New Fracture Diagnostic Test Delivers Tight Reservoir Data in 2 Hours or Less, Bolsters Future of Engineered Completions

One of the grand challenges facing the oil and gas industry’s global quest to improve the potential of tight reservoirs involves designing horizontal-well completions that match the often-complex heterogeneity of the target formations. This sums up the general concept most call the “engineered completion.” In theory, tailoring a stimulation job to the varying rock properties found along the lateral section of a horizontal wellbore should result in better production for less capital. In practice, the industry has never attempted to do this on a meaningful scale. Among other reasons, the detailed subsurface data required to shake the bonds of geometric, or “cookie cutter,” designs have long been considered too costly to gather or too time-consuming to analyze. A shift is underway though. This is thanks in part to a number of innovations that have hit the market in recent years to meet rising demand for real-time completions-monitoring services. By interpreting pressure signals and other reservoir responses, the new tools aim to give operators the competency they need to adjust fracture designs as the stimulation progresses. But there is another route to the engineered completion. It begins before the well is hydraulically fractured. This effort to predetermine different fracture-stage designs has established its own distinct arena of innovation. Behnam Zanganeh, a former research student at the University of Calgary, was part of a team that developed one of the latest approaches. It is notable in part because it requires no new technology - just new ways of thinking about some old ideas. In a paper published last month during the virtual Unconventional Resources Technology Conference, Zanganeh and his fellow petrotechnical researchers showed how multiple points in a wellbore can be tested for different reservoir-quality parameters quickly and simply relative to traditional methods (URTeC 2838). This is done by combining and fundamentally altering a test known for being slow: the diagnostic fracture injection test (DFIT). The biggest change it calls for is to start flowback after the injection cycle for flowback analysis (FBA), thus eliminating the lengthy falloff cycle associated with the DFIT. The paper outlines a validation study done with Sydney-based Origin Energy which used the blended DFIT-FBA method in a vertical open hole to test two previously untested horizons in the Beetaloo Basin, a frontier unconventional gas play in the center of Australia’s Northern Territory. The results were integrated into the models Origin ultimately used to select its landing target for its subsequent horizontal program.

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