Hydraulic Fracturing: Compensation of Surge and Swab Pressures in Floating Drilling Operations

Abstract

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110562, "Contacting More of the Barnett Shale Through an Integration of Real-Time-Microseismic Monitoring, Petrophysics, and Hydraulic-Fracture Design," by J. Daniels, SPE, G. Waters, SPE, J. LeCalvez, SPE, J. Lassek, SPE, and D. Bentley, Schlumberger, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November. The paper has not been peer reviewed. With effective stimulation techniques, economics for horizontal wells in shale-gas reservoirs are favorable compared to vertical wells. Real-time fracture mapping enables on-the-fly changes in fracture design to maximize the effective stimulation volume (ESV). ESV is defined as the reservoir volume effectively contacted by the stimulation treatment as determined by microseismic (MS) event locations and density. Correlation of MS activity with log data enables estimating fracture geometry. These data then are used to design a fit-for-purpose stimulation that has the greatest chance of maximizing the ESV and production. Introduction The Barnett shale is a Mississippian marine-shelf deposit that lies unconformably on the Ordovician Viola limestone/Ellenberger group and is conformably overlain by the Pennsylvanian Marble Falls limestone. The Barnett shale, within the Fort Worth basin, was the focus of this study, concentrating on wells in Denton, Wise, and Tarrant counties of Texas: the "core area." The Barnett in the core area ranges from 300 to 500 ft thick. Matrix permeabilities range from 0.00007 to 0.0005 md, with porosities ranging from 3 to 5%. The Barnett is its own source rock and is abnormally pressured in this area, with a pore-pressure gradient of approximately 0.5 psi/ft. Hydraulic-fracture stimulation is required to obtain commercial production. Before 1997, Barnett wells were completed with massive hydraulic-fracture treatments of crosslinked gelled fluids and large amounts of proppant. Difficulties in cleaning up fracture damage from the crosslinked gel and the high cost of these massive stimulation treatments led to marginally economical wells. In 1997, large-volume high-rate slick-water fracture-stimulation treatments were tested. While well performance was not increased significantly, completion costs were reduced by approximately 65%. In 2002, horizontal wells were drilled to increase wellbore exposure to the reservoir. The first horizontal wells increased the estimated ultimate recovery by 300% at double the well cost relative to vertical wells. Horizontal wells offer an economic solution outside the core area because fracture-height growth can be reduced while creating a large fracture-surface area. This solution is critical for regions in which the shale is bounded by potentially water-producing formations. Horizontal wells reduce the number of surface locations needed near populated areas and have been used in various infill-drilling programs. Gas-recovery factors can be improved by focusing the stimulation treatments on zones in the lateral section that have not been contacted by offset wells.