Ranking Production Potential From Key Geological Drivers - Bakken Case Study

Abstract

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14733, ’Ranking Production Potential Based on Key Geological Drivers - Bakken Case Study,’ by Robin S. Pilcher, Jessica McDonough Ciosek, Kelsey McArthur, John Hohman, and Peter J. Schmitz, SPE, Hess Corporation, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, 15-17 November 2011. The paper has not been peer reviewed. Conference rescheduled to 7-9 February 2012. The Bakken play is a complex, low-porosity/-permeability system with variable source maturity, reservoir pressure and temperature, and fluid type. Target reservoirs are thin and variably affected by subtle structure, faults, or natural fractures. Many horizontal wells with multistage completions will be required to develop the Bakken play. A method is presented to assess the underlying production potential of the reservoirs on the basis of key geological drivers. With an extensive well-log database, petrophysical uncertainty can be addressed and stock-tank oil originally in place (STOOIP) can be calculated and mapped. Bakken Play The Williston basin oil province was discovered in 1951, and the Bakken formation was formally described in 1953. First oil was produced from the play in the same year. However, most of the early vertical wells, with the exception of those in the heavily fractured Antelope field, proved uneconomical to produce. The Bakken play is a hybrid of conventional (although tight) reservoirs and continuous resource plays that require development by use of closely spaced horizontal wells and multistage-hydraulic-fracture completions. Production Potential and Ranking Goals Regional ranking of future drilling locations is inherently challenging because of the many geological factors involved, and is complicated further by the influence of drilling, completion, and production operations. Traditional ranking schemes try to describe the relative potential of acreage and provide empirical support for the ranking by correlating the resulting rank to some measure of production performance. The production measure may be either a cumulative volume over a certain time frame (e.g., 90-day cumulative production) or a modeled estimated ultimate recovery (EUR) for the life of the well. Horizontal wells and multistage completions are a relatively new technology in the basin, with short production histories. As a result, use of actual production or actual production normalized per hydraulic-fracture stage is preferred because EUR introduces more assumptions and unknowns. A minimum period of 90 days of production was used in this study. Calibrating the regional-ranking predictions to actual production data will, inevitably, prove impossible to match past performance because the producing wells are subject to rapidly evolving technology and to variations in drilling, completion, production history, and operatorship.