This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125532, ’Modeling Well Performance in Shale-Gas Reservoirs,’ by C.L. Cipolla, SPE, Carbo; E.P. Lolon, SPE, StrataGen Engineering; and J.C. Erdle, SPE, and V. Tathed, SPE, CMG, prepared for the 2009 SPE/EAGE Reservoir Characterization and Simulation Conference, Abu Dhabi, UAE, 19-21 October 2009. The paper has not been peer reviewed. This paper focuses on modeling well performance in shale-gas reservoirs by use of numerical simulation. Stimulation treatments in many shale-gas reservoirs create very complex fracture networks. These fracture networks are required to achieve economic production rates from rock with a matrix permeability as low as 10 nanodarcies. The primary issues with modeling production from shale-gas reservoirs are describing gas flow from the tight shale matrix into the fracture network accurately, properly characterizing the matrix-block size (or fracture density) and the conductivity of the network fractures, and evaluating effects of stress-sensitive network-fracture conductivity and gas desorption. Introduction Gas shales are organic-rich formations that are both source rock and reservoir. Gas is stored in the limited pore space of these rocks, with a sizable fraction of the gas in place possibly adsorbed on the organic material. Typical shale-gas reservoirs exhibit a net thickness of 50 to 600 ft, have porosity of 2 to 8% and total organic carbon of 1 to 14%, and are found at depths of 1,000 to 13,000 ft. The success of the Barnett shale in the USA has illustrated that gas can be produced economically from rock that was previously thought to be source rock and/or caprock, not reservoir rock, leading to the development of many other shale-gas reservoirs, including the Woodford, Fayetteville, Marcellus, and Haynesville. The economic viability of many unconventional gas developments requires effective stimulation of extremely low-permeability rock, typically 0.0001 to 0.00001 md. In most cases, economic production is possible only if a very complex, highly nonlinear fracture network can be created that effectively connects a large reservoir surface area to the wellbore. Many conventional hydraulic-fracture treatments use high-viscosity fluids to reduce fracture complexity and promote planar fractures, allowing the placement of high concentrations of large proppant. However, stimulation treatments in shale reservoirs use large volumes of low-viscosity fluid (water) to promote fracture complexity and place very low concentrations of small proppant. Hydraulic-fracture treatments in horizontal wells can require several million gallons of water and up to 1 million lbm of proppant pumped at rates of 75 to 150 bbl/min.