Predicting long-term production from gas shale reservoirs has been a major challenge for the petroleum industry. To better understand how production profiles are likely to evolve with time, we have conducted laboratory experiments examining the effects of confining stress and pore pressure on permeability. Experiments were conducted on intact core samples from the Barnett, Eagle Ford, Marcellus, and Montney shale reservoirs. The methodology used to measure permeability allows us to separate the reduction of permeability with depletion (because of the resultant increase in effective confining stress) and the increase in permeability associated with Knudsen diffusion and molecular slippage (also known as Klinkenberg) effects at very low pore pressure. By separating these effects, we are able to estimate the relative contribution of both Darcy and diffusive fluxes to total flow in depleted reservoirs. Our data show that the effective permeability of the rock is significantly enhanced at very low pore pressures ( []) because of the slippage effects. We use the magnitude of the Klinkenberg effect to estimate the effective aperture of the flow paths within the samples and compare these estimates to scanning electron microscopy image observations. Our results suggest effective flow paths to be on the order from tens of nanometers in most samples to 100–200 nm, in a relatively high-permeability Eagle Ford sample. Finally, to gain insight on the scale dependence of permeability measurements, the same core plugs were crushed, and permeability was again measured at the particle scale using the so-called Gas Research Institute method. The results show much lower permeability than the intact core samples, with very little correlation to the measurements on the larger scale cores.

Experimental investigation of matrix permeability of gas shales

Although hydrocarbon production from unconventional reservoirs, the so-called shale gas, has exploded recently, reliable predictions of resource availability and extraction are missing because conventional tools fail to account for their ultra-low permeability and complexity. Here, we use molecular simulation and statistical mechanics to show that continuum description--Darcy's law--fails to predict transport in shales nanoporous matrix (kerogen). The non-Darcy behaviour arises from strong adsorption in kerogen and the breakdown of hydrodynamics at the nanoscale, which contradict the assumption of viscous flow. Despite this complexity, all permeances collapse on a master curve with an unexpected dependence on alkane length. We rationalize this non-hydrodynamic behaviour using a molecular description capturing the scaling of permeance with alkane length and density. These results, which stress the need for a change of paradigm from classical descriptions to nanofluidic transport, have implications for shale gas but more generally for transport in nanoporous media.

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Subcontinuum mass transport of condensed hydrocarbons in nanoporous media

Gas transport and storage capacity in shale gas reservoirs – A review. Part A: Transport processes

Laboratory measurement of low permeability unconventional gas reservoir rocks: A review of experimental methods

Petrophysical and geomechanical characteristics of Canadian tight oil and liquid-rich gas reservoirs: I. Pore network and permeability characterization

Steady-State Permeability Measurements on Intact Shale Samples at Reservoir Conditions - Effect of Stress, Temperature, Pressure, and Type of Gas

Determination of permeability of unconventional reservoirs is critical for reservoir characterization, forecasting production,
determination of well spacing, designing hydraulic fracture treatments, and a number of other applications. In many
unconventional reservoirs, gas is produced from tight rocks such as shale. Currently the most commonly used industry
method for measuring permeability is the Gas Research Institute (GRI) technique, or its variants, which involve the use of
crushed samples. The accuracy of such techniques, however, is questionable because of a number of inadequacies such as the
absence of reservoir overburden stress while conducting these measurements. In addition to questionable accuracy of crushed
rock techniques, prior studies have indicated that there is significant variability in results reported by different laboratories
that utilize crushed-rock technique to measure permeability on shale samples. Alternate methods are required to obtain
accurate and consistent data for tight rocks such as shales. In this paper we discuss a robust steady-state technique for
measuring permeability on intact tight rock samples under reservoir overburden stress. Permeability measurement standards
for low permeability samples are critical for obtaining consistent results from different laboratories making such
measurements, regardless of the method used for measuring permeability. In this paper we present permeability measurement
standards developed based on first principles that serve as the “ground-truth” for permeability in the 10 – 10,000 nanoDarcy
range. These standards can be used to calibrate any permeability measurement apparatus used to measure permeability on
intact tight rock samples such as shales, to enable delivery of consistent results across different laboratories conducting
measurements on intact tight rock samples.

Advances in Measurement Standards and Flow Properties Measurements for Tight Rocks such as Shales

Steady-State Stress-Dependent Permeability Measurements of Tight Oil-Bearing Rocks

Effect of Stress, Creep, and Fluid Type on Steady State Permeability Measurements in Tight Liquid Unconventional Reservoirs Shreerang S. Chhatre, Somnath Sinha, Edward M. Braun, William L. Esch, Matthew D. Determan, Quinn R. Passey, Sergio A. Leonardi, Timothy E. Zirkle, Alexander C. Wood, Jeff A. Boros, Ryan A. Kudva 1. ExxonMobil Upstream Research Company, Houston, TX, United States. 2. Consultant, Houston, TX, United States

Effect of Stress, Creep, and Fluid Type on Steady State Permeability Measurements in Tight Liquid Unconventional Reservoirs

A calibration standard or check plug provides calibration standards in the permeability range of 10-10,000 nanoDarcy. The check plug is of similar exterior dimensions to a core sample that would be used with existing permeameters. The check plug is constructed from an impermeable material that is insensitive to moisture. The check plug has one or more channels of known diameter from which the permeability may be calculated. Methods for use thereof and methods of manufacture thereof are also disclosed.

Timothy E. Zirkle

Papers

Steady-State Permeability Measurements on Intact Shale Samples at Reservoir Conditions - Effect of Stress, Temperature, Pressure, and Type of Gas

Advances in Measurement Standards and Flow Properties Measurements for Tight Rocks such as Shales

Steady-State Stress-Dependent Permeability Measurements of Tight Oil-Bearing Rocks

Effect of Stress, Creep, and Fluid Type on Steady State Permeability Measurements in Tight Liquid Unconventional Reservoirs

Capillary-Based Calibration Standards For Measurement of Permeability