Abstract

This paper presents new procedures for analyzing pressure buildup data obtained from drillstem tests. The new methods apply for cases where the produced fluid does not reach the surface during the flowing period so that, the flow period represents a slug test. The combined effects of variable flow rate, short producing time and changing wellbore storage generally make it producing time and changing wellbore storage generally make it difficult to apply conventional analysis methods to DST buildup data. Two new straight-line methods for analyzing buildup data presented in this work account for both the variable rate during the presented in this work account for both the variable rate during the flow period and producing time effects. If the buildup wellbore storage-skin group CSD exp(2s) is small, then shortly after shut-in, a well-defined straight line is obtained for both methods. Using the slope of the straight line obtained by either method, it is shown that the flow capacity kh), the skin factor (s) and the initial reservoir pressure (Pi) can be determined. If the group CSD exp(2s) is large, longer shut-in times are needed before the proper straight line can be obtained. However, for the latter case, it is shown that a multi-rate equivalent time can be constructed so that standard type-curve matching can be performed to obtain estimates of the flow capacity and the skin factor. A field example is presented to illustrate the applications of the proposed methods. proposed methods

Introduction

A drillstem test is a temporary well completion with the specific purposes of rock and fluid characterization under dynamic reservoir conditions. DST's are also used for monitoring reservoir and well condition in developed productive zones. Standard DST equipment and operational procedures have been described elsewhere in the literature. Essentially, the testing tool consists of a packer and a tester valve attached to the tail of the drill pipe packer and a tester valve attached to the tail of the drill pipe or production tubing. After the packer is set in position, the opening of the DST valve imposes a sudden pressure drop at formation face causing the reservoir fluid to be pushed into the wellbore, increasing the liquid level in the string. When the tester valve is closed for the buildup period, the wellbore storage coefficient decreases from one for a rising-liquid-level to one for fluid- compression, which may represent a reduction of two orders of magnitude in the storage coefficient.

For wells in which the liquid level does not reach the surface, the DST typically shows a variable, decreasing flow rate throughout the flow period. The flow period pressure data can be analyzed by conventional multi-rate techniques, though this is rarely done in practice. The standard procedure for analyzing DST flow data has been by type-curve matching the measured pressure data with the slug type curves presented by Cooper et al. and Ramey et al. Recently, Peres et al. presented by Cooper et al. and Ramey et al. Recently, Peres et al. presented a new procedure for DST flow and slug test analysis which presented a new procedure for DST flow and slug test analysis which converts the measured data into an equivalent constant rate problem. The "converted' data can then be analyzed by standard constant rate procedures (e.g. type-curve matching, semilog straight line procedures (e.g. type-curve matching, semilog straight line analysis).

Buildup analysis following a variable rate drawdown has been the object of several investigations. When the flow rate history is known, the multi-rate method of Ref. 11 can be used to analyze pressure buildup data. Horner also proposed a simplified approach in which the actual producing time is replaced by the ratio of the cumulative production to the last rate. Odeh and Selig presented expressions for correcting both the rate and flowing time in order to account for the flow rate variation on pressure buildup calculations. Dolan et al. verified that if the pressure buildup calculations. Dolan et al. verified that if the rate variation during the DST flow period is not severe, the use of the average production rate in the semilog slope of the Horner plot yields an accurate estimate of the flow capacity. Streltsova showed that for small shut-in times, the buildup response is affected by the last flow rate before shut-in. Ref. 14 also showed that for large shut-in times the Horner semilog slope does not depend upon the rate-history but only upon its average value. Several authors indicated that the rate variation effect on the shape of semilog plots can be erroneously interpreted as reservoir heterogeneity. Soliman proposed a continuous multi-rate method for DST applications, which approximates the flow rates by a polynomial expression.

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