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The paper presents the experience of using downhole microseismic monitoring to determine the direction of working agent losses while maintaining formation pressure in Baitugan oil field in Orenburg region. Studies were aimed at history matching and elaboration of the further strategy for formation pressure maintenance (FPM) and field development as a whole. The seismic monitoring method was used in the downhole version, when observations are done from the observation well located nearby the injection one. For reliable recording of weak microseismic events, high sensitivity receivers were used with 4 sensors per component. A special injection program was developed. Its first stage consisted in optimization of modes that ensure the maximum injection into formation of a fluid supplied at the wellhead. During acquisition parameter testing, passive recording of the seismic signal was done at all stages of injection during two weeks in various modes, including a short-term stop of injection with subsequent increase in injection to a maximum injection rate with exceeding the fracture gradient. Fracture growth zones were identified below the target formation. Starting from the second week of recording, fracture propagations to the overlying formations were observed under increased injection pressure. Based on data obtained, a three-dimensional map of microseismic events recorded in the formation was created. It was used for interpretation and allowed to specify geometry of self-induced hydraulic fractures depending on injection modes. Microseismic mapping of self-induced fractures in injection wells was done in Russia for the first time. The results of observations allow to optimize the formation pressure maintenance system through optimizing injection modes depending on local fracture gradients and injection shutting off in the zones with uncontrolled self-induced fractures that develop under minimum wellhead pressures. The obtained data also make it possible to significantly improve quality of history matching for carbonate deposits with reduced formation pressure through determining the injection efficiency. This result directly improves both the quality of forecast analysis and economic impact of formation pressure maintenance.

This paper discusses an approach to the static Young's modulus calibration on the basis of fracturing statistics from one of the West Siberian fields. The relevance of this work is due to the fact that there are many fields in the region where multi-stage fracturing is en masse carried out in horizontal wells, but laboratory tests of mechanical and strength properties are lacking. The procedure is based on reiterated matching of estimated fracture closure time to the actual values obtained during interpretation of data-frac test (or calibration or minifrac test) results in the course of the sequential search over the pairs of Young's modulus and leakage factor values. Then simulation of main fracturing is carried out, and simulation result is compared to the actual results of the works (whether fracture was successful or finished with emergency shutdown of pumps). From the entire set of experiments, the multiplier that satisfies all accidents and describes successful operations is chosen. Calibration of mechanical properties and stress model was successfully carried out in this field using the field data of more than hundred fracturing operations, which is evidenced by the similar values obtained in fracturing simulation and half-lengths of hydraulic fractures matched with field development data in one of the hydrodynamic model implementations. This work is a continuation of research [1, 2] and includes comparison of field development parameters in both calibration methods, which led to the final decision on the repeated laboratory studies, because none of the calibration methods used allowed creating a single universal model of mechanical properties. One of the models more reliably describes the situation of fracture development within the rock mass, the other relates to fracture development along the fault. In addition, the geomechanical model analysis also revealed that in most cases where fracture intersects the fault it would develop along it.