Abstract

Water-oil (W-O) relative permeability is a critical parameter in modeling practices for performance prediction and water management of unconventional reservoirs. To date, laboratory measurements of W-O relative permeability have been limited to conventional rocks with permeability on the order of milliDarcies or greater. Due to the lack of lab measurements or representative analogs, W-O relative permeability is often unconstrained, which results in large uncertainty in reservoir performance prediction. This work describes a laboratory approach to constrain W-O relative permeability to reduce uncertainty in reservoir simulation through determination of wettability of unconventional rocks with nanoDarcy permeabilities. Laboratory measurements of water spontaneous imbibition were made on oil-bearing unconventional core samples from the Permian Basin with nanoDarcy permeability. A Nuclear Magnetic Resonance (NMR) technique was used for measurement of the oil and water saturations over time. The wettability of the rock (water-wet, mixed-wet, or oil-wet) was inferred from the spontaneous imbibition data and used to constrain W-O relative permeability curves. This work describes a novel approach to determining the wettability of shale rocks with nanoDarcy permeability. Measured laboratory data assist in constraining water-oil relative permeability curves used for history matching simulation models and significantly reduce the uncertainty in production performance predictions.

Introduction

Oil recovery from tight unconventional basins has increased drastically over the past few years to over half of the U.S. total production (EIA, 2019). This has been possible due to advancement in horizontal drilling and fracturing technologies. Yet, characterization of unconventional rocks has been challenging, given the low permeability and short production history.

The Permian Basin accounts for the majority of the production from unconventional plays. Oil producing intervals in the Permian Basin are geologically complex. These intervals have interbedded source rocks and low permeability reservoir rocks with a wide variation in mineralogy. Over geologic times, hydrocarbons were generated in the source intervals, and these hydrocarbons accumulated in the reservoir rocks by partially draining water from these rocks. Due to the presence of multiple source and reservoir rocks, a free water level cannot be established for such basins. Therefore, each zone is expected to have non-monotonic water saturation, depending on the relative distance from the nearest source, degree of overpressure, and geologic history of the interval. In addition to this inherent variability, massive hydraulic fracturing treatments result in localized changes in fluid saturation near wellbores and fractures.

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