Characterization of shale gas stimulation and production mechanisms is of paramount importance to continued horizontal well hydraulic fracture stimulation design and execution. This study integrates analyses of fracture calibration tests, hydraulic fracture treatments, production logs, pressure buildup and well interference transients, and long term production data to quantify hydraulic fracture extent, shale permeability, and the expected ultimate recovery.The study includes integrated analysis of 16 horizontal wells drilled from a pad in two opposing directions with mostly uniform length and spacing. Uncertainties in the hydraulic fracture and formation properties are reduced through rigorous modeling with analytical and numerical models. Results enable critical analysis of the shale development plan.Recommendations from this study offer insight on stimulation design modifications to yield improved well performance and increased recovery efficiency within the pad stimulated volume defined by the wells.
Successful development of shale gas reservoirs is highly dependent on hydraulic fracture treatments. Many questions remain in regards to the geometry of the created fractures. Production data analysis from some shale gas wells quantifies a much smaller This study examines hydraulic fracturing of shale gas formations with specific interest in fracture geometry. Several field cases are analyzed using microseismic analysis as well as net pressure analysis of the fracture treatment. Fracture half lengths implied by microseismic events for some of the stages are several thousand feet in length. The resulting dimensions from microseismic analysis are used for calibration of the treatment model. The fracture profile showing created and propped fracture geometry illustrates that it is not possible to reach the full fracture geometry implied by microseismic given the finite amount of fluid and proppant that was pumped. The model does show however that the created geometry appears to be much larger than half the well spacing. From a productivity standpoint, the fracture will not drain a volume more than that contained in half of the well spacing. This suggests that for the case of closely spaced wells, the treatment size should be reduced to a maximum of half the well spacing.iii This study will provide a framework for understanding hydraulic fracture treatments in shale formations. In addition, the results from this study can be used to optimize hydraulic fracture treatment design. Excessively large treatments may represent a less than optimal approach for developing these resources.iv DEDICATION This thesis is dedicated to my family who encouraged me to pursue graduate studies and supported me throughout my education.v ACKNOWLEDGEMENTS
This paper presents a new integrated workflow that couples geology, geomechanics and geophysics (3G) with a constrained asymmetric frac model as applied to a Wolfcamp well to address the concerns of well interference. The proposed workflow enables the ability to adapt the frac design of each stage based on the in-situ geologic and geomechanical variability. The objective of this approach is to identify the variable treatment parameters required to overcome the stress heterogeneity and estimate the impact of the adaptive frac design on the final fracture geometry. The lateral stress gradients resulting from the pressure depletion due to a nearby producing well and the fluid leak-off due to opening of natural fractures are fine-tuned to account for asymmetry observed in the geomechanical modeling. The role of the natural fractures is emphasized and practical approaches to estimate a validated natural fracture model are described and illustrated. A validation well is used to highlight the importance of the input natural fracture model in calculating validated differential stress and strain that reproduce the main features of the microseismic. With this validated strain model, a constrained frac design provides the proper asymmetric fracture geometry able to pinpoint the poor and good frac stages. Once the workflow is extensively validated, it can be used on target wells to avoid frac hits. In this Wolfcamp example, the challenge was to find the optimal frac design to minimize interference of an infill well with existing offset producers. To address the possible zones of interference, the stage spacing was locally increased to 152 m (500 ft), and the treatment was especially modified in the middle stages of the well. This resulted in reducing the number of stages from 40 to 34, specifically in zones indicating high probability of interference. The design was altered from pumping a mixture of 320,000 lb of 100 mesh and 40/70 mesh sand to 220,000 lb of 40/70 mesh sand, and the injected fluid viscosity was increased from 10 centipoise (cP) for slick water to 30 cP for linear gel as better carrying capacity was required to pump only 40/70 mesh sand. Additonally, the injection rate was reduced from 105 bbl/min to 80 bbl/min. The integrated approach allows for the ability to adapt the frac design to in-situ conditions including heterogeneity in the stress fields and the pressure depletion from existing producers. Adaptive frac design significantly reduces the probability of frac hits and well interference. The proposed modeling workflow enables greater investment efficiency and overall field development optimization.
Predictable well performance is a key factor for the economic development of unconventional reservoirs including tight sands, tight carbonates and shales. A factory approach to developing unconventional reservoirs has resulted in unpredictable and highly variable well performance, much of which has been uneconomic. Minimizing the uncertainty in production forecasting and reservoir simulation necessitates an accurate model, which captures the interaction of induced hydraulic fractures with existing natural fractures. One method to achieve this is by using a 3G workflow, which leverages the synthesis of geophysical and geological information through geomechanical techniques to model the hydraulic fracturing of unconventional reservoirs. A complete workflow is presented for modeling and simulation of unconventional reservoirs, which incorporates the characterization of natural fractures and their interaction with hydraulic fracture stimulation. The 3G workflow is applied to an unconventional well in the Wolfcamp Shale, Permian Basin. The geomechanical modeling results are exported to a standard commercial numerical reservoir simulator using two different approaches; strain volume and constrained asymmetric hydraulic fractures. A third reservoir simulation case is created in which commonly used symmetric hydraulic fractures are generated without any external geomechanical model. An automated history matching tool is used to find the hydraulic fracture parameters for this over simplistic and unrealistic case. The production forecast and pressure depletion profiles are compared for all three cases. The proposed unconventional modeling workflow is not only fast but also significantly reduces uncertainty in the reservoir simulation results, improving reliability of the production forecast as well as the pressure depletion profile. These constrained simulations provide the information necessary to make better decisions in field development planning.
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