This paper discusses a stimulation optimization case history in the STACK (Sooner Trend, Anadarko Basin, Canadian, and Kingfisher counties of Oklahoma). This area has been active for a number of years, and operators are still trying to figure out how best to drill and complete the asset. This case history will cover a field trial conducted in the Meramec, the Sycamore and the Woodford, and will compare the completion methods of two offset pads, with one pad serving as the pre-optimization offset. These field trials consisted of wellbore spacing tests as well as the implementation of certain design and execution changes. The first major design change was the implementation of an algorithm-based, automated controlled breakdown process designed to improve the uniformity and the cluster efficiency of given stimulation treatments. When stimulations are conducted, it has been consistently demonstrated that a disproportionate number of perforation clusters are not effectively treated during any given stimulation treatment. The implementation of a controlled breakdown process not only allows for a better stimulation efficiency, but also allows for consistent treatment operations across stages and wellbores. The second design change was the application of ultra-fine particulates (UFP) during the initial pad stages of stimulation treatments. Unconventional reservoirs contain some level of complexity in the form of microfractures. Conventional proppants are typically too large to prop those microfractures, which limits how much hydrocarbon can be produced from a given reservoir. UFPs are small enough to enter those microfractures. Likewise, UFPs have been shown to reduce near wellbore friction early in stimulation treatments, which improves operational efficiencies. The third design change was the utilization of a wellhead connection system in place of a traditional zipper manifold. This system reduces equipment on location as well as the complexity of operations when stages on two or more wells are being stimulated in sequence. The operational changes on the post-optimization pad yielded increased efficiencies and reduced costs. The wells also showed a substantial production improvement over the typical curves for the area. The post-optimization wells had a higher rate of return over the pre-optimization pad. The wells where the automated controlled breakdown process was utilized demonstrated a 5 to 15% production increase over comparable offsets on the same pad. The wellhead connection system improved transition times between wellhead swaps during well zipper stimulation operations. The implementation of the breakdown process, the wellhead connection system, and UFPs improved operational efficiencies as well as making treatments more consistent. Observed treating pressures were lower and more consistent when the breakdown process was utilized. This paper demonstrates how the implementation of a controlled breakdown process, wellhead connection system, and UFPs can help improve well economics. Also, the economic potential for the STACK when utilizing an optimized completion is demonstrated.

The STACK (Sooner Trend Anadarko Canadian and Kingfisher counties) is a prolific multi-target stacked play in Oklahoma. Development challenges in the STACK are underpinned by fieldwide geological heterogeneities, including variable reservoir quality throughout the Sycamore-Meramec and Woodford formations and the presence of natural fractures and dense laminations. This case study examines the operator's first fully co-developed section in Canadian County, which comprised of 11 wells across 4 targets. This project was undertaken after de-risking much of the geological uncertainty in several offset pads. The data acquisition program was designed to assess the impact of total completion design including: interwell spacing, targeting, and wine-rack configuration on well-to-well connectivity and well performance in full section development. Within the section, half of the wells were drilled with the same spacing as offset pads and the other half were downspaced. On both sides of the section, similar targets received the same hydraulic fracturing design. Given it was the operator's first full section development in the county, the operator utilized an advanced data acquisition program that included downhole pressure gauges, chemical tracers, and DNA based diagnostics. DNA diagnostics proved especially useful in measuring the relative contribution from the multiple strata between landing zones, which would not have otherwise been possible. Although the previous offset pilot pads were developed with similar spacing and completion parameters, there were significant differences between average production profiles, with higher initial production (IP-180) observed in the full section. This paper evaluates these production differences by examining the impact of well spacing/targeting, completion design, and interwell communication on well performance in full section development. Well performance was assessed by integrating production, pressure, and tracer data, along with DNA based diagnostics. DNA diagnostics played a key role in assessing and monitoring the duration of interwell communication between offset wells across the section. Results from this integrated approach demonstrated that full section well performance was impacted by completion design and interwell communication in three notable ways: 1) interbench co-development significantly increased communication across perceived deterrents to fracture growth, 2) well-to-well communication was influenced by completion order, and 3) aggregate interwell communication was higher in full section development than in pilot pads, which may have contributed to the full section initially outperforming pre-drill expectations. The differences in well performance and well-to-well connectivity carry important implications for operators who plan to use partial spacing tests to develop multi-target full sections. Specifically, these observations underscore the potential for similar completion designs to yield materially different well performances between full section and 1 to 3 well pad development. These results also demonstrate the ability of DNA based diagnostics to accelerate learnings in full section development, which may have otherwise required additional CAPEX to test via heuristic techniques.

This paper discusses a STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) case study that determined the effectiveness of different diversion techniques, including pods, sand ramps with sand slugs, rate cycling, and utilization of the completions order to control fracture growth. A secondary goal of this study was to evaluate the suitability of pressure-based fracture maps and oil and water phase tracers in monitoring diverter effectiveness. Effectiveness of a given diverter technique and diverter drop was evaluated using the two techniques on a 3-well pad. The three wells were completed using a combination of: 4 pods per treatment interval6 pods per treatment interval8 pods per treatment intervalhigh-volume proppant loading per treatment interval The effectiveness of the diverter drop was evaluated using each of the diagnostic techniques listed above. The pressure-based fracture analysis uses the pressure response recorded in an isolated stage in the monitor well to compute fracture geometry and the rate of growth of the fracture dimensions. The effectiveness of a given diverter drop is classified into one of four possible categories: stop dominant fracture growth, impede dominant fracture growth, no impact on growth of dominant fracture and accelerate the growth of dominant farcture. These results were then compared with the analysis from oil and water phase tracers and treatment pressure analysis. Successful (effective) diversion was observed on 82 % of the stages with pods compared to 64% successful diversion where sand ramps were used. In addition, stages using 8 pods for diversion had a 15% reduction in average fracture half-length compared to stages using 4 pods. Fracture height was better controlled through the order of completions of the stages between 3 wells. Completing the middle well in the upper part of the zone ahead of the two outer wells in the lower part of the zone, controlled the vertical height growth of the two outer wells. The offset pressure-based analysis proved to be as effective in accurately diagnosing the diverter effectiveness and provided a significant cost and timing advantage compared to other diagnostic techniques.