In-Situ Stress Profiling and Prediction of Hydraulic Fracture Azimuth for the West Texas Canyon Sands Formation

Abstract

Summary This paper presents results of hydraulic fracture azimuth and in-situ stress measurements for two wells in the west Texas Canyon Sands formation. The paper gives information for designing infill drilling patterns and improving fracture treatment designs. Eight techniques were applied to measure fracture azimuth; the results from each are discussed. In-situ stress was measured in 12 intervals, and the results were used to calibrate long-spaced digital sonic logs. This paper also discusses the application of calibrated stress to fracture treatment design. Introduction Since 1984, the Gas Research Inst.'s (GRI) Tight Gas Sands Program has sponsored a number of field-based experiments to verify the effectiveness of recently developed technologies in geologic basins known to contain significant amounts of potentially recoverable gas in tight-gas-sand reservoirs. The strategy of this research is to conduct an integrated program emphasizing resolution of three main tight-sand R&D needs:improved geology and resource parameter quantification;enhanced stimulation techniques, including modeling of hydraulic fracture treatments; andimproved fracture diagnostics for determining fracture azimuth and dimensions. This strategy was extended to the Canyon Sands in Sutton County, TX, through data acquisition and analysis on cooperative wells with Phillips Petroleum Co. and Enron Oil & Gas Co. Fig. 1 shows the wellsites. The project was initiated because of the significant tight gas resource in the Canyon Sands and because of the relative effect that advanced technology could have on improving extraction of this resource. The overall GRI data collection and analysis effort on both wells supported geologic evaluation, log interpretation development, and reservoir analysis of the Canyon Sands. However, the objective of this paper is to present the results obtained in predicting or measuring hydraulic fracture azimuth and in measuring the in-situ stress of various layers in the Canyon Sands. This information will be useful for (1) more effective infill drilling patterns of hydraulically fractured wells and (2) improved design and modeling of hydraulic fracture treatments in the Canyon Sands interval. Background The two wells that have been analyzed extensively in this project are within 4 miles of each other (see Fig. 1). The Phillips Petroleum Ward Well C-11 (the Ward well) is in the Sonora field, and the Enron Oil & Gas Sawyer 144A Well 5 (the Sawyer well) is in the Sawyer field. Drilling and openhole data acquisition - including extensive coring, logging, and openhole stress testing - began in March 1990 on the Ward well and in April 1990 on the Sawyer well. Cased-hole data acquisition - including cased-hole stress testing, pre- and postfracturing well testing, and fracture treatment monitoring - were performed during the remainder of the year. The Canyon Sands interval in each well is about 1,250 ft thick and occurs in the approximate depth interval from 5,250 to 6,500 ft. When the two wells were completed, the gross Canyon Sand interval was informally subdivided into upper, middle, and lower intervals. The lower interval is characterized by discrete sandstone reservoirs bounded by thicker shales. The middle interval is characterized by thick sandstone reservoirs and a few thin shale beds. Like the lower interval, the upper Canyon Sands interval is characterized by shale-bounded sandstone reservoirs. Approximate well-to-well correlations of these subdivisions are possible, but individual sandstone reservoirs within these intervals are usually discontinuous. Preliminary interpretations based on examination of Canyon Sands core indicate a deep-water submarine fan depositional setting.** Techniques of Predicting Hydraulic Fracture Azimuth A combination of eight techniques was applied to estimate hydraulic fracture azimuth in the Canyon Sands. These included (1) oriented overcoring and direct observation of hydraulic fractures created during openhole stress tests, (2) use of wireline logging tools [Circumferential Acoustic Scanning Tool (CAST) and Formation MicroScanner (FMS)] to image the openhole stress test fracture in the borehole wall, (3) correlation of coring-induced, drilling-induced, and natural fractures to in-situ stress fields, (4) acoustic velocity anisotropy in core, (5) an elastic strain recovery, (6) oriented caliper logging to determine preferential direction of borehole breakouts, (7) postfracture oriented gamma ray logging, and (8) continuous microseismic radiation surveys in the treatment well. Not all techniques were attempted on both wells, and not all were effective in providing useful fracture azimuth information. The results acquired from each of these techniques are presented in the following sections. Overcoring of Open-Hole Stress Tests. Two openhole stress tests were conducted in the Canyon Sands, and the hydraulically induced fractures were subsequently overcored. The basic technique is (1) to set an openhole packer to isolate a zone between the packer and the bottom of the borehole, (2) to pump fluid down the drillpipe and induce a fracture in the formation beneath the bottom of the borehole and in the borehole wall, and (3) to cut an oriented core and attempt to intercept the fracture induced beneath the borehole (i.e., over core). Daneshy et al.1 described this technique more completely. The sequence of operations described above was successfully implemented in the Ward well at 6,050 ft. The core cut after the openhole stress test was 4 in. in diameter (in a 7 7/8-in. hole) and 24.5 ft long. No hole deviation problems were noted, and the borehole at the stress test interval was within 1/2° of vertical. The core was oriented with an electronic survey instrument. Core-orientation quality-assurance measures were implemented rigorously at the wellsite, and the resulting orientation data quality is valid. Overcoring of Open-Hole Stress Tests. Two openhole stress tests were conducted in the Canyon Sands, and the hydraulically induced fractures were subsequently overcored. The basic technique is (1) to set an openhole packer to isolate a zone between the packer and the bottom of the borehole, (2) to pump fluid down the drillpipe and induce a fracture in the formation beneath the bottom of the borehole and in the borehole wall, and (3) to cut an oriented core and attempt to intercept the fracture induced beneath the borehole (i.e., over core). Daneshy et al.1 described this technique more completely. The sequence of operations described above was successfully implemented in the Ward well at 6,050 ft. The core cut after the openhole stress test was 4 in. in diameter (in a 7 7/8-in. hole) and 24.5 ft long. No hole deviation problems were noted, and the borehole at the stress test interval was within 1/2° of vertical. The core was oriented with an electronic survey instrument. Core-orientation quality-assurance measures were implemented rigorously at the wellsite, and the resulting orientation data quality is valid.

