Identifying oil-saturated versus water-saturated sands in shallow, unconsolidated, viscous-oil-bearing terrigenous-clastic reservoirs of Kuwait field is challenging. Field appraisal was based upon seismic, core and wireline-log data from 19 wells. Static and dynamic models incorporating all subsurface data were built to estimate oil-in-place and forecast production. Estimating and modeling fluid saturations in reservoir zones was accomplished by integrating core, dielectric-resistivity, Nuclear Magnetic Resonance (NMR) and Wireline Formation Tester (WFT) data. Wells were drilled along a northwest/southeast-trend, thus geologic and reservoir-property variability in east and west parts of the field are uncertain. Stratigraphy and lithologic properties in these Miocene-age fluvial to shallow-marine strata impart a complex 3–D fluid distribution in the field. Repeated shoreline progradations and retrogradations deposited a stratigraphic succession defined by five facies-associations (i.e., shoal, tidal flat, tidal channel, lagoon, sabkha). Five lithofacies (i.e., shale, shaly sandstone, sandstone, carbonate-cemented sandstone, evaporite) were identified from core, elemental spectroscopy logs, and X-ray diffraction (XRD) data. Facies associations and lithofacies models were built using a combination of multiple-point statistics and sequential-indicator simulation. Lithofacies distribution in the static model was constrained by the facies-association distribution; reservoir-property distribution (e.g., porosity, permeability) was conditioned by lithofacies. Discrete reservoir zones were defined to separate oil-saturated versus water-saturated sands. The volume and position of oil-bearing sands are controlled by the defined zones and permeability distribution. The oil-filling process in these viscous oil-bearing reservoirs is typically controlled by the pore throat distribution with the migrating oil taking the path of least resistance. Due to the presence of stratigraphic-flow baffles, fluid contacts vary from sand-to-sand vertically and laterally. Log data, core descriptions, ultraviolet photographs, WFT and pressure volume temperature (PVT) data guided the interpretation of lowest known oil and highest known water levels, thus reducing fluid saturation uncertainty in the field.
Within North Kuwait heavy oil fields, integrated reservoir modelling is challenged by inherent reservoir heterogeneities, regional non-stationarity (i.e. trends), asymmetrical well and seismic distributions, and the need to maintain alignment between various the model scales required and multiple purposes for which the models will be used. This paper presents a number of customized workflows adapted to characterize these reservoir architectures and heterogeneities within one field, appropriately at all model scales and in regions with variable well control. A reliable new rock type classification scheme was derived from cross plot analyses of Gamma Ray and Bulk Density (GR-DENS) logs. Within an initial production area containing over 900 regularly spaced wells, 3D variograms for these lithotypes were estimated, calibrated with 3D seismic and reservoir equivalent surface outcrops. The lithotypes were distributed into full field static models using these variograms and the Sequential Indicator Simulation (SIS) algorithm. An additional declustering step was implemented to express regional trends and account for asymmetrical data distribution. Petrophysical property modeling (shale volume, effective porosity, water saturation) was performed using the Kriging algorithm conditioned to lithofacies. From these full field models, sector models were created to capture geological heterogeneity at a smaller grid increment. Full-field facies were downscaled onto the sector model grids, and then the Sequential Gaussian Simulation (SGS) algorithm was used to interpolate petrophysical properties, constrained by histograms of the kriged background models. This allowed information from wells outside of sector models to be incorporated efficiently into them. The facies and heterogeneities represented within the full-field static models have improved upon earlier versions, by being distributed more consistently relative to known seismic and well control, and to outcrop reservoir analogues. Modelled petrophysical properties also show a more consistent linkage with known values derived from core analyses. This consistent set of models can now be used with greater confidence, to answer questions ranging from in-place volume uncertainties to dynamic production forecasting, to life of field development. This has also led to reduced dynamic model run times, and improved reservoir management and operations optimization. In summary a robust series of full-field and sector models was developed and customized to a North Kuwait heavy-oil field, with information from data-rich areas being elegantly applied to reduce uncertainties in data-poor areas. These nested models can now be matched to the detail required for the model purpose. For example heterogeneities that matter-for-flow in dynamic simulation models can be represented explicitly, whereas for full-field volume estimations property averages can be used.
