Reservoir management practices are classically based on analytical models and standard Reservoir Engineering tools. In the waterfood or water alternating gas recovery process, the analysis is made traditionally with the hypothesis of constant predefined patterns. The producer – injector pair's interaction is quantified based on predefined geometrical analysis of the percentages of contribution of each injector to a producer. In the absence of certain degree of reservoir homogeneity, and also possible injection/production technical issues this method presents a lot of limitation and may lead to erroneous results. Fields in the Middle East are dominantly carbonates and the flow paths are guided by heterogeneous distribution of reservoir characteristics mainly permeability. This paper outlines a case study for the usage of streamline simulation in predefining the optimized rates of each producer and injector in order to optimize the recovery from individual pattern. The study quantified the interaction between producers and injectors pairs and defined the dynamic pattern distribution through the history. A number of attributes can be derived for each producer injector and pattern. Attributes such as the instantaneous and cumulative voidage replacement ratio, sweep efficiency and injection leakage can be analyzed in order to give more weight in the optimization stage to certain producer and certain injectors. It was concluded that the geometrical lay out of the patterns is not necessary respected and the injectors may support producers outside their geometrical patterns. There was as well a certain amount of the injection that is not contributing to any production and it is not targeting or supporting any specific well. A number of forecast scenarios were conducted and through ranking different realizations based on total patterns sweep efficiency, the best scenario was selected to determine the allowable volumes to be injected and produced. The scenario showed better control of the patterns as there was a reduction of any redundant injection and the leakage was cut down.

A novel workflow was developed to select the optimal field development plan (FDP) accounting for the associated uncertainties in a green onshore oil field with a limited number of wells and no production data. The FDP was then revisited in view of the performance of wells drilled during the execution phase and updated as needed based on the acquired data . Comprehensive uncertainty analysis was performed resulting in multiple subsurface realizations. A broad set of development scenarios and options were screened under uncertainty. The viable scenarios were then economically evaluated, resulting in an optimal FDP that is robust to uncertainty and the least risk prone from an economical point of view. The used workflow was specifically suitable to test many development concepts and explore various options including horizontal well orientation, well pattern concept, pattern acreage and spacing, length of the horizontal sections, and landing of the horizontal sections. Following an extensive techno-economic analysis of all possible combinations (900 in total), the most robust development concept was selected and analyzed considering the viable development strategies pertaining to plateau rate, drilling schedule, phasing, water injection timing and artificial lift timings. A phased development approach was adopted enabling acquiring necessary data to mitigate the remaining uncertainty and avoid costly consequences of significant over- or under-capacity. Data acquired in one development phase were assessed and used to update the following planned phases, if necessary. The study demonstrated that the field development could accommodate a delay in either water injection or artificial lift implementation. Although it was not recommended at this stage to delay either of them, it is noteworthy that the long lead time that may be incurred in the implementation of artificial lift or the risk of lower injectivity would not impact the field performance or ultimate recovery if contained to a few years during initial production. These results further reinforced the robustness of the proposed development plan. Large subsurface uncertainty combined with an extensive set of possible development scenarios and options required cutting-edge uncertainty analysis and screening workflows to select the optimal FDP. These unique workflows can be readily used in similar green fields to help arrive at the final FDP.

Low permeability and complexities of rock formation in tight gas resources make it more complicated to predict well production performance and estimate gas recovery. To produce from the unconventional resources in the case that formation rock is not sensitive to damage caused by liquid invasion, hydraulic fracturing is the most common stimulation treatment to improve the production to the excepted economically rate. In term of reservoir geometry, tight sand formations are normally stacks of isolated lenses of sand bodies that are separated by shale layers. Each sand lens varies in shape and size and acts as a trap for original hydrocarbon accumulations. The sand lenses parameters such as length and width can play important role in controlling gas recovery from hydraulically fractured tight gas reservoirs. This study shows the effect of drainage pattern of the lenticular sand bodies on production performance and ultimate gas recovery in tight gas formations. Analytical and numerical simulation approaches are used in order to understand the effect of hydraulic fracture parameters and also attribution of sand lens size and shape to the drainage pattern and gas recovery in hydraulically fractured tight sand gas reservoirs. The results highlighted that in tight gas with massive hydraulic fractures, sand lens size in the direction perpendicular to hydraulic fracture wings has the major impact on gas recovery. Sand lens size in the direction parallel to hydraulic fracture wings does not have significant effect on gas recovery. When the sand lenses are isolated and small in size, from a singlewell-enhancement perspective, the gas recovery will increase significantly by performing massive hydraulic fracturing through isolated lenses.

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