The complex Spraberry trend extending 150 mi long and 75 miles wide covering the entire Midland Basin, and bounded on the west by the Central Basin Platform and on the east by the Eastern Shelf is characterized by its varying degrees of laminated layers of sandstones, siltstones, organic shale and carbonate mudstones. The rock fabric variability is a critical factor in understanding varying hydraulic fracturing responses in horizontal well completions. Optimized consistent fracturing design schedules were pumped bearing significantly differing outcomes in treatment pressure response, fracture parameters, proppant pack conductivity and ultimately well performance. The core of this paper discusses the impact of enhancing fracturing treatment design when integrated with well landing and placement, formation geological, petrophysical and geomechanical physiognomies recommending predictive measures that can significantly improve operational practices and results.

8 wells with 145 stage pressure responses were analyzed showing potential near well bore screenouts on numerous occasions during proppant laden steps. When this occurs, a wellbore volume of clean fluid (sweep) is injected to prevent the imminent screen out. These sweeps cause increased job times and require extra fluid which decreases the overall operational efficiency. The analysis developed improves the predictability of fracturing operations using drilling measurements and geomechanical attributes.

A wellbore profiling method was developed utilizing geological, petrophysical and geomechanical attributes where rock types are identified along the lateral and are associated with a specific fracturing pressure response. Seven rock types were determined based on a combination of geological and petrophysical analysis. Geomechanical attributes were then used to further subdivide the groups to predict fracturing pressure responses. The latter was integrated with an engineered model to calculate dynamic perforation efficiency based on the change in effective flow area during the treatment stage. Observed pressure responses were history matched and the varying impact on fracture geometry was compared across stages pumped as per design and stages where screenouts had to be prevented using pre-mature or necessary sweeps.

The developed wellbore profile accurately predicted expected pressure responses across all 8 wells. Rock types that provide the best combination of drilling, completions, and production enhancements can be successfully identified to make recommendations for lateral landing depths and completions design optimizations. Additionally, expected operational challenges can be predicted and accounted for in advance.

The developed method reduces operational uncertainty and risk to a minimal level. Fracturing treatment pressure responses can thus be accurately predicted and accordingly required operational changes could successfully be planned to manage challenging sections of the wellbore. Planning for operational anomalies is critical to ensure successful fracturing treatments pumped as designed that which has a vital impact on created fracture geometry, ultimately affecting well production performance.

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