Reservoir Modeling in Shale-Gas Reservoirs

Abstract

Abstract 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.