Six hydraulic-fracture injections into a fluvial sandstone at a depth of 4500 ft were monitored with multi-level triaxial seismic receivers in two wells, resulting in maps of the growth and final geometry of each fracture based upon microseismic activity, These diagnostic images show that the hydraulic fractures are highly contained for smaller-volume KC1-water injections, but height growth is significant for the largervolume, higher-rate, higher-viscosity treatments. Fracture lengths for most injections are similar. Final results are also compared with fracture models.
The paper presents some important conclusions obtained by analysis of data from many hydraulic fracturing treatments monitored over the past five years. These conclusions involve some major changes from conventional concepts about hydraulic fracturing, many of which have been based on inadequate models of the process and a commensurate lack of adequate data or motivation to check those models. Recommendations are, therefore, also made about simple, low-cost procedures for adequate data collection, such as the use of flow-rate changes and/or multiple injection/shut-in cycles for stringent model evaluation. Our conclusions from such careful analysis include: shorter, wider fractures; relative insensitivity of fracture width to frac-fluid rheology; dangerously fast convection vs. settlement of proppant in imperfectly-contained fractures; and a potential role of natural fractures in explaining many phenomena formerly regarded as evidence for long contained fractures. Although serendipity may sometimes compensate for poor job design, we recommend that many existing approaches to fracture design and execution be re-considered and that more credible efforts at treatment optimization be achieved by more careful (on-site) analysis of properly monitored and more flexible field execution schedules. lIItroductionThe theory and practice of hydraulic fracturing abound ",":ith concepts, analysis techniques and procedures for creat~g "optimum fracture geometries" in representative reservoIrS.References and illustrations at end of paper. 131These ideas have evolved somewhat over the past twenty years, as may be seen, for instance, by comparing Ref. I and Refs. 2, 3: the most obvious, but still hard-won, recognition has been that fractures are typically not well-contained in the pay-zones of the target formations. However, many other misconceptions and inadequate models or procedures still pervade the industry -despite large amounts of data which, directly or indirectly, refute those approaches. This situation is still possible because adequate data-sets are not often collected and are rarely analyzed properly, if at all; and unsatisfactory explanations are often found when anomalies are noted (e.g. Ref. 4). Indeed, clearly questionable models are still purveyed (e.g. Refs. 2,3) as adequate representations of the physical process: in particular, they do not often come close to matching the actual observed pressures, even in well-defmed job situations. Results vary from vague (e.g. Ref. 5) to demonstrably erroneous recommendations for optimum job design. One of the authors (Geary) has been working on this problem for over twelve years, fIrSt conducting laboratory (Ref. 6) and computer (Ref. 7) simulations, then applying the resulting practical computer-based models (Refs. 8,9) to field applications, using actual data and on-site analysis (e.g. Ref. 10). Some of our original concepts (e.g. the role of rheology) have changed quite dramatically (e.g. from those presented in Ref. 11), but others (such as the roles of stress, modulus an...
A deviated observation or "intersection" well (IW 1-B) was drilled, cored, logged and tested through an area in a fluvial sandstone reservoir that had previously been hydraulically fractured. The point of intersection with the fractured interval was located 126 ft from the fracture well along one wing of the fracture(s) at a measured depth of 4,675 ft. Direct observations from core and borehole imagery logs in IW 1-B indicate that a total of 11 far-field vertical fractures were created. Clustered in a narrow 2.6-ft-wide interval, these 11 fractures are the direct result of 6 experimental fracture treatments executed in the distant frac well over a 4-month period. Diagnostic data acquired through IW 1-B included direct core observations and measurements, borehole log imagery, gamma ray (GR) tracer identification, well-to-well pressure transient and fracture conductivity tests, and production logging surveys. The explicit intent in the emplacement of IW 1-B was to provide direct observations and information to characterize the hydraulic fracture(s) in support of a remote-sensing fracture diagnostic program that included microseismic monitoring and inclinometer measurements. Introduction Research being conducted as a part of the Gas Research Institute (GRI) and Department of Energy (DOE) Multi-Site (M-Site) Hydraulic Fracture Diagnostics Project has focused primarily on the development of a microseismic fracture mapping capability. As such, a series of hydraulic fracture injections and associated diagnostic data acquisition activities were conducted in a fluvial sandstone reservoir, designated the B Sand, at a nominal depth of 4,540 ft. Comprehensive diagnostic instrument arrays including 30 triaxial microseismic packages and 6 biaxial inclinometers were permanently emplaced at depth in Monitor Well No. 1. A 5-level wireline-retrievable microseismic array was employed in MWX-3. Figure 1 provides a plan view of the M-Site detailing project-related well locations and the predicted hydraulic frac azimuth. Data analyses of microseismicity associated with the fracture process zone provided plan and profile map views of the fracture, while FRACPRO simulations and inclinometer results yielded correlative dimensional frac characteristics, e.g., length and height. Following a series of six separate injections involving fracture mapping experiments, the B-Sand research program plan scheduled the drilling of a deviated wellbore designed to intersect one wing of the hydraulically fractured interval approximately 130 ft from the MWX-2 treatment well. The intent was to use direct observation of a hydraulic fracture(s) to provide a measure of ground-truth concerning certain aspects of the microseismic mapping technique's accuracy and the inclinometer-derived frac characterization. It would also facilitate the assessment of results from 3D and other types of hydraulic fracture model predictions. This hydraulic fracture intersection well, IW 1-B, also provided project scientists a unique opportunity to observe and describe the far-field character of the induced hydraulic fracture(s) and to conduct other fracture technology experiments. The employ of five different radioactive (RA) tracers in four of the treatments and the use of three different colored proppants afforded a tagging process that would aid in defining the origin of any remotely intersected fracture(s). Moreover, this process would provide complimentary information regarding hydraulic fracture dimensions and proppant placement. The supporting information verifying that hydraulic fractures were intersected, the character of the hydraulic fractures, fracture genesis, proppant placement, and proppant conductivity are the primary emphasis of this paper. P. 351
Six hydraulic-fracture injections into a fluvial sandstone at a depth of 4500 ft were monitored with multi-level triaxial seismic receivers in two wells, resulting in maps of the growth and final geometry of each fracture based upon microseismic activity, These diagnostic images show that the hydraulic fractures are highly contained for smaller-volume KC1-water injections, but height growth is significant for the largervolume, higher-rate, higher-viscosity treatments. Fracture lengths for most injections are similar. Final results are also compared with fracture models.
The success of most fracture treatments is primarily dependent on the ability to evaluate the characteristics and critical mechanisms that control how a formation hydraulically fractures. By developing an understanding of the mechanisms, it is possible to make the necessary improvements to ensure optimum proppant placement and therefore maximize economic results. This discussion presents a simple, low cost method for improving the overall fracture geometry and reducing the risk of premature screenouts. Dramatic improvements in near-wellbore tortuosity and improvements in proppant placement can be achieved by maximizing the viscosity of fluid that is used to initiate the fracture and carry proppant through the near-wellbore region. Using the approaches presented, it has been possible to eliminate premature screenouts and improve the overall proppant placement in many different environments.
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