Two-Phase Gas/Liquid Flow Rate Estimation During Closed-Chamber Testing
Authors: Kabir C.S. , Badry R.A. , Hasan A.R. 
Published: March 2010

Flow rate estimation constitutes one of the most important tasks in a closed-chamber test (CCT). During a CCT flow period, the reservoir fluids are allowed to accumulate in the drill-string, and are not produced to the surface. This operational aspect differentiates the CCT from a conventional drill stem test (DST), where the flow rate is measured at the surface unless the well kills itself.

A flew methodology has been developed to compute the flow rate of each phase during two-phase gas/liquid flow, frequently encountered in a DST. By measuring pressure at both the wellhead and above the downhole flow-control valve, the changing liquid height is calculated by considering two-phase flow, including the effects of gas and liquid compression, friction and mass transfer. The knowledge of rising liquid height during the flow period allows calculation of liquid flow rate, while the gas flow rate is computed from the material-balance considerations.

Several field examples are used to verify the new method. Indeed, good agreement is obtained between the measured liquid recovery in the drill pipe and that predicted by the new method. We further show that the computed rates enhance pressure transient analysis. Appropriate equations are also presented for both single-phase gas and liquid flow.

Introduction

Interpretation of DST or initial flow period data has been attempted by the hydrologists and petroleum engineers alike over the past 35 years. In these tests, the flow typically occurs against an open wellhead valve, allowing maximum possible flow rate. This is the so-called ‘slug-rest’ where fluid withdrawal from formation into the wellbore occurs at a high initial rate, followed by the continuous rate decline with consequent pressure increase. The flow ceases when the downhole valve is shut in or when the hydrostatic heads of the well bore fluids balance the formation pressure. In other words, reservoir fluids are not produced at the surface in a slug test.

In contrast, a near-constant downhole flow rate may be possible in a conventional DST because critical flow is attainable across the downhole choke. The resulting flow rate may be sustained by producing the reservoir fluids to the surface.

On the other hand, in a closed-chamber test, the fluids are also not produced at the surface, by design, by keeping the wellhead valve closed. The rate decline in this case is more rapid than a slug test because of smaller pressure differential between the reservoir and the sandface. As gas above the liquid column gets progressively compressed, the late time pressure behavior differs markedly from a slug test. The name closed-chamber test or CCT is used in a generic sense and that test data may be gathered from many hardware configurations, such as, DST(1), temporary perforation completion(2,3) and backsurge perforation cleaning(4).

This, pressure and flow behavior are quite different in these three principal tests conducted to evaluate a zone's initial productive potential. The main objective of this work is to present a method to compute the flow rate of a two-phase gas/liquid mixture during the flow period.