In Abu Dhabi, the Mishrif Formation is developed in the eastern and western parts conformably above the Shilaif Formation and forms several commercial discoveries. The present study was carried out to understand the development of the Mishrif Formation over a large area in western onshore Abu Dhabi and to identify possible Mishrif sweet spots as future drilling locations. To achieve this objective, seismic mapping of various reflectors below, above, and within the Mishrif Formation was attempted. From drilled wells all the available wireline data and cores were studied. Detailed seismic sequence stratigraphic analysis was carried out to understand the evolution of the Mishrif Formation and places where the good porosity-permeability development and oil accumulation might have happened. The seismic characters of the Mishrif Formation in dry and successful wells were studied and were calibrated with well data. The Mishrif Formation was deposited during Late Cretaceous Cenomanian time. In the study area it has a gross thickness ranging from 532 to 1,269 ft as derived from the drilled wells; the thickness rapidly decreases eastward toward the shelf edge and approaching the Shilaif basin. The Mishrif was divided into three third-order sequences based on core observations from seven wells and log signatures from 25 wells. The bottom-most sequence Mishrif 1.0 was identified is the thickest unit but was also found dry. The next identified sequence Mishrif 2.0 was also dry. The next and the uppermost sequence identified as Mishrif 3.0 shows a thickness from 123 to 328 ft. All the tested oil-bearing intervals lie within this sequence. This sequence was further subdivided into three fourth-order sequences based on log and core signatures; namely, Mishrif 3.1, 3.2, and 3.3. In six selected seismic lines of 181 Line Km (LKM) cutting across the depositional axis, seismic sequence stratigraphic analysis was carried out. In those sections all the visible seismic reflectors were picked using a stratigraphic interpretation software. Reflector groups were made to identify lowstand systems tract, transgressive systems tract, maximum flooding surface, and highstand systems tract by tying with the observations of log and core at the wells and by seismic signature. Wheeler diagrams were generated in all these six sections to understand the lateral disposition of these events and locales of their development. Based on stratigraphic analysis, a zone with likely grainy porous facies development was identified in Mishrif 3.0. Paleotopography at the top of Mishrif was reconstructed to help delineate areas where sea-level fall generated leaching-related sweet spots. Analysis of measured permeability data identified the presence of local permeability baffles affecting the reservoir quality and hydrocarbon accumulation. This study helped to identify several drilling locations based on a generic understanding of the Mishrif Formation. Such stratigraphic techniques can be successfully applied in similar carbonate reservoirs to identify the prospect areas.

Sonatrach in Algeria needs to meet its natural gas production targets to honor foreign sales contracts and domestic demand. As depletion drive gas fields, their reservoir pressure declines with an associated reduction in gas production. This phenomenon is more pronounced when aquifer water breaks through resulting in well-head pressures drop. This paper demonstrates how we developed several workflows serving construction of robust high-resolution simulation model to optimize gas recovery of mature field. The applied workflows started by reviewing seismic interpretation where different scenarios for velocity model were evaluated. Then followed by revising the petrophysics reservoir evaluations and developing a general deterministic for reservoir rock typing (RRT) and fluid contact identification. A pseudo-saturation modeling workflow was settled when SCAL data are missing. Control of channels bodies distribution in the model was achieved by applying a workflow that integrates all available geological data with interpreted dynamic data. Last workflow combining the defined RRT with generated maps of GIIP density, flow-capacity (KH) and actual reservoir pressure helped to identify the sweet spot locations for infill drilling option. A robust 3D geological and compositional dynamic model that allows accurate computation of LPG and condensates recoveries was constructed for a complex clastic reservoir in South-East of Algeria. No upscaling was applied on the static model to preserve its geological sense and getting high-resolution multi-million cell model. It replicates perfectly the reservoir pressure behavior and the 20 years of production history, allowing optimization of the field development plan. Among the multiple development scenarios that were investigated using the high-resolution simulator to reduce the run time, combination of infill drilling and mainly gas compression widely adopted by the petroleum industry and considered as a reliable method for improving reserves base was found to be the optimum development plan for the studied mature gas condensate field. Compression at wellhead from 75 to 20 bars extends well and field life resulting in tapping additional reserves of natural gas, LPG and condensates, which may be left behind in case surface compression facilities are not put in place in a timely and phased manner. By 2050, the final recovery factor (RF) of gas and condensates can be increased by 35% and 15% respectively compared to the existing development. The application of such integrated workflows in a structured, consistent and proactive approaches with the use of high-resolution simulator tool leads to have multiple scenarios/evaluations in a very short time and assure the ability to handle detailed geology and therefore reduce uncertainty in modeling outcomes. All of these will definitively improve the overall asset management in terms of maximizing production and recoverable reserves in similar complex clastic reservoirs from any part of the world.

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We have performed an exploration-oriented investigation in nine European countries to identify and rank prospective shale gas plays within their borders. This study, conducted as a rank exploration or “pathfinding” effort because the industry’s activity for these types of reservoirs is in its early stages in Europe, was performed in two phases. The first was a high-level, rapid review of data from public sources for nine countries: Sweden, France, Poland, Denmark, Turkey, Germany, Spain, Romania, and Hungary. The objective of this first phase, preliminary filtering, was to review as many potential shale gas plays within these nine countries as possible and identify the top three countries containing the most prospective shale reservoirs. During the study’s second phase, referred to as the “deep dive,” a deeper investigation into details into the most prospective shale plays identified during the first phase was conducted. More than 400 published documents were reviewed to extract geologic information for these nine countries. This literature review identified 65 shale formations within 56 basins and 22 subbasins. Geologic, geochemical, and geomechanical data for these potential shale plays are also collected and analyzed during this preliminary filtering first phase. These data are used for ranking the shale plays identified, and cutoffs are established to determine “go” and “no-go” plays. Within selected basins, 1D thermal maturity modeling was performed and combined with published maturity data. The 11 shale plays are found to be within all of the selection criteria cutoffs established for this study. These 11 shale plays are investigated in more detail during the second phase of the study, the deep dive. This study’s exploration methodology, which proved valuable for rapidly screening potential exploration targets at a high level, is the main focus of this paper.

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