Abstract
Abstract
This paper examines issues with forecasting and evaluating production from unconventional gas reservoirs, such as the Barnett Shale. How can reservoirs be commercial with matrix permeability measured not in milli-Darcy or even micro-Darcy (10-3 mD), but as low as 10–100 nano-Darcy (10-6 mD)? The key is maximizing the reservoir area that is connected to the wellbore by creating a very large man-made fracture network. But how do we create a fracture network? The answer is large volume, high rate hydraulic fracture treatments using water and small-mesh proppant to activate or stimulate the existing natural fractures or rock fabric. The fractures created are far from the classic planar model; they are large complex flow networks that typically encompass more than 50 acres where the rock has been broken. For a given matrix permeability and pressure, gas production will be determined by the number and complexity of fractures created, their effective conductivity (kfwf), and the ability to effectively reduce the pressure throughout the fracture network to initiate gas production. Understanding the relationship between fracture complexity, fracture conductivity (kfwf), matrix permeability, and gas recovery is a fundamental challenge of shale-gas development. This paper highlights the application of reservoir simulation to model production in shale-gas reservoirs, providing significant insights into these relationships that can improve stimulation designs, completion practices, and field development strategies.
Characterizing the relative conductivity of the fracture network and primary fracture are critical to evaluating stimulation performance. Because of the uncertainty in matrix permeability and network fracture spacing (i.e., complexity), it is difficult to find unique solutions when modeling production from unconventional gas reservoirs. The paper demonstrates the application of numerical reservoir simulation and contrasts this approach with advanced decline curve analyses to illustrate issues associated with conventional production data analysis techniques when applied to unconventional reservoirs. The paper examines the effect of conductivity distribution within complex fracture networks, complexity of the fracture network, and permeability of the rock matrix on well productivity and gas recovery. It also illustrates the effect of gas desorption on the production profile and the ultimate gas recovery from shale reservoirs.
The paper presents selected examples from the Barnett Shale that incorporate microseismic fracture mapping and production data to illustrate real-world applications of the production modeling to evaluate well performance in unconventional gas reservoirs. Currently, most shale gas resources are developed using horizontal wells, and the reservoir simulations in this paper focus on horizontal completions. This paper highlights production modeling and analysis techniques that aid in identifying stimulation and completion strategies that may significantly improve production rates and ultimate recovery from unconventional gas reservoirs.
Introduction
The exploitation of unconventional gas reservoirs has become an ever-increasing component of North American gas supply, and there is increasing interest in the potential of international shale gas plays. Gas shales are organic-rich shale formations that serve as the hydrocarbon source rock and as the reservoir. In addition to the gas stored in the limited pore space of these rocks, a sizable fraction of the gas in place may be adsorbed on the organic material. The success of the Barnett Shale has led to the development of other shale plays in North America, such as the Woodford, Haynesville, Fayetteville, and Marcellus. The natural gas resource potential for gas shales is estimated to range from 500 to 1,000 Tcf in the USA (Arthur et al. 2008). Typical shale gas reservoirs exhibit a net thickness of 50 to 600 ft, porosity of 2 to 8%, total organic carbon (TOC) of 1 to 14% and are found at depths ranging from 1,000 to 13,000 ft. Although each shale reservoir poses unique challenges, this paper summarizes examples from the Barnett Shale because the reservoir is better understood and because the fracture geometry has been evaluated by means of microseismic mapping. The Barnett Shale is found at depths of 6,500 to 8,500 ft, with 100 to 600 ft of net thickness, 4 to 5% total porosity, 4.5% TOC, basin size of 5,000 square miles (3.2 million acres), and OGIP of 50 to 200 bcf per square mile. Typical Barnett well spacing ranges from 60 to 160 acres with estimated ultimate gas recovery of approximately 1 to 5 bcf per well.