Near wellbore complexity is a current topic of discussion among geoscience and engineering disciplines across North America. Asset teams are constantly investing money and resources into the variety of near- and far-field wellbore diagnostic techniques to ascertain completion efficiency. These range from high-cost microseismic for far-field fracture placement to higher risk technologies such as fiber optics, cameras, and production logging tools. These techniques are generally used for parameter constraints for rate-transient-analysis (RTA) that requires months (and sometimes years) of production after post-frac flowback. Therefore, in this study we utilize flowback water-oil-ratio (WOR) as a diagnostic tool to provide early-time feedback for completion-efficiency evaluation. We analyze flowback, post-flowback and completion-design data of 19 multi-fractured horizontal wells (MFHWs) completed in Niobrara and Codell formations that are classified into parent and child groups. Child wells are then sub-clustered into Zipper-1 and -2 completed with more and less intense completion strategy, respectively. First, we analyze the flowback rate and pressure profiles of the 19 wells to estimate initial pressure in the stimulated area around wellbore and validate it against the outcomes of diagnostic fracture injection test (DFIT). Second, we apply rate-normalized-pressure (RNP) diagnostic analysis to a) investigate flow regimes during flowback and post-flowback periods; and b) assess interference between parent and child wells. Third, we use WOR diagnostic plots to estimate ultimate load recovery (ULR) and calculate initial effective fracture volume as two indicators for completion efficiency. We also cross-check the estimated effective fracture volume with microseismic dimensions. Finally, we apply rate-decline analysis on oil production data to predict ultimate oil recovery (UQo), assuming a critical oil rate of 1 stbd, and use it as a third performance indicator to evaluate the completion-design efficiency of each group. Child wells show 32% more load recovery compared with the parent wells. However, the parent wells show 38% and 50% more 9-months cumulative oil production (Qo) and UQo, respectively. For both the parent and child wells, more than 50% of the predicted ULR is produced back within the first three months of production. Although the intense completion-design strategy for Zipper-1 wells led to 35% larger effective fracture volume compared to Zipper-2 wells, both groups show similar oil recovery performance. Generally, Niobrara wells show less load recovery and effective fracture volume compared to Codell wells in each completion group.

It is now well established that production from horizontal wells with multi-stage hydraulic fracture stimulations performed through plug and perf completions is highly variable along the length of the wellbore. In addition to the elements of the completion design, such as fluid and proppant volume, injection rate, stage length, and the number and spacing of perforation clusters, subsurface conditions influence the performance of individual stimulated perforation clusters, intervals, and wells. Information about completion efficiency can be obtained using conventional well log measurements for fracture fluid mapping. Contemporary logging conveyance methods make this information gathering practical for modern horizontal wellbores. A log-based Perforation Cluster Efficiency (PCE) computational method will be presented. These conventional open-hole logging measurements reveal insights into the Near-Wellbore Region (NWR), including annular cement density, and can be used to anticipate fracture behavior. Integrating well log measurements with Fiber Optic (FO) diagnostics provides insight into the performance of each perforation cluster and the factors controlling frac construction. This paper illustrates recent observations about PCE using traditional well log measurements with new conveyance methods and summarizes the results for several cemented plug and perforated completed Niobrara and Codell wells within the DJ basin. A comparison to interpreted FO DAS data is included, illustrating a good agreement for PCE.