carried out by the operator previously. A reduction in the uncertainties for the permeability distribution is needed to evaluate the feasibility of the next development phase.In this study we attempt to resolve these issues through a systematic re-evaluation of the reservoir simulation model, considering, in particular, the field's diagenetic history. Our aim is to understand the fundamental controls on fluid flow that need to be adequately captured in the reservoir model. Geological studies carried out by the operator suggest that the key permeability pathways are strongly related to the mechanism of reservoir porosity -permeability evolution during late-burial corrosion (Wright & Barnett 2011). Late-burial corrosion in Field X is referred to as deep burial/ mesogenetic corrosion associated with the corrosion of limestone by burial-derived (hypogene) fluids. However, it is unclear how a diagenetic model that accounts for late-burial corrosion should be included in the reservoir simulation model and how such an updated reservoir simulation model could i...

Carbonate reservoirs host a major portion of the world's remaining conventional and unconventional hydrocarbon reserves, typically containing multi-scale geological heterogeneities varying over many orders of magnitude in size. Characterizing and representing them robustly in reservoir models is a prime challenge in carbonate reservoir simulation. One of the key aims of this paper is, hence, to present a novel near wellbore upscaling (NWU) workflow that addresses the challenges associated with conventional carbonate modelling workflows. The NWU workflow provides a systematic geostatistical approach to obtain more realistic representation of multi-scale geological-petrophysical heterogeneities in complex carbonate reservoir simulation models. Using well log and core data, near wellbore regions were recreated to represent the core scale heterogeneities via high resolution geostatistical models. These core/centimeter scale permeability models were then upscaled into wireline/decametre scale using flow-based upscaling. The results, coupled with wireline data were used to generate global porosity-permeability and vertical-horizontal permeability relationships for reservoir simulation. Importantly, the workflow mitigates sample bias, which is frequently observed in the core data for carbonate reservoirs. We have applied our approach to a mature carbonate field, to model and upscale crucial multi-scale heterogeneities ubiquitous in the reservoir. These heterogeneities, such as mechanically weak zones of enhanced micro- and macro-porosity, leached stylolites and associated tension gashes, were caused by diagenetic corrosion. Core plugs representivity is always an issue in carbonates and these highly corroded features were very difficult, if not impossible, to sample due to their fragility. As a result, the field suffers from inherent sample biasing and insufficiency of Routine Core Analysis (RCA) data, consequently underestimating the permeability in the simulation model. The workflow presented here has enabled the authors to re-evaluate the reservoir permeability model by accounting for as yet under-sampled geological heterogeneities. The paper represents a focused individual study addressing this specific issue and doesn't necessarily reflect the operator's full understanding of this multifaceted field. Our new permeability model has addressed the need for artificial permeability multipliers and provided insight on the potential causes of the original mismatch. As a result, a new alternative model scenario has been built to help guide the on-going development plans and forecasting incremental oil recovery.