Kent Edward Newsham

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

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.

A Comparative Study of Capillary-Pressure-Based Empirical Models for Estimating Absolute Permeability in Tight Gas Sands

This paper presents the results of a laboratory study where we compare permeability estimates obtained from several mercury-injection capillary-pressure-based models to a set of measured (steady-state), Klinkenberg 1 -corrected permeability in tight gas sands. We evaluated 63 core samples from several prolific tight gas reservoirs in the U.S. Steady-state permeability and mercury-injection capillary pressure tests were completed on each sample. The permeability samples range is from 0.0001 mD to 0.2 mD. We review a variety of currently-employed models that are classified as belonging to either Poiseuille or Percolation/ Characteristic Length models. We identify those correlations that are best applied in tight gas sands by quantifying each methods accuracy and precision and force rank each based on error analysis score.

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

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,

A Modified Purcell/Burdine Model for Estimating Absolute Permeability from Mercury-Injection Capillary Pressure Data

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A Comparative Study of Laboratory Techniques for Measuring Capillary Pressures in Tight Gas Sands

This paper presents results from a laboratory study comparing capillary pressure measurement techniques for tight gas sands. Included in our evaluation are the more traditional high-speed centrifuge and high-pressure mercury injection methods as well as the less conventional high-pressure porous plate and vapor desorption techniques. The results of our study show significant differences between the mercury injection data and composite capillary pressure curves constructed with data from the other three methods. Consequently, we have concluded that high-pressure mercury injection can be used to quantify pore size distribution, but often inaccurately characterizes capillary pressures, particularly at the irreducible water saturation. Moreover, our study suggests that a composite capillary pressure curve constructed from a combination of the vapor desorption data for the low water saturation range and high-speed centrifuge or high-pressure porous plate data for the high saturation range provides the most accurate capillary pressures for tight gas sands.

Beyond Decline Curves: Life-Cycle Reserves Appraisal Using an Integrated Work- Flow Process for Tight Gas Sands

Decline curve analysis is often either the only or the primary tool used for reserve evaluations in tight gas sands. However, the flow and storage properties characteristic of lowpermeability sands often preclude accurate assessments using only or primarily decline curve analysis, especially early in the productive life. The most accurate reserve estimates incorporate multiple data sources and the appropriate evaluation techniques. Therefore, this paper presents a reserves appraisal work-flow process that complements traditional decline curve analyses with comprehensive and systematic data acquisition and evaluation programs that integrate both static and dynamic data. Our approach—which has been developed specifically to incorporate the production characteristics of tight gas sands— is an adaptive process that allows continuous but reasonable reserve adjustments over the entire field development and production life cycle. Implementing this process will prevent unrealistic (either too low or high) reserve bookings. Although it is applicable during any field development phase, our work-flow process is most beneficial during early stages before true boundary-dominated flow conditions have been reached and when reserve evaluation errors are most likely.