Observations From a Tight-Gas-Reservoir Stimulation

Abstract

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117570, "Observations From Tight-Gas-Reservoir Stimulations in the Rocky Mountain Region," by Erik Borchardt, SPE, Schlumberger; Jessica Cavens and Craig Wieland, SPE, EnCana Oil and Gas; and Brian Pluemer, SPE, Don Graham, Abdunnaser Erwemi, Alexei Kazantsev, SPE, and Joel Le Calvez, SPE, Schlumberger, originally prepared for the 2008 SPE Tight Gas Completions Conference, San Antonio, Texas, 9-11 June. The paper has not been peer reviewed. Unconventional tight gas reservoirs are made economical through effective stimulation techniques. Hydraulic-fracture mapping combined with an in-depth knowledge of reservoir geology and geomechanics can provide a better understanding of the effectiveness of reservoir stimulation. Massive hydraulic fractures from two wells in the Rocky Mountain region were mapped in real time with a 3D stimulation-viewer soft-ware package. One well used techniques standard to the area, while some experimental fracture techniques were tested on the other. Regional Background The area of study included 3,000 vertical ft of fluvial and marine sands in the Rocky Mountain region of the US. The formation contains natural fractures, laterally restricted lenticular sandstones, and tight brittle sands. The main natural-gas reservoir interval is from 5,000 to 8,500 ft. The productive sands have an average porosity of approximately 7%, and permeability is in the µd range. The first well was drilled in this region in 1955. In the late 1990s, the discovery of increased production resulting from fracturing lenticular sands made this a profitable area. Wells currently are drilled on 10-acre density. Much of the area uses directional drilling from well pads to reduce surface damage. Pad Layout On the study pad, there are four S-shaped wells (Fig. 1). The middle well (Well A) was used as the monitoring well, and the wells directly north (Well B) and directly east (Well C) were stimulated. Wells B and C are approximately 1,200 ft from the monitor well in the vertical section that was stimulated. Well C was considered the control well, while some experimental fracture techniques were used in Well B. Offset to the south of the monitor well (Well A), a series of openhole (OH) logs was run to help understand formation characteristics. A pulsed-neutron tool was run in all four wells so that geological modeling from OH logging on Well D could be projected to all wells on the pad by means of a neural network. The two treatment wells (Wells B and C) had 11 and 12 stages stimulated, respectively. Perforations were designed as 10 sets of perforations per fracture stage. The fracture stages ranged from 180 to 350 ft of net pay.