Paradigm Shift in Wolfcamp Shale Improves Well Performance by 70%
- Efejera Ejofodomi (Schlumberger) | Richa Sethi (Schlumberger) | Elcin Aktas (Schlumberger) | Julie Padgett (Schlumberger) | Bruce Mackay (Schlumberger) | Andrey Mirakyan (Schlumberger) | Ben McCrackin (Manti Tarka Permian) | Chris Douglas (Manti Tarka Permian)
- Document ID
- Unconventional Resources Technology Conference
- SPE/AAPG/SEG Unconventional Resources Technology Conference, 23-25 July, Houston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2018. Unconventional Resources Technology Conference
- 2 in the last 30 days
- 300 since 2007
- Show more detail
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As with most shale reservoirs, understanding the production-driving mechanism in the Wolfcamp formation, Delaware basin, is difficult due to several factors, including large variations in mineralogy, lithology, wetting characteristics, etc. Only after the production mechanisms have been determined can an optimized completion strategy be developed to effectively maximize the well deliverability performance.
An integrated, unconventional workflow, coupled with a new laboratory measurement technique, was used to understand the production-driving mechanism in the Wolfcamp shale formation and develop an optimized completion strategy that increased the well performance while reducing the completion costs. The workflow is based on the seismic-to-simulation workflow that models complex hydraulic fractures and their interaction with preexisting natural fracture networks and the resulting production impact. This process was applied on a horizontal well in the field and comprises three main steps: modeling the created complex hydraulic fracture systems, matching the observed production response, and developing an optimized completion strategy to be applied on future wells, including a new intrinsic rock-fluid interaction process to identify the optimum flowback-aid additive.
The integrated workflow was applied on a producing Wolfcamp horizontal well in Ward County, Texas. The results revealed significant degradation of the hydraulic fracture systems within the first 2 months of production. Three possible causes were identified: improper flowback procedure, inadequate completion strategy, and resistance to flow due to rock-fluid interactions. Advanced flowback analysis indicated no proppant mobilization; thus, the first possible cause was eliminated. The calibrated fracture system indicated a highly conductive system with limited surface area away from the wellbore. But the results from the production sensitivity analyses demonstrated that the extent of the propped surface area away from the wellbore was a larger driver of the production than the fracture conductivity. Thus, an optimized completion strategy was developed that maximized the propped fracture surface area. However, this still could not account for the degree of degradation observed.
A new fluid compatibility testing process revealed that the flowback additive pumped on the well was ineffective and negatively affected the ability of the fracture system to flow back stimulation fluids. Thus, an optimum flowback aid along with a clay stabilizer were determined and integrated into the optimized completion strategy. The new design was executed on a newly drilled Wolfcamp shale horizontal well. The first year of production showed a 70% increase in cumulative oil with 50% less pressure degradation compared to the offset. Additionally, oil and chemical tracer data indicated that all the stimulated stages were contributing to flow.
The innovative integration of unconventional fracture modeling with rock-fluid compatibility testing is a step change in completion optimization and provides the ability to properly understand and predict the well performance. The positive impact of these results provided an excellent platform for efficiently determining the optimum completion strategy including fluid additives to maximize production in the Wolfcamp shale, and the approach serves as a model that is readily applicable to other unconventional basins.
|File Size||1 MB||Number of Pages||13|