Most of the northern Oman fields have tight carbonate reservoirs. The field under study was initially produced under natural depletion with declining reservoir pressures through vertical and horizontal wells (1990-2002), then followed by two years water flood piloting and thereafter full field line drive water flood implementation through open hole horizontal wells. After more than 10 years of water injection, water production increase is seen in most of the wells and water cut reached an average of 65-75% in the major producing blocks. Based on current data, the ultimate recovery factor of the current water flood development from these blocks is expected to be as high as 40-45%. In sight of the continuous increase of water production from the field and taking into account that more than 50% of the field's oil initially in place will not be recovered by the current secondary production mechanism (water flood), the block operator initiated research work on the tertiary production mechanism to maximize the oil recovery from the field. Extensive laboratory and field testing works were performed over the past five years to select the suitable and optimum IOR/EOR technique to be implemented in this tight carbonate reservoir. The process started with screening of different EOR methods and was followed by laboratory fluid behavior testing and core flooding experiments for the selected method. Out of all EOR methods, chemical EOR was screened as the most convenient and applicable method to be implemented due to the nature of both reservoir and fluid. This paper summarizes the working process which was followed to eventually select the convenient chemical starting from screening process, then laboratory work, followed by single well field testing and eventually extended injection field testing. High level results will be presented for the first three milestones and more elaborations on the extended injection field testing will be presented. Results for both field trials; the huff and puff and the extended injection are encouraging with incremental oil gains exceeding the expectation from these trials. The extended chemical injection field trial was executed in ~ 40 acre, horizontal line drive pattern utilizing two horizontal injectors and four horizontal producers with two vertical pressure observation wells. The evaluation of injection results was based on actual daily production and injection data as well as reservoir log and core data collected before chemical injection. Comparing to water flood, initial recovery factor evaluation indicate possible improvement of up to 18% (per pore volume injected) in unit A which has more mature water flood where water cut exceeding 80% but less oil volume. Recovery improvement in unit B, a less mature water flood reservoir unit, was not remarkable. Post job analysis and review claims this due to the relatively immature water injection and thus lower water cut in this reservoir unit. Unit B is also three times thicker than unit A, which meant it received a lower chemical volume, which might have resulted in a lower recovery performance. With limited field trials of surfactant injection in tight carbonate reservoirs in Middle East, this case study will help to enrich the literature with actual field data of continues surfactant injection in tight carbonate field.
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...
This paper describes a workflow that was applied to a carbonate field in Oman to derive fracture and effective permeability models that were validated with multiple blind wells and reservoir simulation. The studied block is the largest and most faulted within a field which is currently under water-flood FDP. The study was kicked off with extensive borehole image interpretation. In parallel, several high resolution seismic inversions and spectral imaging attributes were generated as drivers to geological and fracture modelling. High resolution seismic was used to highlight subtle faults. Facies changes were also visible from seismic as seen in cored wells. Sequential geological modelling of GR, density, porosity and SW was carried out and constrained by seismic attributes. The derived fracture frequency logs were compared against geological, structural and seismic drivers in a process called driver ranking. The results confirmed the role of faults as well as facies being primary controls of fracturing. Subsequently, the screened and cross-correlated potential drivers were carried forward to constrain the fracture models. Multiple stochastic realizations were derived through neural network training and testing and an average model was kept. Final models were validated against hidden BHI data. A new BHI was used to confirm model prediction. Different types of dynamic data in non-BHI wells were also used to validate the fracture models as specific production/injection related issues could be directly linked to presence of fractures. These data include PLT, PTA and tracer tests from which injectivity issues and short circuiting were explained by higher fracture densities and corridors derived from modeling. Through dynamic calibration, the fracture model was converted to fracture permeability. The fracture permeability is the product of fracture density and a scaling factor derived from history matching. Subsequently, the addition of matrix permeability and fracture permeability will determine the effective permeability. This Keffective was directly used in the reservoir simulator without upscaling since it was part of the same grid hosting the fracture models. The results were encouraging as the simulation was smooth and error-free.
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