Abstract

Pay in tight-rock reservoirs is often associated with organic richness. The assumption is that the low permeabilities of the source rock do not allow for the migration of the hydrocarbon generated during the thermal maturation process. If core data are available, the water saturation, porosity, and total organic carbon (TOC) measurements can be used to confirm that the resource in place is correlated with the organic matter, which impacts the log characterization of pay. We studied the Wolfcamp A, Wolfcamp C, and Wolfcamp D tight-rock reservoirs using seven wells with core data through the Delaware Basin Wolfcamp Formation and discussed appropriate log-based pay identification methods. The linear relationship between TOC and original hydrocarbon in place (OHIP) for samples in the Wolfcamp C and D intervals validated the hypothesis of a self-sourced reservoir. We adopted the well-established correlation between TOC and formation bulk density to identify the better part of the Wolfcamp C and D reservoirs. Our core data suggested to use a bulk density of 2.55g/cc or less to define pay. The lack of trend in the scatterplot of TOC and OHIP for samples in the Wolfcamp A interval indicated that the hydrocarbon had probably migrated, at least on a local scale. In this case, pay could not be identified by log techniques developed to calculate TOC in organic-rich rocks. Instead, we built an OHIP model based on a quad combo logging suite using an ensemble learning method. This model favorably compared with a TOC-based pay flag against production logging data from two vertical producers with stages through the Wolfcamp A interval.

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