The High Cost of Poor Child Protection: Economic Evaluation at the Pad Level with Primary Well Refracs

Abstract

AbstractMost organic shale operators and capital providers believe that refracs cannot compete economically with new wells. If production from actual refracs and infill well protection is considered, the combined NPV10 is higher than that of a new well in several of the areas studied (Barba et al 2022 and 2023). The two components of the uplift are reviewed here in greater detail than previous refrac economic analyses. For this evaluation, we looked at the Eagle Ford, Haynesville, and the Midland Basin Wolfcamp age organic shales. In the first iterations of the studies, the actual declines of 34 refracced wells in the Eagle Ford and 63 wells in the Haynesville were burdened with a current AFE estimate to provide an estimate of rate of return and NPV (Barba et al 2022 and 2023). When the completion practices were reviewed for the Haynesville we observed that operators did not consistently follow perforating "best practices" to obtain high cluster efficiencies and that they were leaving a lot of "meat on the bone." A second iteration in Haynesville estimated the increased uplift with the application of "best practices." Since the majority of the refracs in the Eagle Ford were done by operators that more frequently employ "best practices" the original declines were used. The hypothetical Permian uplift was estimated with the assumption that "best practices" would be used to obtain 100% cluster efficiencies. This should result in the recovery of the majority of the stranded hydrocarbons that have been identified with recovery factor analyses of legacy and new completions. The expected Permian uplift is the difference between the +/- 14% expected recovery factor for liner refracs with XLE and wells completed with wide cluster spacings prior to H2 2016. These legacy completions in what we are now calling "primary" or "parent" wells have recovery factors that are typically in the 2% to 5% range (Barba and Villarreal 2020).On the primary well protection refrac uplift portion, the first iterations also assumed that first order infill child wells in proximity to primary parent wells delivered 40% lower EURs than analogous infill wells without offset depletion sinks (Elliott 2019). It does not assume damage to second order or higher offsets which this study will show can be significant. A review was done of 143 Haynesville recent generation completions to estimate the recovery factors for infill wells. This recovery factor was used to compare the relative performance of infills which have primary well offsets to those without them. A key finding of that comparison was that the primary well protective refracs were indeed successful in reducing EUR damage in the infill wells. They did not totally eliminate it, however. One issue that came up in SPE 212371 (Barba et al 2023) was the liner refracs in the study did not utilize "best practices" with regard to recommended friction pressure drops and was likely that +/- 40% of the protective refrac clusters were not stimulated. The first order and second order offset EUR damage was lower than was observed in the unprotected wells. It was also observed on several occasions that the higher order more distant offsets often had similar recovery factors to lower order offsets in the same pad. Well spacing also played a role in this as the majority of the infill well spacings were less than the 1320 ft benchmark spacing (660 ft drainage radius) that provided the most consistent reasonable recovery factors. Recovery factors are based on volumetric calculations of hydrocarbon in place of an area that is the length of the lateral by the 1320 ft width and the height of the reservoir. Decline analysis provided the EUR which divided by the hydrocarbon in place yields the recovery factor.The P10 recovery factor for new wells was 56% with most of the wells with no close offsets at the high end. The distribution of recovery factors for the 143 new wells ranged from a low 16% to a high of 79%, and a P50 value of 41%. A plot will be presented in a later section to show the distribution. The wells below the P10 56% value, were not all first-order infills to depleted primary wells. The lower performance was probably a combination of infill damage to both first and higher order infill wells, well spacings less than 1320 ft, and completion practices that often did not use the recommended 3000 psi perforation friction pressure dops to maximize cluster efficiency. (Barba and Villarreal 2023 HFTC). While the study will provide an estimate of the relative importance of each variable it is clearly not as simple as just comparing EURs.