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Results
Klinkenerg-Corrected Permeability Measurements in Tight Gas Sands: Steady-State Versus Unsteady-State Techniques
Rushing, J.A. (Anadarko Petroleum Corp.) | Newsham, K.E. (Apache Corp.) | Lasswell, P.M. (OMNI Laboratories Inc.) | Cox, J.C. (Texas Tech University) | Blasingame, T.A. (Texas A&M University)
Abstract 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. Introduction Permeability measurements in core samples are based on the observation that, under steady-state flowing conditions, the pressure gradient is constant and is directly proportional to the fluid velocity. This constant of proportionality, as defined by Darcy's law, Equation 1 is the absolute core permeability, k8. This relationship has been validated for a wide range of flow velocities. For cores with permeabilities less than about 0.1 md, steady-state flow is difficult to achieve in a reasonable test time, especially when liquid is the flowing fluid. Consequently, gas is routinely used in low-permeability core samples. However, gas flow in tight gas sands is often affected by several phenomena that may cause deviations from Darcy's law. Failure to account for these non-Darcy effects, principally gas slippage and inertial flow, may cause significant measurement errors. Gas slippage is a non-Darcy effect associated with non-laminar gas flow in porous media. These effects occur when the size of the average rock pore throat radius approaches the size of the mean free path of the gas molecules, thus causing the velocity of individual gas molecules to accelerate or "slip" when contacting rock surfaces. This phenomenon is especially significant in tight gas sands that are typically characterized by very small pore throats. Klinkenberg, who was one of the first to study and document gas slippage effects in porous media, showed the observed permeability to gas is a function of the mean core pressure. Furthermore, he observed that the gas permeability approaches a limiting value at an infinite mean pressure. This limiting permeability value, which is sometimes referred to as the equivalent liquid permeability or the Klinkenberg-corrected permeability, is computed from the straight-line intercept on a plot of measured permeability against reciprocal mean pressure. In equation form, the line is defined by Equation 2 where k is the Klinkenberg-corrected permeability and b is the gas slippage factor. Experimental studies by Krutter and Day, Calhoun and Yuster and Heid, et al., extended and validated the work of Klinkenberg.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- North America > United States > Texas > East Texas Salt Basin > Mimms Creek Field > Cotton Valley Group Formation > Cotton Valley Group Formation > Bossier Shale Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Mimms Creek Field > Cotton Valley Group Formation > Bossier Sand Formation > Bossier Shale Formation (0.99)
A Comparative Study of Laboratory Techniques for Measuring Capillary Pressures in Tight Gas Sands
Newsham, K.E. (Apache Corp.) | Rushing, J.A. (Anadarko Petroleum Corp.) | Lasswell, P.M. (OMNI Laboratories Inc.) | Cox, J.C. (Texas Tech University) | Blasingame, T.A. (Texas A&M University)
Abstract 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. Introduction Tight gas sands constitute a significant percentage of the domestic natural gas resource base and offer tremendous potential for future reserve growth and production. Since tight gas sands often exhibit unique gas storage and producing characteristics, effective exploitation requires accurate description of key reservoir parameters, particularly capillary pressures to quantify the vertical water saturation distribution and resource-in-place. Furthermore, the combination of low connate water saturations and high capillary pressures characteristic of many low-permeability systems often precludes use of most conventional laboratory measurement techniques that are most applicable in reservoirs with higher permeabilities and porosities. To date, no comprehensive evaluation of capillary pressure measurement techniques for tight gas sands has been published in the petroleum literature. Accordingly, this paper presents a comparative study of all current laboratory methods, including the more traditional high-speed centrifuge and high-pressure mercury injection methods and the less conventional high-pressure porous plate and vapor desorption techniques. Twenty-five core samples, taken from wells producing in the Lower Cotton Valley/Bossier tight gas sands in the East Texas and North Louisiana Salt Basins, are used in the study. Core properties, representing most of the entire range of productive sands, include porosities from about 2% to 14% and Klinkenberg-corrected permeabilities ranging from about 0.0005 md to 0.5 md. Water saturations, which typically range from 5% to 60% in these sands, are also associated with very high capillary pressures.
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.99)
- North America > United States > Louisiana > North Louisiana Salt Basin (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)