When the word "shale" is included in the name of a formation, a high-rate water frac is often instantly assumed to be the correct choice for hydraulic fracture treatment. This is because high-rate water fracs are the common treatment in the Barnett shale in northeast Texas, and that is the shale reservoir with which industry professionals are most familiar. When a new shale development, such as the Eagle Ford shale in south Texas, is discovered, engineering tends to take a back seat, and a high-rate water frac is often the initial treatment design chosen simply because that is what has been done in the Barnett. Reservoir understanding acquired from core analysis, geomechanical tests, formation evaluation, proppant-embedment testing, stress analysis, and other data are sometimes ignored in the design process.
This paper discusses the thought process that engineers are encouraged to follow when deciding what type of completion should be used to fracture stimulate a shale reservoir (water frac, hybrid, or conventional). Considerations, such as the type of hydrocarbon that is expected to be produced, fracture complexity of the reservoir, lithology and mineralogy of the rock, and other reservoir parameters, should be included as part of the completion design. To close the loop, the production also should be evaluated to make good engineering-design changes as the asset is developed. Quantifiable analysis of a stimulation treatment in a horizontal well can be a daunting task because of the complexity and lack of data. Production analyses for several stimulated wells are presented. This application can be directed toward any horizontal completion in low/ultra-low permeability reservoirs and can be performed in a timely manner. The immediate goal of this process is to determine a qualitative measurement of stimulation effectiveness; the eventual goal is a quantitative tool.