Many currently producing shale-gas reservoirs are overmature oil-prone source rocks. Through burial and heating these reservoirs evolve from organic-matter-rich mud deposited in marine, lacustrine, or swamp environments. Key characterization parameters are: total organic carbon (TOC), maturity level (vitrinite reflectance), mineralogy, thickness, and organic matter type. Hydrogento-carbon (HI) and oxygen-to-carbon (OI) ratios are used to classify organic matter that ranges from oil-prone algal and herbaceous to gas-prone woody/coaly material. Although organic-matter-rich intervals can be hundreds of meters thick, vertical variability in TOC is high ( 50% of the total porosity, and these pores may be hydrocarbon wet, at least during most of the thermal maturation process. A full understanding of the relation of porosity and gas content will result in development of optimized processes for hydrocarbon recovery in shale-gas reservoirs.

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From Oil-Prone Source Rock to Gas-Producing Shale Reservoir - Geologic and Petrophysical Characterization of Unconventional Shale Gas Reservoirs

One of the biggest challenges in estimating the elastic, transport and storage properties of shales has been a lack of understanding of their complete pore structure. The shale matrix is predominantly composed of micropores (pores less than 2 nm diameter) and mesopores (pores with 2–50 nm diameter). These small pores in the shale matrix are mainly associated with clay minerals and organic matter and comprehending the controls of these clays and organic matter on the pore-size distribution is critical to understand the shale pore network. Historically, mercury intrusion techniques are used for pore-size analysis of conventional reservoirs. However, for unconventional shale reservoirs, very high pressures (> 414 MPa (60 000 psi)) would be required for mercury to access the full pore structure, which has potential pitfalls. Current instrumental limitations do not allow reliable measurement of significant portions of the total pore volume in shales. Nitrogen gas-adsorption techniques can be used to
characterize materials dominated by micro- and mesopores (2–50 nm). A limitation
of this technique is that it fails to measure large pores (diameter >200 nm). We use a nitrogen gas-adsorption technique to study the micro- and mesopores in shales and clays and compare the results from conventional mercury porosimetry techniques. Our results on pure clay minerals and natural shales show that (i) they have a multiscale pore structure at different dimensions (ii) fine mesopores, with a characteristic 3 nm pore size obtained with N2 gas-adsorption are associated with an illite-smectite group of clays but not with kaolinite; (iii) compaction results in a decrease of pore volume and a reduction of pore size in the ‘inter-aggregate’ macropores of the illitesmectite clays while the fine ‘intra-tachoid’ mesopores are shielded from compaction; (iv) for natural shales, mineralogy controls the pore-size distributions for shales and the presence of micropores and fine mesopores in natural shales can be correlated
with the dominance of the illite-smectite type of clays in the rock. Our assessment of incompressible 3 nm sized pores associated with illite-smectite clays provides an important building block for their mineral modulus.

Specific surface area and pore‐size distribution in clays and shales

Porosity plays a clearly important role in geology. It controls fluid storage in aquifers, oil and gas fields and geothermal systems, and the extent and connectivity of the pore structure control fluid flow and transport through geological formations, as well as the relationship between the properties of individual minerals and the bulk properties of the rock. In order to quantify the relationships between porosity, storage, transport and rock properties, however, the pore structure must be measured and quantitatively described. The overall importance of porosity, at least with respect to the use of rocks as building stone was recognized by TS Hunt in his “Chemical and Geological Essays” (1875, reviewed by JD Dana 1875) who noted:

> “Other things being equal, it may properly be said that the value of a stone for building purposes is inversely as its porosity or absorbing power.”

In a Geological Survey report prepared for the U.S. Atomic Energy Commission, Manger (1963) summarized porosity and bulk density measurements for sedimentary rocks. He tabulated more than 900 items of porosity and bulk density data for sedimentary rocks with up to 2,109 porosity determinations per item. Amongst these he summarized several early studies, including those of Schwarz (1870–1871), Cook (1878), Wheeler (1896), Buckley (1898), Gary (1898), Moore (1904), Fuller (1906), Sorby (1908), Hirschwald (1912), Grubenmann et al. (1915), and Kessler (1919), many of which were concerned with rocks and clays of commercial utility. There have, of course, been many more such determinations since that time.

