Thomas Alwin Blasingame

Analysis of Mechanisms of Flow in Fractured Tight-Gas and Shale-Gas Reservoirs

In this paper we analyze by means of numerical simulation the mechanisms and processes of flow in two types of fractured tight gas reservoirs: shale and tight-sand systems. The numerical model includes Darcy’s law as the basic equation of multiphase flow and accurately describes the thermophysical properties of the reservoir fluids, but also incorporates other options that cover the spectrum of known physics that may be involved: non-Darcy flow, as described by a multi-phase extension of the Forschheimer equation that accounts for laminar, inertial and turbulent effects; stress-sensitive flow properties of the matrix and of the fractures, i.e., porosity, permeability, relative permeability and capillary pressure; gas slippage (Klinkenberg) effects; and, non-isothermal effects, accounting for the consequences of energy balance and temperature changes in the presence of phenomena such as Joule-Thompson cooling in the course of gas production. The flow and storage behavior of the fractured media (shale or tight sand) is represented by various options of the Multiple Interactive Continua (MINC) conceptual model, in addition to an Effective Continuum Method (ECM) option, and includes a gas sorption term that follows the Langmuir isotherm. Comparison to field data, analysis of the simulation results and parameter determination through history matching indicates that (a) the ECM model is incapable of describing the fractured system behavior, and (b) shale and tight-sand reservoirs exhibit different behavior that can be captured (albeit imperfectly) using some of the more complex options of the multi-continua fractured-system models. The sorption term is necessary to describe the behavior of shale gas reservoirs, and significant deviations from the field data are observed if it is omitted. Conversely, production data from tight-sand reservoirs can be adequately represented without accounting for gas sorption. All the other processes and mechanisms allow refinement of the match between predictions and observations, but appear to have secondorder effects in the description of flow through fractured tight gas reservoirs.

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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Development and Application of the Multiwell Productivity Index (MPI)

In this article we generalize the concept of the pseudosteady-state productivity index for the case of multiple wells producing from or injecting into a closed rectangular reservoir of constant thickness. The work complements the analytical study by Rodriguez and Cinco-Ley for systems produced at constant flowing pressures. Wells are represented by fully penetrating vertical line sources located arbitrarily in a homogeneous and isotropic reservoir. The multiwell productivity index ~MPI! is a square matrix of dimension n, where n is the number of wells. The MPI provides a simple, reasonably accurate and fast analytical tool to evaluate well performance without dividing the cluster into single-well drainage areas. The MPI approach is used to obtain approximate analytical solutions for constant ~but possibly different! wellbore flowing pressures, and to visualize the resulting pressure field. In addition, the skin factor trace technique is introduced as a tool to monitor a cluster of wells. The MPI technique is illustrated using a synthetic example taken from Ref. 2, as well as two field cases.

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.

Simplified Correlations for Hydrocarbon Gas Viscosity and Gas Density - Validation and Correlation of Behavior Using a Large-Scale Database

The focus of this work is the behavior of gas viscosity and gas density for hydrocarbon gas mixtures. The viscosity of hydrocarbon gases is a function of pressure, temperature, density, and molecular weight, while the gas density is a function of pressure, temperature, and molecular weight. This work presents new approaches for the prediction of gas viscosity and gas density for hydrocarbon gases over practical ranges of pressure, temperature and composition. These correlations can be used for any hydrocarbon gas production or transportation operations. In this work we created an extensive database of measured gas viscosity and gas density (>5000 points for gas viscosity and >8000 points for gas density). This database was used to evaluate existing models for gas viscosity and gas density. In this work we provide new models for gas density and gas viscosity, as well as optimization of existing models using this database.

A Semianalytic Solution for Flow in Finite-Conductivity Vertical Fractures by Use of Fractal Theory

