مجله ژئومکانیک نفت
سال پنجم شماره 3 (پاییز 1401)

 In this study, we present an analytical model developed to describe broadband inhomogeneous wave propagation in an unsaturated visco-poroelastic layered medium which can applied in geomechanics issues as hydrocarbon reservoirs. By taking into account the effect of the tortuosity parameter on the movement of pore fluids, the proposed formulation is capable of describing the wave behavior at high as well as mid and low frequencies. The boundary conditions proposed in this study, account for the connection between the surface pores, along with the slip that occurs between the two media at their interface. This enables us to model the layered medium in a more realistic way, where, the pore fluids are able to pass through the layers and the layers are able to move relative to each other. Finally, a sensitivity analysis is carried out and the effect of the various parameters on wave propagation inside the layered medium is observed.

The study of factors affecting wellbore stability has become very important in the oil and gas industry because they will save time and costs. In studying the stability of oil and gas wells, different factors such as mechanical properties, in-situ stresses, and pore pressure can be used. Consequently, knowing and calculating these parameters will be helpful in analyzing the wellbore stability. This study evaluated the effects of changing stresses on the wellbore stability and drilling mud weight window using a ratio of different stresses for the first time in one of the wells of the Zireh gas field, located in the southwest of Iran. Due to the lack of laboratory data, each of the parameters of the geomechanical model were determined by empirical correlation. Using Mohr-Coulomb and Mogi-Coulomb criteria, the drilling mud weight window was determined to be 76.99-128.17 (pcf) and 67.56-128.17 (pcf), respectively; however, Mogi-Coulomb provided better results. The wellbore stability is also investigated by using 3D numerical modeling using ABAQUS software and the Mohr-Coulomb criterion. According to the results of the numerical and analytical methods, the well is completely stable. Ultimately, five different in-situ stress ratios were examined to determine how in-situ stress distribution affected wellbore stability. According to the results, the mud weight window range decreases as the stress changes from an isotropic to an anisotropic state, indicating wellbore instability.

Geomechanical modeling and simulation are introduced to accurately determine the combined effects of hydrocarbon production-injection scenarios and changes in rock properties due to geomechanical effects. Pore pressure and stress states vary during production and injection steps. These variations considerably affect reservoir and cap-rock integrity, faults reactivation, formation compaction and uplifting, and wellbore stability. Therefore, accurate pore pressure estimation is essential to maintain optimal conditions during injection and production operations. A series of data, including rock mechanical test data, well logs data, formation dynamic tester data, image logs data, leak-off tests (LOTs), drilling events, and regional geological studies were used in this work. In this study, a coupled geomechanical-fluid flow model was constructed to evaluate the cap-rock integrity during the injection-production scenario. The steps of the investigation are data audit, 1-D mechanical modeling (MEMs), 3D rock mechanical properties modeling, and 4D geomechanical simulation using a one-way coupling method. The results showed that throughout the production and injection scenario, the cap-rock was stable. Since there is a long distance between Mohr's circle and the envelope, the cap-rock will not fail. Due to the low permeability of the cap-rock, there is no connection between its pore spaces, which leads to ignoring the variation in stress state due to variations in reservoir pressure.

In the process of oil recovery, after the initial oil recovery process, a considerable amount of oil remains in oil reservoirs. Enhanced oil recovery methods are used to extract residual oil of reservoirs. Various methods are used to improve oil recovery, one of which is the injection of nanofluids instead of water injection. In this study, a numerical study has been considered to determine the effect of various nanomaterials on the improvement of oil recovery. Various nanoparticles have been included, and their major impacts on the factors affecting oil extraction are also presented. The black oil model has been used to study the numerical effect of the nanoparticles on oil extraction. A mixture of different metal oxides nanoparticles such as Al2O3, TiO2 and SiO2, and water as nanofluids is used as an aqueous phase in solving problems. Mass balance and momentum balance equations of nanofluids are solved numerically. In this study, the effect of temperature changes, nanoparticle concentration, nanofluid density, size and density of solid particles of nanoparticles on oil recovery, interfacial tension, and pore pressure variations have been examined.According to the results presented in this study, the addition of nanoparticles reduces the amount of suction and interfacial tension and also increases the amount of oil extraction by about 10%. By increasing the concentration of nanomaterials in the base solution, the amount of oil extraction increases by average 10%. The effect of the size and density of solid particles of nanoparticles on the amount of oil extraction is considerable, and the variations of these parameters also result in a change in oil extraction and increase the amount of oil recovery by about 5 to 8 percent.

In this study, an eniched element free Galerkin framework is developed to investigate the effects of conductive-convective heat transfer on hydraulic fracturing. Weak and strong discontinuities are introduced in field variables using the enrichment strategy. The cohesive crack model is used in this study to simulate the process of initiation and propagation of fractures in saturated deformable porous media. The complicated process of hydraulic fracturing with thermal effects is simulated considering multiple components including fluid flow within the fracture, fluid flow through the host medium, fluid leak-off from the fracture into the surrounding porous rock, heat transfer within the fracture medium, heat transfer through the host porous rock, the heat exchange between the crack medium and the surrounding media, deformation of porous rock due to the hydraulic and thermal loading and crack propagation. To create the discrete equation system, Galerkin technique is applied, and the essential boundary conditions are imposed via penalty method. Then, the resultant constrained integral equations are discretized in space using EFG shape functions. For temporal discretization, a fully implicit scheme is employed. The final set of algebraic equations that form a non-linear equation system are solved using the iterative Newton-Raphson procedure. Numerical simulation results show the accuracy of the formulation as well as the performance of the program in coupling the heat transfer equation inside the crack with other governing equations.

This paper presents a control volume finite element model (CVFEM) to simulate simultaneous flow of two immiscible fluids in non-deformable porous media. The method is fully conservative at the local and global level. It keeps the data structure of the common finite element method (FEM). A pressure-based formulation is presented in this paper. The proper choice of primary unknown variables is a critical step in developing an efficient solution of the multiphase subsurface flow problems. Pressure-based models are one of the common choices to this end. This type of models consists of strong nonlinear terms and encounters convergence difficulties when the Jacobian matrix are poorly approximated. The most severe problem is related to the relative permeability term that appears as a function of volume fraction (or degree of saturation) of the wetting phase. Since water saturation is not a primary unknown variable, the relative permeability terms become a function of two primary unknowns, i.e. wetting and non-wetting pressures, together. A fully implicit first order accurate finite difference scheme is employed for temporal discretization of the equations. A full Newton method with exact Jacobian is considered in this work, and a rapid convergence has been achieved. The model is used to simulating a five-spot problem in a block heterogenous porous medium.