Development of a Calibrated Fracture-Growth Model and Automated Staging Routine for the Jonah Field

Abstract

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 116304, ’Development of a Calibrated Fracture-Growth Model and Automated Staging Routine for the Jonah Field,’ by Scott Malone, SPE, and Mark Turner, SPE, EnCana Oil and Gas; Mike Mayerhofer, SPE, Pinnacle; Neill Northington, SPE, Carbo Ceramics; and Leen Weijers, SPE, Pinnacle, prepared for the 2009 SPE Rocky Mountain Petroleum Technology Conference, Denver, 14-16 April. An important challenge in the Jonah field in Wyoming is obtaining effective fracture-height coverage over the entire 2,800+ ft Lance formation. A calibrated fracture model was developed for the field that ties log analysis to the fracture-growth behavior that was mapped by use of direct fracture-mapping technologies and to the net-pressure response measured during propped-fracture treatments. These improvements in predictive-modeling capabilities have led to better insight into fracture-growth behavior in the Lance formation. A 3D fracture-growth model was modified to determine perforation strategies and fracture-treatment schedules in a semi-automated process. Introduction The formation comprises a stacked sequence of 20 to 50 fluvial-channel sands interbedded with associated overbank-siltstone and floodplain-shale deposits. Within this interval, the net-to-gross ratio varies from 25 to 40%. Sandstone bodies occur as individual 10- to 25-ft-thick channels and as stacked-channel sequences greater than 200 ft in some cases. The formation is overpressured and generally exhibits a net-pay thickness averaging 500 ft. The discontinuous lenticular sand bodies generally are aligned northwest/southeast, but sandstone-body geometries are largely uncertain. The Jonah field covers approximately 23,000 acres and has estimated reserves of 15.2 Tcf of natural gas. The average permeability from all diagnostic fracture-injection tests (DFITs) in the field is 0.024 md. However, the accepted permeability averages 0.01 md. Between November 2002 and September 2004, a 630 fracture treatments were mapped with surface-tilt-meter mapping (STM), 145 treatments were mapped with microseismic mapping (MSM), and 94 treatments were mapped with downhole-tiltmeter map-ping. A total of 130 surface tiltmeters were installed in shallow 40-ft holes across the field, enabling most propped-fracture treatments in various test areas to be mapped during that time period. In February 2008, another 16 fracture treatments were mapped with MSM along the northern downdip area of the field to verify whether the lessons learned in the southern part of the field could be extended to other areas. Fracture-Mapping Results Fracture Orientation and Complex-Fracture Growth. Approximately 75% of all fracture treatments in the field show a dominant fracture azimuth of N45°W, while a quarter of the treatments result in a primary fracture azimuth of N45°E. Approximately half of the fracture treatments consistently show a secondary orthogonal-fracture orientation resulting in a crosscutting-fracture network. The third occurring fracture orientation is horizontal, which is most likely associated with the debonding of bedding planes. This mechanism could also be responsible for fracture-height containment.