Summary The exploitation of unconventional gas reservoirs has become an ever increasing component of the North American gas supply. The economic viability of many unconventional gas developments hinges on effective stimulation of extremely low-permeability rock by creating very complex fracture networks that connect huge reservoir surface area to the wellbore. In addition, gas desorption may be a significant component of overall gas recovery in many shale-gas reservoirs. The widespread application of microseismic (MS) mapping has significantly improved our understanding of hydraulic fracture growth in unconventional gas reservoirs (primarily shale) and has led to better stimulation designs. However, the overall effectiveness of stimulation treatments is difficult to determine from MS mapping because the location of proppant and the distribution of conductivity in the fracture network cannot be measured (and are critical parameters that control well performance). Therefore, it is important to develop reservoir-modeling approaches that properly characterize fluid flow in and the properties of a complex fracture network, tight matrix, and primary hydraulic fracture (if present) to evaluate well performance and understand critical parameters that affect gas recovery. This paper illustrates the impact of gas desorption on production profile and ultimate gas recovery in shale reservoirs, showing that in some shale-gas reservoirs desorption may be a minor component of gas recovery. In addition, the paper details the impact of changing closure stress distribution in the fracture network on well productivity and gas recovery. In shale-gas reservoirs with lower Young's modulus rock, stress-dependent network-fracture conductivity may reduce ultimate gas recovery significantly. The paper includes an example that contrasts the application of numerical reservoir simulation and advanced decline-curve analyses to illustrate issues associated with conventional production-data-analysis techniques when applied to unconventional reservoirs. Selected examples from the Barnett shale are included that incorporate MS fracture mapping and production data to illustrate the application of production modeling to evaluate well performance in unconventional gas reservoirs. This paper highlights production modeling and analysis techniques that aid in evaluating stimulation and completion strategies in unconventional gas reservoirs.

The exploitation of unconventional gas reservoirs has become an ever increasing component of North American gas supply. The economic viability of many unconventional gas developments hinges on effective stimulation of extremely low permeability rock by creating very complex fracture networks that connect huge reservoir surface area to the wellbore. In addition, gas desorption may be a significant component of overall gas recovery in many shale-gas reservoirs. The widespread application of microseismic mapping has significantly improved our understanding of hydraulic fracture growth in unconventional gas reservoirs (primarily shale) and led to better stimulation designs. However, the overall effectiveness of stimulation treatments is difficult to determine from microseismic mapping, as the location of proppant and distribution of conductivity in the fracture network cannot be measured (and are critical parameters that control well performance). Therefore it is important to develop reservoir modeling approaches that properly characterize fluid flow in and the properties of a complex fracture network, tight matrix, and primary hydraulic fracture (if present) to evaluate well performance and understand critical parameters that affect gas recovery. The paper illustrates the impact of gas desorption on production profile and ultimate gas recovery in shale reservoirs, showing that in some shale-gas reservoirs desorption may be a minor component of gas recovery. In addition, the paper details the impact of changing closure stress distribution in the fracture network on well productivity and gas recovery. In shale-gas reservoirs with lower Young's modulus rock, stress dependent network fracture conductivity may significantly reduce ultimate gas recovery. The paper includes an example that contrasts the application of numerical reservoir simulation and advanced decline curve analyses to illustrate issues associated with conventional production data analysis techniques when applied to unconventional reservoirs. Selected examples from the Barnett shale are included that incorporate microseismic fracture mapping and production data to illustrate the application of the production modeling to evaluate well performance in unconventional gas reservoirs. This paper highlights production modeling and analysis techniques that aid in evaluating stimulation and completion strategies in unconventional gas reservoirs. Introduction Gas shales are organic-rich shale formations and are apparently the source rock as well as the reservoir. The gas is stored in the limited pore space of these rocks and a sizable fraction of the gas in place may be adsorbed on the organic material. The natural gas resource potential for gas shales in the USA is estimated to be from 500 to 1,000 Tcf (Arthur 2008). Typical shale gas reservoirs exhibit a net thickness of 50 to 600 ft, porosity of 2–8%, total organic carbon (TOC) of 1–14% and are found at depths ranging from 1,000 to 13,000 ft. The success of the Barnett Shale has illustrated that gas can be economically produced from rock that was previously thought to be source and/or cap rock, not reservoir rock. This revelation has led to the development of many other shale-gas reservoirs, including the Woodford, Fayetteville, Marcellus, and the Haynesville (Figure 1). Besides increasing natural gas prices (until recently), the economic development of many shale reservoirs was made possible through improved stimulation techniques and horizontal drilling.

Unconventional shale gas reservoirs require stimulation via hydraulic fracturing of pre-existing fracture networks for practical exploitation, creating a stimulated reservoir volume (SRV). Within the SRV, gas flow from the nano-Darcy shale to the complex stimulated fracture network has been modeled in reservoir simulators using a variety of techniques which upscale/simplify the fracture network. The simulation techniques used in the past were normally not compared with reference solutions. This work investigates using finely-gridded single well reference solutions (approximately 6-14 million cells) for simulating Darcy and non-Darcy flow within an explicitly modeled SRV complex fracture network, in 2-D, with and without primary hydraulic fractures, as well as scenarios which model stress sensitive permeability and later re-stimulation of a horizontal well. The network fractures use cells which are only 0.001 ft. wide. The reference solutions are compared with standard dual permeability and MINC (multiple interacting continua) dual continua models as well as novel models which simulate flow inside of the SRV using coarse, logarithmically spaced, locally refined, dual permeability grids, and simulate flow outside of the SRV using unrefined dual permeability grids. These coarse models can be run in minutes on standard hardware, where as the reference models can take days to run on the same hardware. We will show that excellent matches to the reference solutions are possible using a modest number of refinements to simulate the flow within the SRV when the fracture permeability and the fracture Forchheimer number (for non-Darcy flow) are scaled as described in the paper. These techniques allow the use of 2.0 ft. wide fracture conduits to mimic non-Darcy flow in 0.001 ft. wide fractures. Good agreement between the reference and coarse models are observed even during the early flow period of the reservoir.

This paper describes a fully implicit four-phase (oil, water, gas, solid fuel) numerical reservoir model for simulating hot water injection, steam injection, dry combustion, and wet combustion in one, two, or three dimensions and in either a Cartesian, radial, or curvilinear geometry. The simulator rigorously models fluid flow, heat transfer (convective and conductive), heat loss to formation, fluid vaporization/condensation, and chemical reactions. Any number of oil or gas phase components may be specified, along with any number of solid phase components (fuel and catalysts).The simulator employs either D4 Gaussian elimination or powerful incomplete factorization methods to solve the often poorly conditioned matrix problems. An implicit well model is coupled to the simulator, where reservoir unknowns and well block pressures are primary variables.This paper includes (1) comparisons of the numerical model's results with previously reported laboratory physical models' results for steam and combustion and (2) analytical solutions to a hot waterflood problem. In addition, an actual field-scale history match is presented for a single-well steam stimulation problem.

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