In today's low oil price environment, the majority of operators are focusing on the development of their best acreage to maximize economic returns. These sweet spots are increasingly scarce, and hence the number of infill wells that will be drilled will increase. Stimulation treatment of the infill wells (“child” wells) drilled next to existing producers ("parent" wells) often causes negative fracture interference ("frac hits"), frequently resulting in irreversible production degradation on both parent and child wells.

This paper focuses on the implementation and modeling of a novel far-field diversion technique to reduce the frequency and severity of frac hits by altering the hydraulic fracture behavior. This method relies on the deployment of fracture geometry control (FGC) diversion pills consisting of a predetermined mixture of multi-sized specialty solid materials designed to create a low permeability barrier at fracture tips (far-field diversion), which alters in-situ fracture propagation.

This paper describes a case history where this novel technology was used during the completion of two infill wells drilled next to a producing parent well in the Eagle Ford Shale. Both infill wells targeted the lower portion of the Eagle Ford but were landed in different pay intervals in order to maximize hydrocarbon drainage. FGC pill was included in the pumping schedule to induce far-field diversion and prevent the infill well fractures’ growth towards the depleted pressure area around the parent well. The effectiveness of diversion was assessed through a high frequency pressure monitoring (HFPM) technique, which relies on processing surface pressure signals at high frequency. Pressure sensors were installed at the wellhead connections of both infill wells and the interpretation of pressure signatures was used to evaluate the degree of hydraulic communication between the wellbores and to gain an understanding of diversion effectiveness of various pill designs. Analysis of the pressure data indicates that hydraulic communication between the adjacent wells was reduced when FGC material was pumped.

Post-job production analysis shows that production of the infill well landed in the same zone as parent well was improved by 12% if compared to the average production of similar offset infill wells in the area. Furthermore, parent well production also improved by 5%, further evidence that fracture hits were successfully mitigated and that the original conductive area did not sustain damage. These results were further confirmed by hydraulic fracture and reservoir modeling using advanced integrated modeling workflow. The model confirmed that production improvement is a direct result of enhanced reservoir stimulation coverage of the infill well when the FGC technique was used.