The exploitation of unconventional reservoirs complements the practice of hydraulic fracturing, and with an ever-increasing demand in energy, this practice is set to experience significant growth in the coming years. Sophisticated analytic models are needed to accurately describe fluid flow in a hydraulic fracture, and the problem has been approached from different directions in the past 3 decades—starting with the work of Gringarten et al. (1974) for an infinite-conductivity case, followed by contributions from Cinco-Ley et al. (1978), Lee and Brockenbrough (1986), Ozkan and Raghavan (1991), and Blasingame and Poe (1993) for a finite-conductivity case. This topic remains an active area of research and, for the more-complicated physical scenarios such as multiple transverse fractures in ultratight reservoirs, answers are currently being sought. Starting with the seminal work of Chang and Yortsos (1990), fractal theory has been successfully applied to pressure-transient testing, although with an emphasis on the effects of natural fractures in pressure/rate behavior. In this paper, we begin by performing a rigorous analytical and numerical study of the fractal diffusivity equation (FDE), and we show that it is more fundamental than the classic linear and radial diffusivity equations. Thus, we combine the FDE with the trilinear flow model (Lee and Brockenbrough 1986), culminating in a new semianalytic solution for flow in a finite-conductivity vertical fracture that we name the “fractal-fracture solution (FFS).” This new solution is instantaneous and comparable in accuracy with the Blasingame and Poe solution (1993). In addition, this is the first time that fractal theory is used in fluid flow in a porous medium to address a problem not related to reservoir heterogeneity. Ultimately, this project is a demonstration of the untapped potential of fractal theory; our approach is flexible, and we believe that the same methodology could be extended to different applications. One objective of this work is to develop a fast and accurate semianalytical solution for flow in a single vertical fracture that fully penetrates a homogeneous infinite-acting reservoir. This would be the first time that fractal theory is used to study a problem that is not related to naturally fractured reservoirs or reservoir heterogeneity. In addition, as part of the development process, we revisit the fundamentals of fractals in reservoir engineering and show that the underlying FDE possesses some interesting qualities that have not yet been comprehensively addressed in the literature.

A Semi-Analytic (p/z) Rate-Time Relation for the Analysis and Prediction of Gas Well Performance

In this paper we present a rigorous theoretical development of solutions for boundary-dominated gas flow during reservoir depletion. These solutions were derived by directly coupling the stabilized flow equation with the gas material balance equation. Due to the highly nonlinear nature of the gas flow equation, pseudopressure and pseudotime functions have been used over the years for the analysis of production rate and cumulative production data. While the pseudopressure and pseudotime functions do provide a rigorous linearization of the gas flow equation, these transformations do not provide direct solutions. In addition, the pseudotime function requires the average reservoir pressure history, which in most cases is simply not available. Our approach uses functional models to represent the viscosity-compressibility product as a function of the reservoir pressure/z-factor (p/z) profile. These models provide approximate, but direct, solutions for modeling gas flow during the boundary-dominated flow period. For convenience, the solutions are presented in terms of dimensionless variables and expressed as type curve plots. Other products of this work are explicit relations for p/z and Gp(t). These solutions can be easily adapted for field applications such as the prediction of rate or cumulative production. We also provide verification of our new flow rate and pressure solutions using the results of numerical simulation and we demonstrate the application of these solutions using a field example.

Improving recovery from mature oil fields producing from carbonate reservoirs: Upper Jurassic Smackover Formation, Womack Hill field (eastern Gulf Coast, U.S.A.)

Reservoir characterization, modeling, and simulation were undertaken to improve production from Womack Hill field (eastern Gulf Coast, United States). This field produces oil from Upper Jurassic Smackover carbonate shoal reservoirs. These reservoirs occur in vertically stacked, heterogeneous depositional and porosity cycles. The cycles consist of lime mudstone and wackestone at the base and ooid grainstone at the top. Porosity has been enhanced through dissolution and dolomitization. Porosity is chiefly interparticle, solution-enlarged interparticle, grain moldic, intercrystalline dolomite, and vuggy pores. Dolostone pore systems and flow units have the highest reservoir potential. Petroleum-trapping mechanisms include a fault trap (footwall uplift with closure to the south against a major west-southeast–trending normal fault) in the western area, a footwall uplift trap associated with a possible southwest-northeast–trending normal fault in the south-central area, and a salt-cored anticline with four-way dip closure in the eastern area. Potential barriers to flow are present as a result of petrophysical differences among and within the cycles, as well as the presence of normal faulting. Reservoir performance analysis and simulation indicate that the unitized western area has less than 1 MMSTB of oil remaining to be recovered, and that the eastern area has 2–3 MMSTB of oil to be recovered. A field-scale reservoir management strategy that includes the drilling of infill wells in the eastern area of the field and perforating existing wells in stratigraphically higher porosity zones in the unitized western area is recommended for sustaining production from the Womack Hill field.