Stephen A. Holditch

Tight Gas Sands

Tight gas sands are defined as sandstone formations with less than 0.1 millidarcy permeability. The millidarcy is a unit of measurement related to the ability of a fluid to pass through a porous medium. The degree of permeability depends upon the size and shape of the pores, the size and shape of their interconnections, and the extent of the latter. It has been estimated that total-gas-in-place in the United States may exceed 15,000 trillion cubic feet. The size, location, and quality of the resource varies.

Application of Pseudotime to Buildup Test Analysis of Low-Permeability Gas Wells With Long-Duration Wellbore Storage Distortion

An imporved method is presented for analyzing pressure transient tests in low-permeability gas wells that is based on a nonlinear form of the diffusivity equation rather than the linear form associated with liquid flow. This review delineates a theoretical basis for plotting pseudopressure changes against elapsed pseudotime to obtain a curve that in some cases corresponds to a type curve derived for a slightly compressible liquid with constant wellbore storage. Computer simulated tests and field data both support the theoretical results, suggesting that (1) the use of both pseudotime and pseudopressure yields linear equations for modeling gas flow in reservoirs and (2) types curves developed for slightly compressible liquids with unchanging wellbore storage constants can be used for gas well tests following large pressure drawdowns if analyzed using pseudotime and pseudopressure.

A Method for Simultaneous Determination of Permeability and Porosity in Low-Permeability Cores

Determining the porosity and permeability of a formation has always been basic to understanding petroleum reservoirs. In low permeability formations, the measurement of permeability from core samples is a difficult task. To complicate the problem, the porosity and permeability can be strongly dependent upon the net stress exerted on the core sample. Net stress, which is the difference between overburden stress and pore pressure, will increase as the reservoir pressure is depleted. A method for determining permeability with precision and reasonable speed can be quite important when one is trying to characterize a low permeability reservoir. The conventional (steady state flow) method for permeability determination is not adequate for low permeability cores. The low flow rates across the core plug are difficult to measure and control. In this paper, the authors describe an analytical model for gas flow through a core, and present a method for rapidly and simultaneously determining both the porosity and permeability of a low permeability core.

Permeability Estimation Using Hydraulic Flow Units in a Central Arabia Reservoir

Knowledge of permeability is critical to developing an effective reservoir description. Permeability data can be obtained from well tests, cores or logs. Normally, using well log data to derive estimates of permeability is the lowest cost method. To estimate permeability, we can use values of porosity, pore size distribution, and water saturation from logging data and established correlations. One benefit of using wireline log data to estimate permeability is that it can provide a continuous permeability profile throughout a particular interval. This paper will focus on the evaluation of formation permeability for a sandstone reservoir in Central Arabia from well log data using the concept of Hydraulic Flow Units (HFU). Cluster analysis is used to identify the hydraulic flow units. We have developed a new clustering technique that is unbiased and easy to apply. Moreover, a procedure for determining the optimal number of clusters that should be used in the HFU technique will be introduced. In this procedure, the sum of errors squared method was used as criterion for determining the required number of HFUs to describe the reservoir. In our work, the statistically derived hydraulic flow units were compared with the core description made at the well site by a geologist. The grain size classes from core description match very well with the statistically derived clusters from the HFU method. Our results indicate that hydraulic flow units correspond to different rock types in this Central Arabian Reservoir. Of course, direct measurement of rock properties using cores is the ideal method to determine HFUs. However, because the costs to cut and analyze cores are so high, few core measurements are routinely available. Hence, it is crucial to extend the flow unit determination to the un-cored intervals and wells. The relationship between core flow units and well log data was established by non-parametric regression in cored wells, and then was used as a tool to extend the flow units prediction to un-cored intervals and wells. Permeability estimation using the HFU method was extended to un-cored wells by implementing the Alternating Conditional Expectation (ACE) algorithm. ACE provides a data-driven approach for identifying the functional forms for the well log variables involved in the correlation. The reservoir porosity vs. permeability relationship was represented with single equation by using the different HFUs as indictor variables. Permeability profiles generated by HFUs using well log data agree with core data. A computer program was developed to perform hydraulic flow unit analysis. In the computer program, three main processing options were integrated, which are: ○ sensitivity runs are made to determine the optimal number of HFUs; ○ the analysis is then based on the optimal number of HFUs (or any user-defined number of HFUs); and ○ regression analysis is performed using the different HFUs as dummy variables to predict values permeability.

