The oil boom in the Permian Basin has been made possible in part by an increase in pad and infill drilling. This drilling practice also has resulted in fracture hits.
Fracture hits occur when a child well is completed near a parent well. Production from the parent well and associated depletion results in a pressure sink around the parent well, which causes the hydraulic treatment from the child well to communicate with the parent well.
Operators have tried various techniques to reduce the effect of parent well depletion on the production of the parent and child wells. These techniques include shutting in the parent well to build up pressure before completing the child well, refracturing the parent well, repressuring the parent well, creating a pressure wall by stimulating wells closest to the parent wells first and using control aids for the far-field fracture geometry.
Today, half of the wells drilled in the Permian Basin’s Midland and Delaware sub-basins are child wells (Xu et al. 2019). As well density in a section increases, drilling and completions decisions regarding the stimulation of child wells are increasingly shaped by changes in the in situ stress, mechanical properties and material balance that result from depletion around parent wells. This is a multifaceted reservoir-dependent 4-D problem with many different dependencies such as the size of the completion, well spacing and timing of infill drilling. As a result, more projects involving parent/child interactions are being carefully preplanned using sound engineering principles that enable real-time changes to completion designs to avoid negative effects of depletion and fracture hits.
By adopting real-time completion designs of infill wells, MDC Texas Energy successfully mitigated depletion effects from parent wells in a section development in the Delaware Basin.
This case study focuses on a section development comprising seven wells in the Delaware Basin in the Wolfcamp A and B formations. The wells described in Figure 1 were drilled and completed at various times over a 10-month time frame and grouped by generation:
• Parent well (Generation I);
• Child 1 and 2 wells (Generation II); and
• Child 3A, 3B, 3C and 3D wells (Generation III).
The parent well experienced fracture hits during completion of Child 1 and Child 2. Because the parent well was spaced about 2,500 ft away from Child 1 and 2, no communication was expected. Chemical tracers and the productivity index (PI) of the parent, Child 1 and Child 2 wells suggested that even a few months of production led to pressure and fluid communication between the parent and Generation II wells.
Before the completion of the Generation III wells, the existing producing wells (Generations I and II) were estimated to have 80% of EUR remaining in the ground. With the earlier experience of pressure flux while completing offsets and the remaining potential of the existing wells, protecting the existing wells was important.
Downhole and surface gauges were installed on the parent, Child 1 and Child 2 wells during the completion of the Child 3A, 3B, 3C and 3D wells. To protect the Generation I and II wells, the decision was made to drill some Generation III wells with a slight offset in true vertical depth from the existing producing wells. Water injection treatment was performed on wells prior to completing the Generation III wells. The team chose fluid injection without diversion aids on the Generation I and II wells. A total of 35,000 bbl was pumped in the parent well, 15,000 bbl in Child 1 and 5,000 bbl in Child 2.
The Child 3A well led the completion sequence to build up pressure on the west side of the section. The Child 3B, 3C and 3D wells were drilled from the same pad and zipper fractured. Design changes were made to the completion program with built-in contingencies to make additional changes on the fly to incorporate fracture geometry control aids and reduction to injection rate, fluid volume and proppant volume. Prior to pad operations, the Schlumberger team ran multiple completion sensitivity analysis models to enable the design changes in real time.
During completion of the Child 3A, 3B, 3C and 3D wells, multiple pressure increases were observed on the parent and Child 2 wells with varying degrees of severity. The stress buffer (shadow) created by carefully sequencing the stimulation program aided in reducing the fracture communication. The fluid injection strategy was effective in reducing the magnitude of pressure communication. Additionally, an active pressure monitoring program informed real-time completion design changes to reduce the magnitude of pressure communications on the parent, Child 1 and Child 2 wells.
The tracer data and PI profile suggest that during stimulation the wells have been hydraulically connected. Even though the connections fade over time, the observed communication between the wells results in the overall lowering of reservoir pressure. Some completion sections of the lateral showed abnormal behavior that is likely due to localized geological features. Figure 2 shows the initial PI for the Child 3A, 3B and 3C wells is smaller than that of the parent well, like for the Child 1 and Child 2 wells. All wells in Wolfcamp A show a similar PI profile after all the wells were put back on production, except for Child 3A, which was the closest well to the parent well.
The infill wells in Wolfcamp A have an increased water cut compared with the parent, Child 1 and Child 2 wells. The Child 3D well is in Wolfcamp B, which has higher in situ water saturation compared with that of the Wolfcamp A. Wells with spacing above 1,000 ft show equivalent productivity, but wells less than 500 ft apart show inferior productivity. The optimal well spacing with the general completion and stimulation design in the area seems to be within 500 ft to 1,000 ft (five to 10 wells in a section) in this area in Wolfcamp A. The higher PI of Child 3D suggests that there is hydraulic connectivity between Wolfcamp B and Wolfcamp A, but the production behaviors seem to be isolated from Wolfcamp A.
Developing a section with depletion effects occurring at various distances and durations is challenging. A proactive approach of planning wells, preloading wells (water injection), observing real-time pressure changes for diagnostics and responding to the pressure communication by changing fluid and proppant volumes and pumping rates provides an effective strategy for completing infill wells in a multigeneration section development in the Wolfcamp Formation and in similar settings around North America.
Editor’s note: This article was adapted from URTeC 2019-472.
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