This paper describes the results from the Pakenham Field effort at fracture stimulation engineering which incorporated, to the greatest extent possible, the results of actual measured field data. Measured data included: formation closure stress in payzones and bounding shales; numerous pre-frac diagnostic injections; measurement of actual perf friction and near-wellbore fracture tortuosity reflected bottomhole pressure and real-time net pressure data on many treatments; post-frac pressure build-up tests; and (early) post-frac production data. We feel that the large amount of measured data allowed us to increase our confidence in the veracity of the results by greatly reducing, the requirements for unsubstantiated physical assumptions.
Measurement of the sand-shale closure stress contrast and the relatively high net fracturing pressures (compared to the closure stress contrast) revealed that fractures obtained in most of the treatments were much shorter and less confined than we originally expected: the fracture half-length was about 200 to 300 ft (instead of about 600 ft), which is consistent with estimates from post-fracture pressure build-up tests.
Based on these measurements, Chevron's fracturing practices in the Pakenham Field could be carefully reviewed to enhance fracture economics. Supported by the real-data fracture treatment analysis, several changes in completion, fracture treatment design and data-collection procedures were made, such as:
changing from CO2-foam to Borate crosslinked gel;
reducing the perforated interval to help minimize the simultaneous propagation of multiple hydraulic fractures; and,
reducing the pad fluid size, as fluid leakoff from the fracture into the formation was relatively low.
This paper should be regarded as only a first step towards fracture treatment optimization in the Pakenham Field. Further fracture treatment optimization will continue throughout the development of the Pakenham Field. Although it is still too early to quantify production benefits of implementing these real-data-based treatment changes, modest cost savings have been realized on the newly completed wells.
Too often in this industry, the engineering of hydraulic fracture stimulation begins with making a number of broad, but unsubstantiated, assumptions about hydraulic fracture growth in the reservoir in question — such as confined fracture height, or radial fracture growth, or assuming an in-situ stress profile and running a favorite 3-D fracture model. After these broad assumptions regarding hydraulic fracture growth are made, and a particular simulation model is chosen, the engineer then embarks on detailed "studies" of the (economic) optimum designed fracture length; the appropriate completion strategy; fluid and proppant selection; detailed treatment schedules; and procedures (if any) for post-treatment evaluation. While motivated by admirable principles, these "studies" often fall short of their goals due to grave errors in the unsubstantiated assumptions that were initially made.
Chevron intended to verify these basic physical assumptions as early as possible during the development of the Pakenham Field (West Texas), especially in the Wolfcamp A2 sand, and to a limited extent in the Wolfcamp D sand. Pakenham engineers in Midland (from Chevron and their local service company alliance partner) desired to utilize the Gas Research Institute's (GRI's) Advanced Stimulation Technology (AST) as the main "tool" to evaluate and enhance their fracturing practices. The main concept behind AST is collecting and utilizing measured (real) hydraulic fracturing data. AST provides a methodology and an engineering tool to approximate fracture dimensions and to identify critical fracture design issues during and after a fracture treatment. A vast number of authors have reported positive results from real-data fracture treatment analysis.
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