There are a large number of methods for quantifying porosity, and an increasingly complex idea of what it means to do so. Manger (1963) listed the techniques by which the porosity determinations he summarized were made. He separated these into seven methods for …

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Characterization and Analysis of Porosity and Pore Structures

Gaseous flow regimes through tight porous media are described by rigorous application of a unified Hagen–Poiseuille-type equation. Proper implementation is accomplished based on the realization of the preferential flow paths in porous media as a bundle of tortuous capillary tubes. Improved formulations and methodology presented here are shown to provide accurate and meaningful correlations of data considering the effect of the characteristic parameters of porous media including intrinsic permeability, porosity, and tortuosity on the apparent gas permeability, rarefaction coefficient, and Klinkenberg gas slippage factor.

Effective Correlation of Apparent Gas Permeability in Tight Porous Media

Thirty Years of Gas Shale Fracturing: What Have We Learned?

Petrophysical Considerations in Evaluating and Producing Shale Gas Resources

This work addresses the problem of estimating Klinkenbergcorrected permeability from single-point, steady-state measurements on samples from low permeability sands. The "original" problem of predicting the corrected or "liquid equivalent" permeability (i.e., referred to as the Klinkenbergcorrected permeability) has been under investigation since the early 1940s — in particular, using the application of "gas

Improved Permeability Prediction Relations for Low Permeability Sands

This paper presents a work-flow process to describe and characterize tight gas sands. The ultimate objective of this work-flow is to provide a consistent methodology to systematically integrate both large-scale geologic elements and small-scale rock petrology with the physical rock properties for low-permeability sandstone reservoirs. To that end, our work-flow integrates multiple data evaluation techniques and multiple data scales using a core-based rock typing approach that is designed to capture rock properties characteristic of tight gas sands. Fundamental to this process model are identification and comparison of three different rock types — depositional, petrographic, and hydraulic. These rock types are defined as: ● Depositional — These are rock types that are derived from core-based descriptions of genetic units which are defined as collections of rocks grouped according to similarities in composition, texture, sedimentary structure, and stratigraphic sequence as influenced by the depositional environment. These rock types represent original large-scale rock properties present at deposition. ● Petrographic — These are rock types which are also described within the context of the geological framework, but the rock type criteria are based on pore-scale, microscopic imaging of the current pore structure — as well as the rock texture and composition, clay mineralogy, and diagenesis. ● Hydraulic — These are rock types that are also defined at the pore scale, but in this case we define "hydraulic" rock types as those that quantify the physical flow and storage properties of the rock relative to the native fluid(s) — as controlled by the dimensions, geometry, and distribution of the current pore and pore throat structure. Each rock type represents different physical and chemical processes affecting rock properties during the depositional and paragenetic cycles. Since most tight gas sands have been subjected to post-depositional diagenesis, a comparison of all three rock types will allow us to assess the impact of diagenesis on rock properties. If diagenesis is minor, the depositional environment (and depositional rock types) as well as the expected rock properties derived from those depositional conditions will be good predictors of rock quality. However, if the reservoir rock has been subjected to significant diagenesis, the original rock properties present at deposition will be quite different than the current properties. More specifically, use of the depositional environment and the associated rock types (in isolation) to guide field development activities may result in ineffective exploitation.

