interactions with far-field
diverters and liquid
chemical tracers
or operators developing shale reserves, determining an optimal infill well strategy can be technically challenging and plagued by multiple sources of uncertainty. Even under the best circumstances, multiple reservoir properties combine to create a complex blend of matrix permeability, natural faults and fractures, and landing interval properties that make ideal placement highly variable from pad to pad—especially within stacked reservoirs.
While heterogeneity in the reservoir cannot be controlled, multiple strategies have been created to mitigate the risk of placing infill wells close enough for negative fracture interactions, instances where overlapping stimulated areas between wells undermines the economic value of one or both assets. These mitigation techniques almost exclusively focus on preventing fracture linkage, either by limiting fracture growth or by controlling the direction of propagation.
In cases where parent well production has significantly depleted the reservoir, stimulation of infill wells frequently results in a higher degree of asymmetric fracture growth, with fractures propagating toward depleted and previously fractured zones surrounding the parent well rather than stimulating previously unexploited reserves. An optimal mitigation strategy redirects the energy of hydraulic fracturing toward more even fracture growth and a more distributed, rather than longer, fracture itself. Yet the selection of an optimal mitigation strategy is not clear cut, particularly when individual pads deal with unique heterogeneities and natural fracture outlays.
To this end, diagnostic tools provide significant value in determining which completion strategy and the possible combination of mitigation techniques best align with an operator’s technical needs and economic drivers. A Permian Basin operator evaluated the effectiveness of far-field diverters at controlling fracture growth and limiting interwell communication between child and parent wells. Liquid chemical tracers were used to establish and quantify flow from and between wells and determine if a novel diversion strategy was preventing negative fracture interference.


Table 1 provides a summary of the stimulation program used for the infill wells.

To further protect the parent wells from negative fracture interactions, Parent Wells A and B were shut in for a period of time to restore the depletion zone surrounding them prior to fracturing the child wells. Parent Well A also saw an injection of water to prepressurize the near wellbore area and provide additional protection from child fracture growth into its drainage area. Three additional parent wells exist within the Wolfcamp A/B and in proximity to Well 7, but these wells could not be sampled over the course of the study. However, the depletion effects of these three parent wells are expected to affect fracture growth direction during the stimulation of the child wells.
Over the span of 200 days, samples were collected from the eight child and two parent wells and analyzed for the presence of the injected tracers. When tracers were recovered from the same well that saw their injection, the combination of tracer concentration and production history generated a mass balance that revealed how much of the oil and water production came from each of the three treated zones. When a tracer was discovered in the production fluid of an offset well, its presence evidenced an intermingling of stimulated reservoir volumes (SRVs) that allowed for tracer migration to occur.

Diversion did not prove effective in preventing fracture network growth toward depleted zones within the reservoir. Though tracer results are suggestive that diverter use may increase cluster efficiency and provide a more even distribution of fracture fluid through each perforation during fracturing, the improvement was insufficient to significantly change the likelihood of negative fracture interactions (Figure 4).


In stages where far-field diverters were used, asymmetrical growth of this far-field fracture system was curtailed but introduced new problems. In creating a more even fracture network around child wells, the use of diverters ensured that negative fracture interactions occurred more often but with slightly diminished magnitude. The use of diverters also notably penalized oil production. Where well spacing was increased or frac order could be managed, the operator achieved comparable or better mitigation of overlapping SRVs and so the future use of diversion was abandoned for their Spraberry field development.