Microseismic shearing generated by fringe cracks and bedding-plane slip

“…Both are fairly typical of tight-sand resources where gas is produced from thick sequences of multiple, low-permeability sand layers that are interbedded with and isolated by shales. Though the fields are in separate basins and represent different depositional environments (Walker, 1999;Hamlin, 2003) their mechanical stratigraphy is similar in terms of natural fracture characteristics and occurrence (Dutton et al, 1991;Marin et al, 1993) and the stress contrasts between sands and shales (Mayerhofer et al, 2000;Miller et al, 1994).…”

Reviews of Science for Science Librarians: Hydraulic Fracturing: Geological, Engineering, and Environmental Literature

“…These studies provide site-specific information that may illustrate hydraulic fracture performance characteristics in targeted geological formations and/or environmental conditions. A few examples include in situ studies at specific locations, such as the west Texas Canyon Sands formation (Miller et al 1994) and the Chinese Southern Qinshui Basin (Meng, Zhang, and Wang 2011), and in particular environmental conditions, such as an inclined borehole within a fluid-saturated porous medium (Abousleiman and Chen 2010).…”

Managing Uncertainty Related to Hydraulic Fracturing Modeling in Complex Stress Environments with Pressure-Dependent Leakoff

“…Blanton and Olson demonstrated closer matches between observed and logderived values in a case where previous authors had discounted log-derived methods as having less applicability. 30 Further, if PDL is noted in the injection data, a fissure opening pressure can be determined using G[dP/dG] diagnostic plots and a minimum estimate for the maximum horizontal stress derived using the relationship derived by Nolte and Smith. [31][32][33] History-matching Process.…”