Reservoir Permeability Estimation From Time-Lapse Log Data

This paper presents a method to estimate permeability using time-lapse log data. The reservoir permeability values are also obtained by history matching production data and analyzing core data. These permeability values are in agreement with the estimates derived from logs. When a well is drilled, mud filtrate invades the formation around the borehole. The volume of mud-filtrate invasion is related to time, formation permeability, and other wellbore and formation parameters. As mud-filtrate invasion progresses, unique saturation profiles and, thus, unique profiles of resistivity and water saturation, are created in the formation surrounding the borehole. Therefore, the data from well logs change with time. By observing and analyzing the changes in log data vs. time, one can estimate formation permeability.

Kinetics and Mechanisms of Gas Hydrate Formation and Dissociation with Inhibitors

Abstract: A common chemical used in petroleum industry for preventing hydrates is methanol. Other alcohols and glycols (thermodynamic inhibitors) can also be used to shift hydrate formation to lower temperatures and higher pressures. A new family of chemicals called kinetic inhibitors delays the formation of hydrates, but does not change the equilibrium formation conditions. We have constructed several new types of apparatus and present results on the kinetics of hydrate formation and dissociation in static and dynamic conditions with fresh water and different solutions of water, seawater, and with thermodynamic and kinetic inhibitors. We also present new morphological forms of hydrate crystal growth in different static and dynamic conditions.

Determination of reservoir permeability from repeated induction logging

Description of a method for estimating permeability from time-lapse induction logging data.

An Investigation Into the Application of Fuzzy Logic to Well Stimulation Treatment Design

Designing an optimal stimulation treatment for an oil or gas well is a complex procedure requiring in-depth knowledge and experience. This paper describes how fuzzy logic applies to stimulation design and clearly illustrates how to apply fuzzy logic theory. The paper also discusses the advantages and disadvantages of applying fuzzy logic to well stimulation design. Fuzzy logic evaluators can be applied to study, evaluate, and determine the best methods to improve productivity in oil and gas wells or injectivity in water wells. The approach can be extended to the solution of other problems associated with drilling, completing, and working over wells and with formation damage diagnosis.

Minimizing damage to a propped fracture by controlled flowback procedures

Severe fracture-conductivity damage can result from proppant crushing and/or proppant flowback into the wellbore. Such damage is often concentrated near the wellbore and can directly affect postfracture performance. Most of the time severe fracture-conductivity damage can be minimized by choosing the correct type of proppant for a particular well. In many cases, however, this is not enough. To minimize excessive crushing or to prevent proppant flowback, it is also necessary to control carefully the flowback of the well after the treatment. Specific procedures can be followed to minimize severe fracture-conductivity damage. These procedures involve controlling the rates at which load fluids are recovered and maximizing backpressure against the formation. These procedures require much more time and effort than is normally spent on postfracture cleanup; however, the efforts could result in better performance.

Using a three-dimensional concept in a two-dimensional model to predict accurate hydraulic fracture dimensions

Abstract Hydraulic fracture treatments can be used to increase the oil and gas flow rates and ultimate recovery. A fracture treatment should be designed to optimize profit from the well. To design and optimize the fracture treatment, an engineer should use (1) a fracture propagation model, (2) a reservoir fluid flow model, and (3) an economics model. Inasmuch as a fracture treatment design involves selection of fracturing fluids, proppants, pump schedule and injection rate, this three-step procedure is repeated several times to obtain the best combination. Using a three-dimensional fracture propagation calculation tool in such a case is difficult and time consuming. In this paper, an easier approach is presented to approximate the three-dimensional fracture geometry by a two-dimensional fracture propagation calculation model in order to save significant amount of computer time.