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Nicholson, A. Kirby (Pressure Diagnostics Ltd.) | Bachman, Robert C. (Pressure Diagnostics Ltd.) | Scherz, R. Yvonne (Endeavor Energy Resources) | Hawkes, Robert V. (Cordax Evaluation Technologies Inc.)
Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1: Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.
Abstract In the Midland Basin, infill wells have high potential of experiencing well-to-well fracture interference or "frac hits". Rock stress alteration around parent wells affect child fracture interactions thus impacting completion effectiveness, well productivity, and well spacing. Endeavor Energy Resources (EER) had a unique opportunity to study parent (hereafter referred to as primary) and child (hereafter referred as infill or active well) interactions and the effects of producing vertical wells on fracture behavior. Two active horizontal wells cross both developed and undeveloped acreage where half of each well is an infill between existing horizontals and the other half is in undeveloped acreage with two existing vertical wells. Operation-driven fracture fluid movement was analyzed by monitoring the treating pressure of the two active wells being completed; and the pressure response of nine shut-in offset horizontals, and ten vertical wells. The measurements and analysis establish a base case to which future fracture- interference monitoring techniques will be compared and later mitigation and intervention. Primary horizontal wells offsetting two infill wells were monitored with wellhead pressure sensors and ESP downhole pressure sensors. Two vertical observation wells (VOW) between the new infill wells were fitted with wellhead wireless pressure sensors and bottomhole pressure gauges. During this area's original development in 2016, vertical wells located hundreds to thousands of feet from the active fraccing well experienced frac interaction. To measure the severity of the invasive fluid movement, wellhead sensors were installed on vertical wells one-half mile, one mile, and one- and-a-half miles away from the active wells. Water and oil tracers were used in the two active infill wells to study fracture fluid movement in conjunction with pressure data. In the unexploited section, the observation horizontal wells’ pressure responses were examined for fracture shadowing (inter-well poro-elastic response) stress shadowing (intra-well dynamic active fracture interactions (DAFI) (Daneshy, 2018), and fracture-to-fracture connections both temporary and long term. As fracture operations approached a primary vertical well (depleted zones), frac fluid was distributed vertically among multiple horizons through perforations in the existing well and laterally into horizontal primary wells. The three laterally closest primary wells, completed in three different intervals, had similar strong pressure responses to a common active stage suggesting a geologic cause. As for the vertical observation wells, fluid incursion was observed over 8400 feet away. The vertical wells between the two horizontal active infills had a 200 ft. to 400 ft. radius of pressure disturbance as the frac stages approached their locations. Fracture stages within the 200 ft. to 400 ft. radius caused direct hits while stages outside this radius caused mild pressure increases identified as fracture shadows. Legacy fields in Midland Basin are usually Held by Production (HBP). Consequently, horizontal development may be around existing vertical wells. Redevelopment of acreage into unexploited benches after primary benches have been horizontally developed is another situation many companies face. By sharing this case study, the authors want other operators who are facing these common issues to leverage these learnings. The significance of ignoring potential fracture interference and hydraulic connection may result in ineffective fractures, reduced stimulated reservoir volume (SRV), or wells sharing SRV. Ultimately this means reduced resource recovery which may occur in either or both the primary and infill wells.