One of the main challenges in development of the fractured reservoirs is the identification of "sweet spots" which are the most intensely fractured areas of a field, maintaining a long term production with minimized risks in drilling. This paper presents a multi-disciplinary approach including G&G (geology & geophysics), petrophysics and reservoir engineering perspective to overcome this difficulty in a particular oil reservoir by defining the fracture systems that mainly contributes to the hydrocarbon storage capacity and flow dynamics.Şambayat Field is one of the most important naturally fractured carbonate reservoirs located in the Southeast Turkey. Reservoir zones in the field include a number of reverse, synthetic and antithetic faults and related fracture sets which are hydraulically in contact with each other. In this context, characterizing the fracture network becomes the most critical issue in the analysis of production and the development strategy of the field.For this purpose; besides the conventional open-hole log analyses, image log interpretations have also been performed in order to evaluate the properties of the fractures. To honor these interpretations; dynamic (drill stem test & production) and static (outcrop & core) data have been evaluated together. Distributions of the petrophysical properties and the fractures have been done by using stochastic methods in full-field scale. At the end of the modeling study, a dual porosity geological model has been generated by using the Discrete Fracture Network (DFN) approach with respect to the estimated fracture characteristics.As the result of the previous characterization study, new well locations and their optimized orientations had been determined and the results coincided with the expected types of fractures estimated in the DFN model. After updating the model with the new well data and the enhanced functionalities in the modeling software, additional well locations have been proposed which will play a role in one step further of the study; simulation.This study has contributed to our knowledge about the characteristics of a naturally fractured carbonate reservoir which is similar to the ones explored in Southeast Turkey and to some extend in Middle East. It should also be noted that, our approach in this particular study is a newly developing technique and could be used for the promising "previously overlooked" unconventional reservoirs.

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Bati Raman field, with an original oil in place of 1.85 billion barrels, is a naturally fractured carbonate reservoir containing 9-13 °API extra heavy oil with viscosities varying from 300 to 600 cp. Not only a wide range of pilot EOR schemes including gas, thermal and chemical methods, but also novel IOR applications have been tried in the field. CO2 injection was a game changer for this reservoir which has been the main drive mechanism since 1987. Since then, various techniques are applied to further improve the production performance of the field. This study focuses on the design and outcome of the pilot acid fracturing treatments in selected three wells in the tighter and less fractured southeastern part of the reservoir. State of the art planning included full evaluation of well integrity, cement bond and open hole logs, geomechanics studies augmented with rock mechanics laboratory tests. Laboratory tests were also conducted focusing on sludge/emulsion forming tendencies and acid reaction rates. Using these results, expected fracture dimensions were predicted along with production forecasts. In all wells, pre-frac calibration tests were conducted to assess stress conditions and fracturing parameter optimization. The treatments were then executed, improving the procedure between each well for acid fracturing. Injections schemes were operationally efficient and various diversion techniques were used to mitigate the presence of naturally fractured zones. Pre and post-job temperature logs helped to evaluate each treatment. The results from the wells were very positive; total production rate increased about fivefold, observed within one month after the treatments. No considerable change in water or CO2 production in the wells was observed which had been one of the most important objectives during the candidate selection process. One well was suspended, which turned out to be one of the producers of the field after acid fracturing treatment. Each well had a different post-frac production performance because of its geological characteristics and flow dynamics, making the study more valuable for better understanding of the process. The wells are still on critical observation to assess the nature of the created fractures and their longevity in the long run. Even after twelve to fifteen months of production, which is the breaking point period for fracture closure, the overall production level of the wells was double compared to pre-frac rates. One well still has a fracture dominated production while other two changed back into its pre-frac rates. Based on these results, acid fracturing campaign was extended in the area which is currently under evaluation.