As suggested by Ballinger et al. (2022), it is crucial to obtain a strong understanding of not just the hydraulic fracture geometry, but also what portion of those hydraulic fractures are conductive. If both parameters and their interactions are not fully understood, then development of the play may be compromised due to unoptimized well spacing and completion design. Midland Basin is a prime location for this application due to a robust resource of stacked pay with multiple high-quality unconventional reservoir targets. The Chow Pressure Group (CPG) analysis is used to understand the conductive half-length (Chu et al. 2018) and the implications of this number on expected communication between primary horizontal targets across the Midland Basin.
CPG is an analytical method of quantifying and categorizing well interference which has been utilized on over 200 horizontal wells in the Midland Basin to date.
Cobanoglu (2021) elaborated on measuring well interference including analyzing downhole pressure derivative; however, this was only a qualitative solution. CPG has established a baseline for zonal interference (same zone as well as co-developed zones) with respect to wells per section equivalent. The CPG technique has validated early interpretations of fracture connectivity, provided acceleration of data validation, and been used to analyze and optimize co-development strategies (predominantly within the Spraberry benches), completion design, and well spacing.
Key learnings have emerged based on the observations from multizone communication or lack thereof, the importance of best practices regarding flowback operations and flowback order, and the impact of spacing and stacking development configurations. Analyses in Midland Basin imply lack of interference between specific Spraberry and Wolfcamp targets and moderate to high interference between Spraberry targets, indicating the importance of the stagger element in the Spraberry plan of development. Anticipated additional insights include further optimization of spacing and stacking configurations, coupling of CPG with estimated ultimate recovery (EUR) and recovery factor (RF), implementation of CPG in late life production for a pseudo-time-lapse CPG to establish drainage area, and analysis of various completion tests and designs. CPG at initial flowback has shown to indicate hydraulic fracture half-length and stimulated reservoir volume (SRV), and not true drained reservoir volume (DRV). Initial flowback CPG does, however, provide the widest range of possible drainage area. Minimal analyses have been executed to date on late life CPG due to few opportunities for shut in production. Late life CPG coupled with time-lapse geochemistry has the potential to aid in narrowing down a more reliable estimate of DRV. A CPG Analysis tool developed as part of this work has streamlined a consistent workflow to analyze 200+ wells in an efficient manner, allowing isolation of single well ramp up procedures to calculate inter-well communication. Additional insights from pressure interference have been gained on how carbonate layers impact field development. In certain areas across the Midland Basin, capital efficiency can be accelerated by targeting the most productive zones without the risk of reduced well performance on secondary targets later. This has also allowed for a calibration of how much carbonate is necessary for classification as a frac baffle versus a frac barrier.
This application combines rate, pressure, and geological data to better understand well interactions spatially. As Ji, et al. (2021) pointed out this workflow has shown to be a cost-effective approach to studying well interference. The result is better decision-making during project planning, enhancing understanding of parent-child communication, and offset well production.
