The carbonate reservoir in question is located in the northwest of the Sultanate of Oman and was developed first in depletion mode since 1970. From the year 2000 until today a horizontal water flood scheme has been implemented. The reservoir is made up of 2 carbonate layers of 27 and 13 meters thickness intercalated with several meter thick shale layers. They form the deepest reservoir layers of the Cretaceous Natih Formation. The reservoir layers are composed of laterally continuous, microporous, low permeability (5-10mD) limestone that is interpreted to be heterogeneously but overall sparsely fractured. The implemented water flood in this field is considered to be well behaved with a stable oil production and low water cuts of around 20 to 25%.An integrated field study was carried out for a planned horizontal infill development. The main objective was to obtain a representative set of static and dynamic models that match historic production. One of the principal challenges was the unknown impact of fracturing and faulting on the intensified water flood development in the reservoir layers and on the potential vertical communication within and with overlying reservoir layers.Seismic, geological, petrophysical, and reservoir data were integrated with drilling and production information to produce a detailed matrix and fracture description of the reservoir. Several iterative workflows that included numerous feedback loops with reservoir simulation results were applied to achieve an appropriate history match and confidence into the predictive capabilities of the reservoir model and the simulation forecasts.The main achievements of the applied workflow are a major reduction of the uncertainties related to the impact of faults and fractures on reservoir behavior. Key was the close integration of simulation results of the dual porosity permeability model and field data. The modeling workflow of the matrix and fracture models and their implementation in the reservoir simulator were optimized in such a way that uncertainty evaluation was entirely handled in the simulator and simulation times were reduced significantly.This study has clearly shown that even in reservoirs that appear to be relatively simple and well behaving with respect to the chosen development option may require a much deeper level of understanding and may reveal significant complexities. In the presented case the reservoir formerly believed to be "simple matrix dominated reservoir" shows a significant heterogeneity in fracturing across the area of interest. Only detailed understanding after comprehensive data integration, construction of a dedicated continuous fracture model and a dual porosity permeability simulation model allowed achieving reliable predictions on reservoir behavior. The study has led to improved well planning and well and reservoir management practices in response to sudden increase in water production. The applied workflows may serve as an example for comparable carbonate reservoirs with apparent sparse fracturing that, however, may...
Petroleum Development Oman's (PDO) portfolio of heavy-oil, fractured carbonate prospects and fields contains a potentially large number of EOR opportunities, many of which present unique subsurface challenges. In the context of evaluating one such field, an EOR screening approach was developed combining subsurface definition through a tailor-made appraisal campaign, coupled with technical & economic feasibility evaluation of candidate EOR methods and benchmarking against other fields globally. This paper presents the screening workflow that will serve as template for the evaluation of future EOR opportunities in heavy-oil, fractured carbonate discoveries in PDO.At the outset of the reservoir characterization of this field it was recognized that the application of any EOR technique would be challenging. High oil viscosities coupled with shallow depths render it a candidate for thermal EOR and potentially chemical concepts. However, key uncertainties in basic subsurface parameters such as reservoir architecture, matrix permeability, fracture spacing and (low) oil saturations, necessitated further data gathering before feasibility of any recovery mechanism could be concluded.Based on literature surveys and examination of showstopper properties, a first-pass screening of a multitude of thermal and chemical EOR methods was conducted. A probabilistic assessment of key subsurface parameters was conducted against which the candidate EOR techniques were ranked. This resulted in the identification of SAGOGD, CSS, ISC and novel-chemical flooding as the most promising EOR methods.For each of these methods the critical subsurface parameters and their impact were further assessed through the combination of (1) an appraisal campaign that included drilling of new wells, conventional production & pressure interference testing to constrain the uncertainties in these parameters and (2) Fit-for-purpose modeling (analytical analysis, sector modeling and full-field simulation) to check project feasibility.It was found that none of the thermal recovery methods are technically or economically feasible, but chemical methods are being investigated further. 2 SPE 155546
The field was discovered in 1992. It produces oil and associated gas from two reservoir sub units of the Upper Shuaiba USh3F1 and USh3F2, and exhibits both structural and startighraphical traps. The reservoir units are compartmentalized by NW-trending normal faults into five fault blocks within the same field towards the North East. They are vertically separated by non-reservoir low permeability mudstone facies. US3F2 is setting above Orbitolina shale. The objective is to build a new geological model in a very complex carbonate reservoir, to allow for better reservoir development, and adding new field opportunities using state of art seismic data. Lower unit (US3F2) consists of an aggradational sequence skeletal peloid-foram packstone/wackestone, and in-situ rudist-algal boundstone/packstone build-ups, which is localized to the NE-trending axis of the field. These sequences are deposited in a low to moderate energy environment. US3F2 reaches a maximum thickness of 50 ft in the rudist build-ups, but the width of the rudist-algal boundstone facies parallel to depositional dip (SE) is only 0.5–0.7 km. Cores exhibit abundant secondary porosity with an average of 30% and permeability up to 700 mD suggesting early subaerial exposure and leaching. Upper unit (US3F1) is either absent or very thin across the crest and thickens to over 20 ft basinward; downdip, it is separated from US3F2 by a shale unit. US3F1 consists of an upward-shallowing deposits of Orbitolina mudstone, reworked stromatoporoid-rudist floatstone, small rudist floatstone, and fine skeletal grain-dominated packstone with rudist fragments. 3D model was generated covering large area of about 15x9km of the field. The new seismic horizon and faults interpretation were used in the 3D structural modeling. Cores descriptions and photos were used to define core facies, depositional environments and vuggy intervals. Rudist buildups direction of progradation was also defined based on BHI. Reservoir rock Fabric number (RFN) was defined based on Lucia method and populated using veriogram per zone for the vertical wells using moving average method followed by Gaussian Random simulation, co-kriged with the moving average properties as a trend, for both vertical and horizontal wells. Porosity was populated with the same method. Water saturation and permeability were calculated using Lucia height function method. Understanding of the reservoir heterogeneity, architecture and 3D modeling using RFN based on Lucia method allowed a better distribution of reservoir properties to be used in dynamic simulation for better history match, predict waterflood performance and adding new development areas.
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