Defining Horizontal-Well Objectives in Unconventional and Tight Gas Reservoirs

Abstract

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137839, ’Defining Horizontal-Well Objectives in Tight and Unconventional Gas Reservoirs,’ by L.K. Britt, SPE, J.R. Jones, SPE, and W.K. Miller II, SPE, NSI Fracturing, prepared for the 2010 Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed. Because unconventional and tight-formation gas reservoirs have poorer-quality pay, a well-planned completion and fracture-stimulation program is required to obtain an economical well. Economic-optimization studies for tight gas reservoirs highlight the importance of lateral length, number of fractures, interfracture distance, fracture half-length, and fracture conductivity. A horizontal-well decision tree was developed for evaluating the various drilling, completion, and stimulation issues encountered with horizontal wells in unconventional and tight-formation gas reservoirs. Introduction Operators have reported difficulty in fracture stimulating some deviated and horizontal wells. The difficulties are associated with increased treating pressures and elevated post-fracture instantaneous shut-in pressures. In unconventional and tight-formation gas reservoirs, greater operational control and reliability are necessary to maintain project economics. Optimization studies of these reservoirs showed the importance and value of integrating horizontal drilling, completion, and well-stimulation practices. To understand the horizontal-well objectives in these reservoirs, a simulation study was undertaken, and the economics of multiple-fractured horizontal wells in tight gas reservoirs was investigated. Of interest in this evaluation were reservoir, completion, and stimulation parameters. Net pay, reservoir pressure, and reservoir permeability were evaluated. For the completion practices, completion control was considered; and for fracture stimulation, the effects of fracture length and conductivity were considered in light of fractured-horizontal-well objectives. Finally, horizontal-well drilling, completion, and fracture-stimulation costs were considered along with economic parameters to ensure that the horizontal-well objectives were established for all environments. Recoverable-Reserves Considerations The study compared reservoirs with 25, 50, and 100 ft of net pay. For a reservoir with limited net pay (25 ft), the optimal number of completions and fracture stimulations required to deplete the reservoir was five. Beyond five, there was little to no economic benefit from increasing the number of fractures. For a reservoir with 50 and 100 ft of net-pay thickness, the economically optimum number of completions was nine and 20, respectively. Thus, the greater the amount of recoverable gas, the more completions that are needed to recover those reserves optimally. Also, doubling the net pay in this example tripled the economic value, and quadrupling the net pay to 100 ft resulted in an eight-fold increase in the discounted net present value. Instantaneous potential (IP), or 30-day rate, for these three cases from 25 to 100 ft of net pay increased linearly with the number of fractures, up to 15 completions/fractures. However, beyond 15, the IP was not linear, indicating that the fractures were interfering with each other within 30 days.