Standards for Characterization of Rock Properties in Unconventional Reservoirs: Fluid Flow Mechanism, Quality Control, and Uncertainties

Abstract

Abstract Estimating basic properties of unconventional shale reservoirs—such as permeability and porosity—is critical for reservoir evaluation, formation damage prediction, hydraulic fracture design, and performance forecasting. Several techniques can be used to measure these properties. For instance, the Gas Research Institute (Luffel et al. 1993) uses crushed rock, modeling high-resolution images of micron-sized samples, pulse decay, steady-state techniques to evaluate the permeability, and gas expansion and mercury immersion for porosity of a shale sample. However, the accuracy and reliability of these techniques are not well-established for unconventional reservoir rocks because of concerns about the flow regime, the absence of net confining stress, the sample size, and the imaging technique resolution. This paper presents the results of a round robin permeability and porosity measurement performed at several commercial and research laboratories. The permeabilities of the evaluated samples vary from 10 nanodarcy to 10 microdarcy, and their porosities vary from 5 to 10%. A wide range of natural and synthetic material was computed tomography (CT) scanned and microscopically examined. Selected samples were used based on their suitability for the desired range of porosity and permeability. The samples were examined before and after drying in a vacuum oven and then tested under several stress cycles. Gas permeability was measured by use of steady-state, transient pulse decay techniques and derived from mercury injection data. Porosity was measured by use of the gas expansion technique and mercury immersion. Image analysis of focused ion beam-scanning electron microscope (FIB-SEM) was also used to model permeability. Klinkenberg permeability was derived from apparent permeability by use of a range of mean pressures to examine validity of the Darcy flow regime. The results of the round robin testing of porosity and permeability indicate: Darcy flow is the predominant flow regime in shales with permeability as low as 10 nano-darcy, based on Klinkenberg characteristics and flow rate-pressure drop criteria. Permeability measurement on 10 nano-darcy to 10 micro-darcy permeability core plugs, under 400 to 5000 psi, is feasible and repeatable with a reasonable uncertainty range, at qualified commercial laboratories. Porosity data showed uncertainties in the range of ±1.0 p.u. for the natural samples. Steady-state method provides similar results from different laboratories, as long as an identical procedure is implemented. Uncertainty in steady-state permeability data from different laboratories could be as high as ±150%. Liquid permeability testing by use of supercritical fluid or laboratory fluid (Decalin) provides a complementary and valuable piece of datum. Rotary sidewall core plugs may provide higher quality core standards for shale material testing because the core plugging takes place under reservoir temperature and stress conditions.