Jay Alan Rushing

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.

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.

Evaluating the Impact of Waterfrac Technologies on Gas Recovery Efficiency: Case Studies Using Elliptical Flow Production Data Analysis

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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.

Post-Fracture Performance Diagnostics for Gas Wells With Finite-Conductivity Vertical Fractures

This paper presents an integrated technique for evaluating the production performance of gas wells with finite-conductivity vertical fractures. Our methodology combines conventional pressure transient test analysis with new material balance decline type curves developed specifically for gas wells with finite-conductivity, vertical fractures. We utilize short-term pressure buildup test analysis to enhance the production data analysis, particularly for interpretation of early-time transient flow behavior. We illustrate—with several field cases—that both techniques can be integrated to provide not only a more consistent and systematic analysis methodology, but also a more accurate assessment of stimulation effectiveness. Introduction Wells producing from tight gas sands require stimulation to achieve economic rates and to maximize ultimate recoveries. The most common stimulation technique is hydraulic fracturing. Depending on the type and size of the treatment, hydraulic fracturing may be expensive—often representing a significant percentage of the total completion costs. Since the economic viability of wells completed in tight gas sands depends on minimizing costs, then it is essential that we optimize fracture treatments, i.e., find the proper balance between stimulation costs and well productivity. A key component in achieving this balance is a post-fracture diagnostics program to determine stimulation effectiveness. Many diagnostic techniques for evaluating hydraulicallyfractured gas well performance have been documented in the petroleum industry, but theoretical model assumptions, model applicability and simplicity, data requirements, and/or data quality and quantity may limit the effectiveness of any single analysis technique. Therefore, we employ an integrated approach in which we capture the benefits and utilize the strengths of several types of hydraulically-fractured well diagnostic techniques. Cipolla and Wright and Barree, et al. have identified and grouped fractured-well diagnostic techniques into three general categories—direct far-field, direct near-wellbore, and indirect. Our methodology focuses on two indirect diagnostic techniques—pressure transient testing and production data analysis. Specifically, we illustrate how short-term pressure buildup testing integrated with long-term production data analysis can be an effective method for evaluating stimulation effectiveness. Indirect Fractured-Well Diagnostic Techniques Although pressure buildup testing is the most effective indirect technique for evaluating the stimulation effectiveness of hydraulically fractured gas wells, knowledge of reservoir permeability—either from the well test or from an independent source—is required to compute fracture properties. If a well is shut in for a sufficient duration to reach the pseudoradial flow period, then we can uniquely determine reservoir permeability from the test data (and very likely also estimate effective fracture half-length and fracture conductivity since these are dependent on the permeability estimate). Wells completed in tight gas sands require very long shut-in times to reach pseudoradial flow, but operators are reluctant to shut in a well for extended periods. If, however, we have an independent estimate of reservoir permeability, then shorter duration pressure buildup tests become practical. Decline type curve analysis of production data has become a common alternative for estimating reservoir permeability without shutting in the well. Fetkovich was the first to incorporate transient flow models with decline curve analysis. He developed the standard “decline type curves” by combining an analytical model for transient, radial flow at constant bottomhole pressure with Arps’ empirical exponential and hyperbolic rate decline models. We note for completeness that the exponential rate decline model is the analytical solution for a well produced at a constant bottomhole flowing pressure and boundary-dominated flow conditions. The original Fetkovich decline type curves are useful for a range of reservoir pressure conditions, but we have observed cases where the boundary-dominated rate-time data changes evaluation curves over time (i.e., changes from one empirical model or stem to another). These changes have been attributed to changes in gas properties as a function of reservoir pressure. To address the impact of pressuredependent gas properties on the evaluation of gas production SPE 97972 Post-Fracture Performance Diagnostics for Gas Wells With Finite-Conductivity Vertical Fractures J.A. Rushing, SPE, and R.B. Sullivan, SPE, Anadarko Petroleum Corp., and T.A. Blasingame, SPE, Texas A&M U.