Early and reliable estimation of shale deliverability and spatial drainage parameters from stimulated exploration vertical wells: Case study on Eagle Ford

Abstract

Industry needs techniques for expediting understanding on shale reservoir deliverability and spatial drainage. Horizontal wells are currently the option of choice for these investigations but their early adoption is costly and time consuming. Stimulated and flow-tested vertical exploration wells could address this challenge. Multi-domain data from one of the initial Eagle Ford shale stimulated vertical wells in DeWitt County, Texas was used to illustrate the viability of this approach. Completion and short-duration flow data were used for interpreting reservoir flow regimes, predicting hydraulic fracture geometry and incorporating natural fractures. Solving analytical relations for the former provided an estimate of system and matrix permeabilities of which the latter was in picodarcy (pD) range after inclusion of natural fractures and other pre-existing discontinuities through a discrete fracture network (DFN). All aforementioned results were used to build reservoir deliverability and drainage models whose subsequent scaling matched the performance and inferred spatial drainage of offset horizontal wells. For verification, the systematic scaling of forecasted flow from an early vertical well matched the long-term performance of offset multi-stage fractured horizontal wells. A modified scaled-profile for a single horizontal well also matched the total production from DeWitt County which had almost two thousand wells at the time of this study. The modification accounted for cross-well interference-driven productivity loss as a result of suboptimal well spacing. The derived picodarcy matrix permeability, estimated from data for both vertical and horizontal wells, was validated through geological timescale overpressure preservation and correcting core plug experimental permeability for in situ stress estimated after using a representative Biot coefficient. For optimal recovery, a set of theoretical optimal stimulations (TOSs) with their associated recoveries and spatial drainages were derived for field trials in the Eagle Ford and its analogues. Contrary to the current philosophy, exploration phase data including stimulation and flow metrics of a vertical well provided reliable predictions of parameters critical for field development. It was posited that costly, time-consuming, and trial and error shale derisking approaches can be optimized.