Slug Test Data Analysis, Including The Inertia Effect Of The Fluid In The Wellbore
Authors: Shinohara Kiyoshi , Ramey Henry J. 
Published: December 2007

In a "slug test," a finite amount of fluid is removed suddenly from a static well in order to obtain information on the reservoir. This is a useful method as a short-time well test. The solution for this problem is old, and has been investigated by many people. problem is old, and has been investigated by many people. However, the available type-curves thus far do not include the inertia effect of the fluid in the wellbore and cannot explain oscillations of pressure in the wellbore.

In this study, a complete solution for this problem is obtained and the effects of some parameters problem is obtained and the effects of some parameters are investigated. The solution for closed chamber tests is discussed as an extension of the general slug test solution.

Introduction

Often in drill stem tests the flow period data are characterized by a pressure trace which increases with increasing time, showing the accumulation of fluid in the drill string. In some cases the pressure time trace is linear at the beginning of the flow period, and then the curves become concave to the time period, and then the curves become concave to the time axis, showing an initial constant flow rate and then a decreasing flow rate. In other cases the curves are concave to the time axis from the beginning of the flow period, showing a decreasing rate throughout the flow period.

In the case where the formation pressure is too low to lift a column of the reservoir fluid to the surface, the well may actually stop flowing before the DST valve is closed. This results because the head of the fluid in the drill string becomes equal to the initial formation pressure. In rare cases with high productivity formations, the fluid level in the productivity formations, the fluid level in the wellbore may oscillate around a stable or eventual static level.

In any event, the initial portion of a DST may be viewed as a test in which a column of fluid whose head is equal to the initial formation pressure has been removed instantaneously. This sort of test is similar to transient test called a "slug test by Ferris and Knowles in 1954. The word "slug" refers to the initial volume of fluid which would cause a head equal to the initial formation pressure. It is also equal to the volume of fluid which would be produced by the time the well became static if formation produced by the time the well became static if formation pressure were too low to lift a column of reservoir pressure were too low to lift a column of reservoir fluid to the surface.

A similar test involving the cooling of a batch of hot water was reported by Beck et al. in 1956. Cooper et al., 1967, reported the results of a field test in a static water well from which a float was suddenly removed, giving the appearance of the sudden removal of a quantity of water equal to that displaced by the float. Maier presented an approximate analysis of the equivalent DST problem in 1970.

van Poollen and Weber, in 1970, and Kohlhaas, in 1972, applied the Cooper et al. solution to DST flow period data analysis. Although most current studies refer to the study by Jaeger, in 1956, which included a surface resistance similar to the skin effect, most recent works do not include wellbore damage effects. A solution including the skin effect was presented by Agarwal et al. in 1970 and 1972, although the use of the solutions was not demonstrated. Papadopulous et al. presented extended results for Papadopulous et al. presented extended results for the zero skin effect case in 1973.

The most complete discussion of DST applications of the slug test solutions was presented in 1975 by Ramey et al. Three new slug test type-curves were developed for analysis of flow period data. This study was reviewed in the Earlougher monograph in 1977, and did include wellbore skin effects.

The solutions mentioned thus far did not consider the momentum of the fluid in the wellbore. In deep wells in high productivity formations, the inertia and momentum of the fluid in the wellbore cannot be neglected. Sometimes the inertia effect causes an oscillation of the pressure in the wellbore about static positions. positions. This inertia effect of the movement of fluid in the wellbore was first investigated by Bredehoeft et al. in 1966, using an analog computer. However, general solutions were not given.