The choice of the optimal trajectory of horizontal and directional wells, the placement of frac-ports for multistage hydraulic fracturing, taking into account prepared input data (using geological and geomechanical modeling with the rock properties anisotropy), provide optimization of hydraulic fracturing operations and field development. Formation T contains more than 3 trillion m3 of gas, and is already an object of close attention of the largest oil and gas companies. The unique character of the object is due to the high reservoir compartmentalization of the collector and low permeability. Therefore, the main development strategy for the reservoir is to drill low-angle and horizontal wells, followed by multistage hydraulic fracturing. The main goal of multistage hydraulic fracturing is to join productive intervals and at the same time avoid undesirable fracture breaks into neighboring layers. To achieve this goal, several tasks were solved: creation of a petrophysical and geological basis for geomechanical modeling, creation 1D and 3D geomechanical models taking into account the rock properties anisotropy due to the high layering of the reservoir, and preparing input data for hydraulic fracturing design. For the qualitative creation of the geomechanical model at the observation wells of the field, an expanded complex of special well logging studies has been performed, borehole measurements of reservoir pressure and minimum horizontal stress have been carried out according to the results of stress tests, core sampling and research to determine petrophysical and mechanical properties. The analysis of the obtained information revealed the features of the stress state along the section and reservoir area, which were taken into account in the design of hydraulic fracturing. Geomechanical modeling was carried out in a uniform work procedure, which made it possible to unify the result, improve the quality of calculations and forecast parameters for horizontal wells.

Development of complex-build oil and gas reservoirs is associated with advanced technologies such as horizontal wells drilling and multi-stage hydraulic fracturing. Geomechanical modeling for hydraulic fracturing purposes is a fundamental tool for assessing technological constraints and risks, as well as increasing efficiency of reservoir treatment. In proposed approach of horizontal stresses modeling and calibration to the actual hydraulic fracturing data additional features considered to compensate low contrast of Poisson's ratio calculated from broadband acoustics: elastic properties TIV-anisotropy, variation of Biot coefficient adjusted to mechanical facies, correlations between static elastic properties and petrophysical parameters based on core measurements. Lab measurements on oriented core samples revealed elastic properties anisotropy that caused difference of the static young's modulus parallel and perpendicular to the formation bedding up to 80 – 100%, and for the Poisson's ratio is up to 10 – 20%. Considering these results stress calculation leads to a difference between an isotropic and anisotropic profile up to 20%, this has significant impact on the hydraulic fracture geometry. The rock behavior under load is different and is determined by the properties of the rock grains and the contact between them. Thus, the section separation into mechanical facies plays an important role when estimating elastic parameters, including Biot coefficient (α), which is different for shales, sand and/or carbonate, for example. Correct estimation of α with respect to mechanical facies allows achieving good agreement between stress calculation and actual measurements obtained with a mini-frac job, thereby increasing fracture geometry prediction accuracy. Another tool to compensate lack of stress contrast calculated based on standard 1D geomechanical workflow is the use of petrophysical parameters such as porosity, clay content, neutron density and its correlation with static elastic properties to estimate minimum horizontal stress. This method may improve geomechanical model matching with field observations, but it has a limited scope of application. In this paper demonstrated that additional study of the rock properties with special logging and core measurements at initial phase of field development planning may significantly reduce geomechanical modeling uncertainties and improve understanding of hydraulic fracturing and fracture geometry, which is a basis for hydrocarbon production and economic evaluation of the project or the whole asset. The paper presents adapted geomechanical modeling workflow based on special lab core testing and elastic properties anisotropy and Biot coefficient evaluation to adjust the horizontal stresses profiles in complex-build reservoirs to the field measurements and observations as well as to fracturing data in existing wells.

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