Unconventional reservoirs such as gas shales and tight gas sands require technology-based solutions for optimum development. The successful exploitation of these reservoirs has relied on some combination of horizontal drilling, multi-stage completions, innovative fracturing and fracture mapping to engineer economic completions. However, the requirements for economic production all hinge on the matrix permeability of these reservoirs, supplemented by the conductivity that can be generated in hydraulic fractures and network fracture systems. Simulations demonstrate that ultra-low shale permeabilities require an interconnected fracture network of moderate conductivity with a relatively small spacing between fractures to obtain reasonable recovery factors. Microseismic mapping demonstrates that such networks are achievable and the subsequent production from these reservoirs supports both the modelling and the mapping. Tight gas sands, having orders of magnitude greater permeability than the gas shales, may be successfully depleted without inducing complex fracture networks, but other issues of damage and zonal coverage complicate recovery in these reservoirs. As with the shales, mapping has proved itself to be valuable in assessing the fracturing results. Introduction Unconventional reservoirs provide a significant fraction of gas production in North America and increasing amounts in some other regions of the world. Such reservoirs include tight gas sands, coalbed methane (CBM), and gas shales; in 2006 these reservoirs provided 43% of the US production of natural gas [Kuuskraa(1)]. Because of their limited permeability, which is foremost among many other complexities, some type of stimulation process (and/or dewatering in the case of CBM) is required to engender economic recovery from wells drilled into these formations. The focus of this paper is on gas shales, with particular emphasis on how these reservoirs perform relative to tight gas sands. The important role of natural fractures in both the stimulation and production processes, the importance of conductivity in the developed fracture or fracture system, and the critical influence of the matrix permeability are investigated using both mapping and modeling results.
Fracture-calibration pressure decline has been used for determination of the leakoff coefficient, a bulk variable describing the process of fluid influx into the reservoir, normal to the created fracture face. In this work, the fluid loss is modeled in terms of the controlling mechanisms: flow through the filter cake, the invaded zone, and the reservoir. A rigorous model describes unsteady-state fluid flow from fractures of varying area into the formation, with the filter cake considered as a time-and rate-dependent skin effect. The injection history is superposed on the pressure decline. This work provides a straight-line technique for determination of reservoir permeability and fracture-face resistance. Log-log diagnostic plots provide the means to recognize visually whether the transient response is dominated by flow in the reservoir or at the fracture face. We found that the pressure transient very frequently is dominated by the flow in the reservoir rather than through the filter cake. The reservoir permeability (an essential value for fracture design that is usually not available) can be estimated, while the model captures all trends of the falloff-pressure variation.
This paper presents case histories and field data that detail the application of well test data to calibrate fracture models, understand fracture performance, and optimize treatment designs. The paper includes field results from gas reservoirs in the Rocky Mountains and west Texas. The case histories also illustrate the application of postfracture pressure-buildup data to identify reasons for fracture treatment problems and to confirm treatment success. The paper also includes a novel data set that illustrates fracture performance from a liquid CO2 stimulation (no sand, no water) in west Texas. The case histories illustrate the importance of integrating well test data with fracture treatment optimization, showing how this process can improve our ability to reliably make multimillion-dollar decisions concerning proppant selection and fracture treatment size.
For data from fracture calibration treatments a methodology is introduced for the determination of the reservoir permeability as an addition to the usual variables of leakoff coefficient and closure pressure. The technique derives from the solution of the diffusivity equation for a well with an infinite-conductivity vertical fracture (as a multi-rate injection) with a superimposed varying filtercake skin effect. The transient reservoir response, which is found to be the essential feature, is then decoupled and used to determine the reservoir permeability.
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