Abstract
Relative permeability is a significant source of uncertainty in current modeling practices for performance prediction of unconventional reservoirs. Due to the lack of reliable measurements or representative analogs, relative permeability is often used as an unconstrained history matching parameter for tight/shale rock formations. To date, reliable laboratory measurements of gas-oil relative permeability have been limited to rocks with permeability on the order of hundreds of microDarcies or greater. This work describes laboratory measurements on rock with permeability of hundreds of nanoDarcies, and the use of that data to reduce uncertainty in modeling and performance prediction.
Laboratory measurements of full gas-oil relative permeability curves were made on an unconventional core sample from a tight oil producing interval from the Permian Basin with permeability of hundreds of nanoDarcies. These difficult measurements were achieved through novel experiment design, equipment, and technique. In addition, these measurements were made using a combination of steady-state and unsteady-state techniques that resulted in direct measurement of the relative permeability curves over a broad range of saturations.
The measured steady-state gas-oil relative permeability curves were used to constrain Corey exponents and endpoint saturation values for gas-oil relative permeability curves in history matching simulation models and reducing uncertainty in performance predictions for tight/shale formations. Examples will be discussed.
This work describes the first known successful laboratory measurement of full gas-oil relative permeability curves on rocks with permeability on the order of hundreds of nanoDarcies (~1,000 times tighter than previous measurements). Measured laboratory data assists in constraining parameters used for history matching simulation models and significantly reduces the uncertainty in performance predictions.
Introduction
Oil and gas production from tight/shale formations has increased from a small value a decade ago to 59% of total U.S. crude oil production in 2018. [1] Hydrocarbon production from such tight rocks has been commercially viable due to large improvements in horizontal drilling and hydraulic fracturing technologies. Characterization of the tight/shale rock matrix, however, remains an open challenge given the extremely low permeability of the rock matrix and relatively small production history. Intervals like the Spraberry, Bone Spring, and Wolfcamp in the Permian Basin region in West Texas and Southeast New Mexico account for a dominant share (~ 4.1 million barrels/day oil and ~14 Bcf/day associated gas), based on a recent EIA estimate of production from tight/shale rocks. [1]
