Altered-Stress Fracturing

Abstract

Summary Altered-stress fracturing is a concept whereby a hydraulic fracture in one well is reoriented by another hydraulic fracture in a nearby location. A field test was conducted in which stress changes of 250 to 300 psi [1.7 to 2.1 MPa] were measured in an offset well 120 ft [37 m] away during relatively small minifractures in a production well. Results show that altered-stress fracturing is possible at this site and others. Introduction The in-situ stress field that exists at depth in a rock mass is known to control many oil and gas stimulation parameters, such as the orientation and height of a hydraulic fracture. In some reservoirs, the stress distribution is unfavorable for an effective stimulation, and considerable research has been directed toward mitigating undesirable effects. Particular examples important for natural gas production are a hydraulic fracture that is not optimally oriented with respect to well layout or permeability anisotropy, and fracture height growth into a low-stress zone above or below the reservoir. Controlling such undesirable growth has been primarily through modifications of the stimulation design or the drilling program. While such modifications as altering the well layout have been successful in some cases, they may not be practical in others. A second approach exists, however, that usually is overlooked: instead of changing the stimulation or drilling program, it may be possible to alter the stress field to a more favorable orientation or magnitude. While altering the stress field at 5,000- to 10,000-ft [1500- to 3000-m] depths may seem pretentious, we should remember that significant stress perturbations are induced by any process that changes reservoir pressure or fractures the rock. Because of the high pressures needed for fracture dilation and the large surface area created. a hydraulic fracture can effectively alter the stress field. This paper elaborates on the concept of stress alteration through hydraulic fractures and the ways it can be applied. We describe an initial field test, where stress tests were conducted in one well while a second well was hydraulically fractured to measure the stress change in the vicinity of a hydraulic fracture. The discussion includes analytic calculations for homogeneous media and finite-element calculations for layered media for comparison with the field results. We describe reservoir simulations that show the productivity enhancement expected from application of this concept and discuss practical capabilities of this altered-stress fracturing technique. Background Large natural-gas resources are found in tight, lenticular gas sandstones, particularly in the western U.S. Most of these lenticular sands have matrix permeabilities less than 1 or 2 ud and limited lens sizes, which are not encouraging for economical production under any foreseeable conditions. Many of these reservoirs, however, are also naturally fractured, resulting in effective reservoir permeabilities of tens of microdarcies as measured in well tests. These permeabilities are just sufficient to allow economical production in some areas and to warrant additional research in others. Such a situation exists at the U.S. DOE's Multiwell Experiment (MWX) Site, near Rifle, CO, in the Piceance basin. 6 A three-well research site was developed to characterize tight gas sands and to evaluate stimulation and production methods. The non-marine, lenticular sands of the Mesaverde group are the target reservoirs, at depths from 4,000 to 7,500 ft [1219 to 2286 m]. Most of these lenticular sands have 0.1- to 2- ud matrix permeabilities, but limited natural fracture systems increase the effective reservoir system permeabilities to 10 to 50 ud. Studies of outcrops and more than 4,100 ft [1250 m] of core-more than 1,100 ft [335 m] of it oriented-have shown that the natural fractures are primarily unidirectional, resulting in an anisotropic permeability distribution. This has been substantiated with three-well interference test results that show permeability anisotropy ratios of 30:1 to 100:1. In the few lenses where cross-fracture sets are observed, permeability anisotropies are still large. Reservoir thicknesses range from a few to 40 ft [12 m], with estimated lens widths of 100 to 2,500 ft [30 to 762 m], depending on the depositional environment. Because these reservoirs were deposited as sand channels or meander belts, lens lengths are expected to be much greater than the widths. Finally, the in-situ stress field is aligned with the natural fractures so that hydraulic fractures parallel the natural fractures. Stimulation and production of these reservoirs is not easy. Hydraulic fractures will intersect only a few of the natural fractures, and productivity enhancements of only about two to four times can be expected. In addition, these natural fractures are extremely narrow and appear to be easily damaged by stimulation gels. JPT P. 990^