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The Jurassic carbonate reservoirs in Minagish Field of West Kuwait have undergone significant pressure depletion (up to 4,000 – 5,000 psi) over the last two decades. However, during the last few years at least two wells showed sudden and significant reservoir pressure increase despite no injection in the reservoir for pressure support. The asset team plans to develop these reservoirs with more horizontal wells in order to increase the reservoir contact and thereby productivity and reservoir recovery. However, drilling and deepening the infill development wells in this area is becoming increasingly challenging due to uneven differential depletion across the field. Unprecedented drilling complications including mud-loss, well kicks, and differential sticking are observed. This paper discusses how a field scale 3D reservoir geomechanical model integrating all available data was built and used to evaluate the impact of production induced stress changes on reservoir behaviour. Furthermore it details how geomechanical characterization provided inputs for the field development planning. The dynamic 3D reservoir geomechanical modelling of this field integrated: the structural geological model, well based 1D geomechanical models, rock mechanical test results from core, production data, reservoir simulation model as well as selected petrophysical and geophysical data. This model was initially built at original reservoir pressure. After proper assignment of both stratigraphically verified mechanical properties and boundary conditions of far field stresses, the finite element stress simulator was utilized to establish a representative initial stress state within the reservoir and its surrounding formations. The history matched and future predicted reservoir pressures at various time steps were coupled to the finite element mechanical simulator to map the changed stresses and strains over the reservoir interval. The finite element analysis helped to investigate the associated changes of the in-situ stress field, pore pressure and rock properties across the field and specifically around the planned wells in order to capture the 3D effect of reservoir depletion such as arching effects. This analysis improved the field development planning by integrating wellbore stability risk assessment, fault slippage and other related aspects. The 3D Geomechanical model also distributed the shear-to-normal stress ratios over the interpreted faults/fractures and explained the dynamic behaviour of certain faults due to depletion. Field scale distribution of in-situ stress changes provided inputs to risk assessment due to further depletion. Understanding the stress induced response of reservoir due to depletion helped to plan new infill wells in due consideration of geomechanical risks and production efficiency. The 3D Geomechanical modelling approach demonstrated that it is technically feasible to incorporate the complexity of 3D geological structure of a reservoir, fault network and other variables within the in-situ stress field. Using appropriate modelling simulations with realistic in-situ conditions, it was possible to explain the behaviour of pressure in wells, faults and also wellbore stability risks.

The evaluation of shale is complicated by the structurally heterogeneous nature of fine-grained strata and their intricate pore networks, which are interdependent on many geologic factors including total organic carbon (TOC) content, mineralogy, maturity and grain-size. The ultra-low permeability of the shale rock requires massive hydraulic fracturing to enhance connectivity and increase permeability for the flow. To design an effective fracturing technique, it is necessary to have a good understanding of the reservoir characteristics and fluid flow properties at multiple scales. In this work, representative core plug samples from a tight carbonate source rock in the Middle East were characterized at the core- and pore-scale levels using a Digital Rock Physics (DRP) workflow. The tight nature of the carbonate rocks prevented the use of conventional methods in measuring special core analysis (SCAL) data. Two-dimensional Scanning Electron Microscopy (SEM) and three-dimensional Focused Ion Beam (FIB)-SEM analysis were studied to characterize the organic matter content in the samples together with (organic and inorganic) porosity and matrix permeability. The FIB-SEM images in 3D were also used to determine petrophysical and fluid flow (SCAL) properties in primary drainage and imbibition modes. A clear trend was observed between porosity and permeability related to identified rock fabrics and organic matter in the core. The organic matter was found to have an effect on the imbibition two-phase flow relative permeability and capillary pressure behavior and hysteresis trends among the analyzed samples. The data obtained from DRP provided information that can enhance the understanding of the pore systems and fluid flow properties in tight formations, which cannot be derived accurately using conventional methods.