Fractures play an important role in geothermal reservoir engineering as they dominate the fluid flow in the reservoir. Because of this reason determination of fracture permeability is very important to predict the performance of the geothermal reservoir. A fracture is usually assumed as a set of smooth parallel plates separated by a constant width. The absolute permeability of a smooth-walled fracture is related to the fracture aperture using the cubic law. However, the flow characteristics of an actual fracture surface would be quite different, affected by tortuousity and surface roughness. Though several researchers have discussed the effect of friction on flow, a unified methodology for studying flow on a rough fracture surface has not emerged. As experimental methods are expensive and time consuming most of the time numerical methods are used. In this work, we present results of the numerical computations for single phase flow simulations through two-dimensional synthetically created fracture apertures. These synthetic rock fractures are created using different fractal dimensions, anisotropy factors, and mismatch lengths that are obtained from the producing geothermal reservoirs in South Western Turkey. Lattice Boltzmann Method, which is a new computational approach suitable to simulate fluid flow especially in complex geometries, was then used to determine the permeability for different fractures. Regions of high velocity and low velocity flow were identified. The resulting permeability values were less than the ones obtained with the cubic law estimates. It has been found that as the mean aperture-fractal dimension ratio increased permeability increased. Moreover as the anisotropy factor increased permeability decreased with a second order polynomial relationship.

Liquid-rich shale reservoirs contribute immensely to the United States oil and gas production. Because Bakken, Lower Eagle Ford, and Niobrara formations have different mineralogy, pore structure, organic content, and fluid compositions, it is critical to differentiate the unique characteristics of each formation for field development and oil and gas production. The latter information is also useful in well stimulation design and hydraulic fracturing. This paper presents an experimental study of mineralogy, pore-size distribution, pore geometry, and spatial correlation between minerals and pores to identify the effect of micro-scale properties on flow behavior. Porosity and permeability of several core samples from the Middle Bakken, Lower Eagle Ford, and Niobrara formations were studied and the results, using mercury injection capillary pressure (MICP), X-Ray diffraction (XRD), and scanning electron microscopy (SEM), were shown. Finally, a workflow that estimates cementation factor combining the results obtained from MICP measurements and GRI crushed core analysis will be presented.

Changes in reservoir pore pressure and temperature during injection or production affect rock deformation, which, in turn, causes alteration of porosity and permeability. Specifically, an increase in pore pressure (or a decrease in rock temperature) can create significant rock deformation and increase of the shear stress that could lead to rock fracturing and microseismic activity in the reservoir. Furthermore, porosity and permeability of rocks decrease because of the pore pressure decrease during depletion. Thus, stress-dependent deformation in hydrocarbon bearing shale formations affects the production decline trends. This paper addresses these issues and presents a computationally efficient in-house numerical simulator for poroelastic dual-porosity reservoirs. The governing transport equations for the fluid flow and rock deformations use two interacting environments consisting of a continuous fracture medium and a discontinuous rock matrix medium. The transport and rock deformation equations are fully-coupled and solved numerically using a stationary coordinate frame. A proper assignment of rock frame modulus, affected by the interconnected fractures, versus the rock matrix modulus is a major focus of this work. The rock frame modulus is smaller than the matrix modulus. The numerical model is compared to a single-phase model and validated with a closed form of analytical solutions. We used field data from a fractured unconventional reservoir to assess our formulation. The field data includes flow rates and pressures during an extended production period in the Bakken formation, Williston basin in North Dakota. Finally, we conducted a sensitivity analysis to determine the effect of bulk rock deformation on reservoir performance as compared to conventional engineering approaches which utilize pore compressibility without accounting for the bulk rock deformation.

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In reservoir evaluation of unconventional reservoirs, engineers use rate transient analysis (RTA) to assess the performance of hydraulically fractured horizontal wells. This technique consists of plotting rate- normalized pressure drop at the well sandface versus square root of time (i.e., linear flow) to calculate the reservoir effective permeability. In this paper, we report on the use of an in-house multiphase numerical simulator applied to production data from several Eagle Ford wells to assess both single- and multi-phase production performance. Furthermore, a combination of numerical simulation and analytical solution techniques was used to validate the information obtained from the RTA in the Eagle Ford wells. This procedure further improved our insight into the flow behavior of unconventional reservoirs. The multi-phase effective permeability calculated from the RTA was within a few percent of the input data to the numerical model. Furthermore, the multi-phase RTA results produce more accurate than the conventional single-phase RTA approach; and the multi-phase analysis results were more in line with the well performance observations than with when using the single-phase analysis approach. Furthermore, the multiphase results were more consistent with the success or failure of the hydraulic fracturing process.