Complexities of the Analysis of Surface Shut-In Drillstem Tests in an Offshore Volatile Oil Reservoir
Authors: Kazemi Hossein , Haws Gerald W. , Kunzman William J. , Milton Harry W. , Halbert William G. 
Published: December 2007

A surface shut-in drillstem test (DST) procedure as used in an offshore volatile oil reservoir. Bottomhole shut-in devices were not used because of operational difficulties and anticipated hazardous problems. The type curve and Horner plots of the bottom hole pressures (BHP's) did not conform to classical theory. This paper explains the reasons and suggests a simulation procedure for the interpretation of data.

Introduction

The type curve plots have a very sharp flattening bend at about 15 minutes of shut-in time, which is not typical. The tubing shut-in pressures also decline while the (BHP's) increase, this is not typical either. As a consequence of these observations, we could not accept the conventional interpretations of the buildup curves. This paper describes a new theory that explains the discrepancies.

The new theory relates this unusual behavior to the combined effects of these wellbore phenomena during pressure buildup testing:wellbore storage caused by rising fluid,inertial effects caused by a rising fluid column,gas/oil phase segregation in the test string.cooling of fluid in the uppermost part of the test string by seawater, andgas going back into the oil phase in the fluid column during buildup.

Background

The DST procedure consisted of isolating a perforated interval by a set of packers, producing the well through a tubing (drillpipe) filled with diesel oil from several minutes to 24 hours, and finally closing the well on the surface to obtain pressure buildup data.

Bottom hole shut-in devices were not used because of operational difficulties and anticipated hazardous problems during inclement weather in this hostile offshore environment.

BHP's were recorded for all wells; tubing pressures and temperatures were recorded for some wells. Fig. 1 is the Homer plot of BHP and tubing pressures for a typical high-flowrate DST. Table 1 contains data needed to analyze Fig. 1. Tubing pressure and temperature are shown in Fig. 2. Fig. 3 is the type-curve plot of BHP differences vs. shut-in time.

The following questions have arisen.Where is the correct straight-line portion of the Homer plot?Does deviation of the Homer plot from the early straight-line segment indicate reservoir boundary effects?Why does tubing pressure decline with shut-in time?Why does the type-curve plot have an unusual sharp bend from the early unit-slope straight-line segment?

This paper provides qualitative answers to these questions based on theoretical considerations that relate to a set of complex wellbore storage phenomena. These phenomena include rising fluid wellbore storage and inertia effects at early shut-in times, gas/oil phase redistribution, wellbore fluid cooling by sea water in the top portion of the tubing, and gas dissolving back into the oil phase.

Some aspects of complex wellbore storage problems and other wellbore phenomena are reported in the literature. Earlougher summarized results of the work on falling and rising wellbore storage, compressive wellbore storage, and phase redistribution wellbore effects-all before 1975. Fair's recent paper provides a promising new method of quantifying phase redistribution effect. Phase change of steam (flashing) caused by wellbore cooling for geothermal wells and its effect on well transient behavior was reported by Gringarten and Miller.

JPT

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