Paper Number 18801-PA
DOI What's this? 10.2118/18801-PA
Title A New General Pressure Analysis Procedure for Slug Tests
Authors Peres, Alvaro M.M., Onur, Mustafa, Reynolds, Albert C., U. of Tulsa
Journal SPE Formation Evaluation
Volume Volume 8, Number 4
Date December 1993
Pages 292-298
Copyright 1993. Society of Petroleum Engineers
Preview Summary
A new analysis procedure for determining formation flow capacity and skin factor from slug-test data is presented. The procedure arises from exact deconvolution equations that convert procedure arises from exact deconvolution equations that convert measured slug-test pressure data into equivalent pressure and pressure-derivative responses that would be obtained if the well pressure-derivative responses that would be obtained if the well were produced at a constant surface flow rate. The converted data then can be analyzed by use of existing wellbore-storage and skin type curves for the particular reservoir or well model represented by the field data. For cases where the slug test is short, we show that now rate convolution can be incorporated to improve analysis reliability. The analysis procedures do not require direct knowledge of the sandface flow rate.
Introduction
In the standard slug-test configuration, an instantaneous pressure drop is imposed on the formation by adding or removing a small amount of fluid from the wellbore. Reservoir properties then can be estimated by analyzing the wellbore pressure change by use of techniques discussed in this work. Ferris and Knowles proposed the first slug-test analysis procedure. By deriving a longtime asymptotic solution for a procedure. By deriving a longtime asymptotic solution for a line-source well, they showed that flow capacity could be estimated from the slope of a Cartesian plot of wellbore pressure vs. the reciprocal time. Cooper et al. presented a solution for a finite-radius well and verified that Ferris and Knowles' method became valid only at long times. Cooper et al. also presented semilog type curves from which the reservoir permeability and the porosity/compressibility product could be determined by type-curve porosity/compressibility product could be determined by type-curve matching. Because of the shape similarity of the curve solutions, however, they pointed out that the accuracy of the porosity/compressibility product obtained from this type-curve porosity/compressibility product obtained from this type-curve matching procedure was questionable.
Cooper et al.'s slug-test type curves were introduced to petroleum engineers by van Poollen and Weber and by Kohlhaas. petroleum engineers by van Poollen and Weber and by Kohlhaas. Ramey and Agarwal incorporated the skin effect into slug-test solutions with the infinitesimally thin skin concept of van Everdingen and Hurst. Later, Ramey et al. presented semilog and log-log slug-test type curves with the correlating group CsD exp(2s) that Earlougher and Kersch suggested. Since then, type-curve matching has become the procedure for analyzing slug-test pressure data. Although the correlating group used in constructing these pressure data. Although the correlating group used in constructing these type curves is not mathematically rigorous, the reliability of the correlation has been verified for large values of the wellbore-storage coefficient. Sageev further investigated the validity of Earlougher and Kersch's correlating group. On the basis of early-time asymptotic approximations, Ref. 10 proposed one type curve for zero-skin cases and a different type curve for nonzero-skin cases.
The Ramey et al. slug-test type curves are strictly applicable for only a fully penetrating well in a homogeneous, infinite reservoir; therefore, specific slug-test type curves must be generated for different flow geometries (e.g., linear and spherical) and reservoir models. Mateen and Ramey and Sageev and Ramey investigated the slug-test pressure response in a double-porosity reservoir for a fully penetrating well. Dougherty and Babu derived slugtest solutions for a restricted-entry well.
For radial flow to a well in a homogeneous, infinite-acting reservoir, Ramey and Agarwal showed that the dimensionless-pressure solution for the slug-test problem was directly proportional to the derivative of the dimensionless-pressure solution of the classic wellbore-storage and skin problem. Ayoub et al.'s Fig. 8 illustrated the preceding Ramey and Agarwal result. Ayoub et al. also introduced impulse preceding Ramey and Agarwal result. Ayoub et al. also introduced impulse testing to analyze shut-in pressure data obtained after a short producing time. They show that, at sufficiently late shut-in times, shut-in pressure drop multiplied by shut-in time will be approximately equal to the pressure-derivative data that would be obtained for the equivalent pressure-derivative data that would be obtained for the equivalent constant-rate drawdown problem. Cinco-Ley et al. present a more complete discussion with more mathematical theory details for generating drawdown pressure-derivative data directly from buildup data obtained after a short pressure-derivative data directly from buildup data obtained after a short flow period. Ref. 16 noted that the shut-in time must exceed twice the producing time before the previous procedure can be used to convert shut-in producing time before the previous procedure can be used to convert shut-in pressure data to the equivalent drawdown pressure-derivative data. pressure data to the equivalent drawdown pressure-derivative data. In this work, we present a new slug-test analysis procedure. The underlying theory for our analysis is that slug-test data can be used to generate pressure and pressure-derivative data that would be obtained for the equivalent wellbore-storage and skin problem. Unlike the buildup procedure of Refs. 15 and 16, we problem. Unlike the buildup procedure of Refs. 15 and 16, we generate both pressure and pressure-derivative data and perform a simultaneous match of these data with the appropriate pressure and pressure-derivative type curves. If the slug test is short, most of pressure-derivative type curves. If the slug test is short, most of the converted data will fall on the unit-slope line of the conventional constant-rate wellbore-storage and skin type curves, making it difficult to obtain a unique type-curve match. For such cases, we present a rate-convolution method to improve analysis reliability. Surprisingly, this convolution method does not require knowledge of sandface flow rates.
Definitions
Different dimensionless-pressure solutions are considered in this work. Throughout, pwD is the dimensionless wellbore-pressure solution of the slug-test problem under consideration, and pwcD is the dimensionless wellbore-pressure solution that would be obtained for the same wellbore or reservoir problem if the well were produced at a constant surface flow rate. The pwcD solution produced at a constant surface flow rate. The pwcD solution incorporates wellbore-storage and skin effects. The corresponding dimensionless wellbore-pressure solution for production at a con- stant sandface rate is and represents the solution obtained when wellbore-storage effects are negligible.