The Northern part of Kuwait is a highly active development area for deeper gas, intermediate-depth conventional oil and shallow heavy oil. All these developments have overlapping footprints in an already congested area, requiring different development concepts for gas, water flood and steam respectively. Additionally, different Assets manage the respective reservoirs. Integrated Urban Planning across all Assets therefore becomes a vital requirement for realizing all concurrent future developments regarding land use, and enabling close collaboration to leverage synergies among the Assets, utilizing both organizational and new technology-based solutions, in order to maximize value for Kuwait Oil Company (KOC). In North Kuwait Urban Planning is a joint effort between KOC and Shell, with initial focus on establishing an agreement for work methods, effective communications, and protocols with all stakeholders. Next all "as-built" infrastructure and current plans were combined and reviewed. This formed the basis to identify and resolve conflicts, recognize opportunities for reduced land requirements and optimize the development synergies. The approach is underpinned with new technologies, tools, best practices, and concepts like multi-well pad developments, area discounting, exclusion zones, and shared infrastructure and road access corridors, based on global analogue developments. In this paper example field ‘A’ is discussed as it has stacked reservoirs of shallow heavy oil, intermediate conventional oil and deep, sour gas. It requires significant urban planning focus to avoid conflicts and enable synergies. In field A, the shallow heavy-oil development requires large number of wells in a dense well-spacing versus fewer wells targeting the intermediate-depth conventional oil and deeper gas reservoirs, which requires large "safety zones" around well sites. In both cases, common infrastructure like roads, power distribution, flow line and trunkline corridors also need to be considered jointly. Urban Planning collaboration between assets with distinct development challenges can help in creating safe co-development opportunities, thus maximizing value for KOC.
A shallow unconventional heavy oil reservoir in Kuwait is primarily an unconsolidated sandstone reservoir with intervening cemented siltstone and sandstone, and thin shale layers. The process and relative timing of cementation in the reservoir played a key role in fluid distribution as the pore-filling cements originated prior to oil migration. Moreover, oil migration into the cemented zones was prevented by the presence of cement. This paper presents a study based on over 100 logs and 10 conventional cores in north of the reservoir. Detailed core analysis including petrography, XRD and SEM studies were considered understand the origin of cement, diagenesis and role in fluid distribution. In terms of origin and diagenesis, three types of cements were identified namely Calcite, Dolomite, and Argillaceous. Calcite and Dolomitic cements are admixture of calcium carbonate and calcium-magnesium carbonate with argillaceous components. Argillaceous cement is dominated by illite-montmorillonite and palygorskite with minor amount of kaolinite and chlorite. Argillaceous one primarily originated from feldspar, calcite from meteoric water rich in dissolved calcium (gypsum) and Dolomite as replacement of precursor calcite. Cement plays different roles in fluid distribution. Argillaceous cements cause pore-throat blockage due to presence of illite and palygorskite that form filamentous-fibrous aggregates. Cemented layers act as baffles in between oil layers capable of producing significant amount of trapped water in low pressure regime as they have significant amount of porosity and permeability. Finally cement layers hold water due to high capillary pressure and act as "water above oil" behaving as thief zone during thermal steam operation. Understanding origin of cement, diagenesis and its role in fluid distribution assist in evaluation of the layered nature of this complex fluid distribution pattern reservoir. Finally, integration of depositional environment, lithofacies, and cement distribution greatly enhance the assessment of lateral extension and characterization of these type of reservoirs.
Wireline Formation Tester surveys are routinely performed for pressure profiling in all new wells. These surveys are being extensively used to identify contacts, cross communication etc. The information is updated and integrated for a full field perspective so that depletion trends, communication across faults, and presence of sub-layers within the main sand lobes are identified, validated and mapped. This data set is acquired over time, against a well laid out strategy and against all the sands.As a precursor for building a model in a multilayered mature oil field of Kuwait, the collected data were analyzed to draw interesting and operationally important conclusions.The study reinforced the sub-layering classification followed in the field on a broader scale; however in a few instances, marked anomalies were noted. The existing sand layering scheme was revisited and corrections applied by adjusting the layer tops in those wells.Multiple pressure points across adjacent sub-layers with close pressure regime were grouped and re-grouped and plots were generated. The layers followed the existing geological layering scheme; but in some instances, the plots indicated a different picture of the extent of these sub-layers. This type of validation of layering scheme of the static model gave important insights during upscaling for the dynamic model. Analyses of the plots were carried out in different segments for well clusters across faults. The plots uncovered important information about the nature of the faults. Conclusions drawn from these plots are planned to be used for supplementing Pressure Transient Analysis information during history match.
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