Effects of Infill- and Offset-Drilling Patterns on Field Development for Shale Wells

Abstract

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165722, ’An Examination of Infill- and Offset-Drilling Patterns in Field Development for Shale Wells,’ by Vivek Sahai, SPE, Greg Jackson, SPE, Farshad Lalehrokh, SPE, and Rakesh Rai, SPE, Weatherford, prepared for the 2013 SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, USA, 20-22 August. Delaying the start of new wells is understood to reduce the net present value (NPV) of a section, but variations in the arrangement of infill wells have not been examined thoroughly. In this paper, the effect of timing and pattern of well placement on NPV is studied. Three scenarios were evaluated: an infill scheme in which future wells are drilled between existing wells, a linear scheme in which future wells are immediate offsets of existing wells, and a hybrid scheme that is a combination of the infill and linear schemes. Introduction All previously published work using reservoir modeling to ascertain optimal well density assumes idealized conditions: zero well-to-well interference through fracture communication and simultaneous production initiation for all wells. Previous work postulated how infill-well drilling can improve cumulative recovery from shale-gas reservoirs because the distance between wells and the type of completion technique affect the amount of additional possible recovery. NPV considerations are important when operators consider either infill drilling or enhanced recovery methods to improve cumulative recovery from reservoirs that have gone through primary recovery. Reservoir simulation can help determine areas where depletion has not occurred and thus are optimal for potential infill-well development. The base case was chosen to be five wells per section (1,056 ft between wellbores) because of previous work. This paper determined how the economic results vary for three different field-development schemes for this optimal-well-spacing scenario. Basis of Modeling The numerical reservoir simulations used in this study capture flow from the stimulated reservoir volume (SRV) and external reservoir volume (XRV) within the drainage volume, as shown in Fig. 1. Average reservoir properties for the models are given in Table 1. The properties were averaged across 160 wells in a shale play in North America. The completed well length was the same for all cases, 3,840 ft, and the lateral was placed in the middle of the pay. The base case had a matrix permeability of 50 nd, a fracture spacing of 80 ft (which corresponds to 48 fractures on the 3,840-ft lateral), and a fracture half-length of 500 ft. The gas-production rate for each well in the section was 3,000 Mscf/D. Base Case The base case, described in earlier work, is shown in Fig. 2. The optimal number of wells per section is determined using normalized incremental cumulative recovery, which is defined as the number of wells beyond which any additional well provides a recovery factor less than 50% of that of the first well. Thus, the optimal number of wells per section for the base case is five wells, as confirmed by the peak in NPV. In this paper, all sections are assumed to require five wells for optimal development, on the basis of Fig. 2.