Rock Typing: Keys to Understanding Productivity in Tight Gas Sands

We measured Mercury Injection Capillary Pressure (MICP) profiles on tight shale samples with a variety of sample sizes. The goal was to optimize the rock preparation and data reduction workflow for determining the storage properties of the rock, particularly porosity, from MICP measurements. The rock material was taken from a whole core in the Cretaceous Eagle Ford Formation in the form of a puck or disc. A horizontal 1 inch core plug was cut from this disc and the remaining material was subsequently crushed and sieved through various mesh sizes. MICP profiles up to 60,000 psia were then measured on the 1 inch plug and all of the various crushed and sieved rock particle sizes. In parallel we subsampled the plug material to measure bulk volume, grain volume, and porosity using a crushed rock helium pycnometry method. These additional measurements provided a comparison set of standard petrophysical properties from which we could compare the MICP results. In general our MICP profiles show a very strong dependence on sample size due to two reasons: pore accessibility and conformance. We verify the conformance correction approach of Bailey (2009) which specifically accounts for the pore volume compression of the sample before mercury has been injected into the largest set of interconnected pore throats. This new method is preferred over the traditional method of conformance correction when compared to crushed rock helium porosity since the latter is performed at unstressed conditions. Our results using Bailey’s (2009) method reveals that the 20+35 sample size is optimal for determining porosity in the Eagle Ford, and potentially other tight oil and gas shales. We use mercury injection for determining the various storage properties of tight shale because helium porosimetry is not always possible on fine cuttings samples. There are many instances when limited cuttings may be the only source of rock information available before a whole core is taken. Cuttings profiles also provide a key insight over long formation intervals that may not be available from whole core. Cuttings and core profiles for use in calibrating well logs have proven to be a requirement in these ultra-low perm systems. Introduction The emergence of shale and oil plays in North America has caused the industry to re-examine the methods which we use to quantify the resource and recoverable reserves in place. We recognize that unconventional gas and oil reservoirs are geologically and petrophysically heterogeneous at a variety of scales. This calls for a continuum of measurements to be used that are generally challenged due to the nano-scale pore nature of these rocks. A sampling of recent studies (Sondergeld et al., 2010; Passey et al., 2010; Spears et al., 2011) point out the lack of a standardized protocol such as that established for conventional and tight gas sand (microDarcy) systems in the API-RP40 (API, 1998). There is some common ground in that most laboratories follow a variation of the procedures established by Luffel and Guidry (1992) for determining storage capacity (crushed rock or GRI porosity) and flow capacity (pressure or pulse decay permeability). Other tools such as image analysis via focused ion-beam milling (FIB) and scanning electron microscopy (SEM) (Loucks et al. 2009; Curtis et al., 2010), and direct nuclear magnetic resonance (NMR) detection of fluids in place (Sigal and Odusina, 2010; Ramirez et al., 2011) are currently being researched by both industry and academia alike. We focus on a specific technology known as Mercury Injection Capillary Pressure (MICP) for determining the porosity and density of small and/or irregular samples such as cuttings or crushed whole core material. Several studies (Olson and Grigg,

Sample Size Effects on the Application of Mercury Injection Capillary Pressure for Determining the Storage Capacity of Tight Gas and Oil Shales

This paper presents results from a laboratory study comparing Klinkenberg-corrected permeability measurements in tight gas sands using both a conventional steady-state technique and two commercially-available unsteady-state permeameters. We also investigated the effects of various rate and pressure testing conditions on steady-state flow measurements. Our study shows the unsteady-state technique consistently overestimates the steady-state permeabilities, even when the steady-state measurements are corrected for gas slippage and inertial effects. The differences are most significant for permeabilities less than about 0.01 md. We validated the steady-state Klinkenberg-corrected permeabilities with liquid permeabilities measured using both brine and kerosene. Although gas slippage effects are more pronounced with helium than with nitrogen, we also confirmed the steady-state results using two different gases. Moreover, we show results are similar for both constant backpressure and constant mass flow rate test conditions. Finally, our study illustrates the importance of using a finite backpressure to reduce non-Darcy flow effects, particularly for ultra low-permeability samples.

Kent Edward Newsham

Papers

Petrophysical Considerations in Evaluating and Producing Shale Gas Resources

Improved Permeability Prediction Relations for Low Permeability Sands

Rock Typing: Keys to Understanding Productivity in Tight Gas Sands

Sample Size Effects on the Application of Mercury Injection Capillary Pressure for Determining the Storage Capacity of Tight Gas and Oil Shales

Klinkenerg-Corrected Permeability Measurements in Tight Gas Sands: Steady-State Versus Unsteady-State Techniques