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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.

Work objective and subject The main work objective is optimization of field development and well operations by providing recommendations on selection of optimal intervals for horizontal well placement and safe drawdown pressure limits in PK1 gas reservoir for minimizing risks of sand production. Up to 25% of the gas from the total recoverable reserves of gas assess of PJSC "NK "Ronseft" in the territory of Russian Federation is concentrated in PK1 formation, which makes it attractive for commercial field development. The uniqueness of the object is determined by the type of reservoir: highly porous and highly permeable weakly consolidated sandstone, which imposes a number of limitations on completion design and operating parameters. Used methods, technologies, process description A significant volume of special studies has been carried out to enhance quality and credibility of geomechanical modeling results: broadband acoustic cross-dipole logging, formation micro-imagers, extended leak off tests, pressure tests and fluid sampling, coring for complex petrophysical and geomechanical lab experiments. Based on the obtained information 1D geomechanical models were calculated for several offset and reference wells and calibrated on drilling results of first horizontal wells in PK1 reservoir of the Kharampur field. According to the results of 1D geomechanical modeling, calculations of safe and critical drawdown pressure are made for sand potential prediction during production. Specialized core samples tests are planned and conducted (thick-wall core cylinder tests) to calibrate modeling results. Results and conclusions Based on geomechanical model and the results of thick-wall core cylinder test, the values of safe and critical drawdown pressure along the wellbore were determined for initial reservoir conditions. It's defined that the planned interval of horizontal well placement in some parts of the study area is characterized by lower value of safe drawdown pressure (DD<2.5 atm.) than was planned in the preliminary field develompent strategy. To achieve the planned volumes of cumulative production, it is proposed to review the placement of horizontal wells in intervals and zones where the critical drawdown pressure corresponds with or may be higher than planned one. Novelty of work and achievements As part of project implementation, at the planning stage of the field development strategy an expanded set of advanced logging and measurements was carried out on a number of offset and reference wells to increase the reliability of the petrophysical and geomechanical models. To confirm the results of drawdown pressure limits calculation on the basis of geomechanical parameters a new method developed and special lab experiments (thick-wall core cylinder tests) were conducted for predicting several states of the rock during loading-deformation process and estimate safe and critical drawdown pressure. The results of geomechanical modeling are used as a basis for project design documentation and will be used to calculate the optimal parameters of well operation and increase the efficiency of field development.

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Effective assessment of the stress-strain state of the near wellbore zone is one of the key problems in the process of modeling the stability of the wellbore walls. Drilling mud infiltrates permeable rocks during the drilling process. This causes a change in the elastic-strength properties of rocks and, accordingly, the redistribution of tension around the well. At present, there are no computational methods that take into account the effect of saturation fluids on the change in the elastic-strength properties. A unified system approach for the implementation of this type of research when changing infiltration fluids is not developed yet. In this paper, we study the effect of various types of drilling mud on the elastic-strength properties of core samples, which are equivalents of rocks (composite samples made of different sand and clay cement facies). Measurements of porosity, acoustic properties, ultimate strength for uniaxial compression, and static Young's modulus at different samples saturation are made. Studies of the elastic-strength properties of the samples are performed after 48 and 168 hours soaked in the drilling fluids. According to the study, the relative change in the dynamic Young's modulus with various sample saturation is 13.4-27.7%, the static young modulus (compression) is 19-40%, the dynamic Poisson ratio is 1.4-14.6% and the uniaxial compression strength is 28-35%. The data obtained indicate a significant effect of the saturating fluid on the elastic and strength properties of materials. A numerical one-dimensional simulation of the stability of the borehole walls is performed, taking into account the type of saturating fluid and the relative change in the elastic-strength properties. The results indicate a change in the stability of the wellbore walls; the indicators of the change in the equivalents of the collapse gradient and hydraulic fracturing are 0.2-0.3 g / cm3. A change in Young's modulus of 30% affects the design parameters of a hydraulic fracturing fracture – by width up to 100%, by half length up to 50%.