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.
Summary In unconventional reservoirs, production data are generally analyzed by use of rate-transient techniques derived from single-phase linear-flow models. Such linear-flow models use rate-normalized pressure, which is pressure drop divided by reservoir-flow rate vs. square root of time. In practice, the well-fluid production includes water, oil, and gas. The oil can be light oil, volatile oil, and gas/condensate as in the Bakken, Eagle Ford, and Barnett, respectively. Thus, single-phase analysis needs modification to account for production of fluid mixtures. In this paper, we present a multiphase-pressure-diffusivity equation to analyze multiphase flow in single- and dual-porosity models of unconventional reservoirs. Our approach is similar to the work presented by Perrine (1956); however, our approach has a theoretical foundation, whereas Perrine (1956) used pragmatic engineering analogy for constant flow rate in vertical wells only. In addition to oil, gas, and formation brine, our method accounts for gas/condensate production, and the flowback of the injected hydraulic-fracturing fluids. Overall, our proposed approach is more comprehensive than the single-phase models but maintains the simplicity of the conventional methods. Our paper includes diagnostic plots of rate-normalized well pressure for light oils and gas/condensates in unconventional reservoirs. Data from two Bakken and two Eagle Ford wells will be presented to demonstrate the usefulness of our approach. In addition to the mathematical analysis of flow-rate and pressure data, we will present the effect of well-stimulation and fluid-lift methods on the flow-rate characteristics of Bakken and Eagle Ford wells.
Compressed-air energy storage (CAES) stores energy as compressed air in underground formations, typically salt dome caverns. When electricity demand grows, the compressed air is released through a turbine to produce electricity. CAES in the United States is limited to one plant built in 1991, due in part to the inherent risk and uncertainty of developing subsurface storage reservoirs. As an alternative to CAES, we propose using some of the hundreds of thousands of hydraulically fractured horizontal wells to store energy as compressed natural gas in unconventional shale reservoirs. To store energy, produced or “sales” natural gas is injected back into the formation using excess electricity and is later produced through an expander to generate electricity. To evaluate this concept, we performed numerical simulations of cyclic natural gas injection into unconventional shale reservoirs using CMG-GEM commercial reservoir modeling software. We tested short-term (diurnal) and long-term (seasonal) energy storage potential by modeling well injection and production gas flow rates as a function of bottom-hole pressure. First, we developed a conceptual model of a single fracture stage in an unconventional shale reservoir to characterize reservoir behavior during cyclic injection and production. Next, we modeled cyclic injection in the Marcellus shale gas play using published data. Results indicate that Marcellus unconventional shale reservoirs could support both short- and long-term energy storage at capacities of 100-1,000 kWe per well. The results indicate that energy storage in unconventional shale gas wells may be feasible and warrants further investigation.
A significant fraction of the world gas needs is supplied from gas-condensate reservoirs. The well productivity of these reservoirs is compromised because of liquid condensation in the matrix and fracture. The Sabriyah field is the first successful exploration in the North of Kuwait which led to the discovery of six extensive, deep, tight gas-condensate reservoirs. A purely fracture-dominated unconventional resource play, Najmah-Sarelu formation, is considered the source for most of the reservoirs in the Sabriyah field. In this paper, a compositional, multi-phase, dual-porosity model was used to analyze an existing horizontal well performance, and to evaluate potential enhancements to the future production. The Sabriyah gas-condensate field in North of Kuwait is an abnormally high-pressure tight reservoir, which has very low matrix permeability and porosity. In this study, the geological system of Sabriyah field was studied using a static model to decipher the complexity of the reservoir—especially, the Najmah-Sarelu formation. A well's performance was analyzed using history-matching of the production data using a multi-component compositional dual-porosity model. To assess potential enhancement of the future production, eight different scenarios were studied. Specifically, we extended the current horizontal well length and added several multi-stage hydraulic fractures to increase production. To assess the flow behavior of gas-condensate in Sabriyah field, we began with a study that tied the reservoir geology to the performance of a typical well using both static and dynamic simulation models. Both pressure build up and production data were analyzed using pressure and rate transient techniques which yielded an effective formation permeability of 0.5 to 0.6 mD. The numerical modeling parameters achieved a successful history match for one year of production, and the sensitivity analysis demonstrated that producing at a pressure of slightly below the dew point yielded the largest amount of condensate production. In particular, the additional condensate production was twenty-two percent for this case. Also, we observed that the existing horizontal well performed as effectively as having three-stage hydraulically fractured well in a matrix-dominated situation because of the presence of existing natural fractures replace the effect of the multi-stage fracturing.
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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