RESERVOIR EVALUATION OF A GAS CONDENSATERESERVOIR USING PRESSURE TRANSIENT ANALYSIS

A.M.ALY W.D.MCCAIN N.C.HILL W.J.LEE

this article begins on the next page FF THE PETROLEUM SOCIETY PAPER 97-54 Reservoir Evaluation of a Gas Condensate Reservoir Using Pressure Transient Analysis A.M. Aly, W.D. McCain, Jr., N.C. Hill S.A. Holditch &Associates, Inc W.J. Lee Texas A&M University This paper is to be presented at the 48th Annual Technical Meeting of The Petroleum Society in Calgary, Alberta, Canada, June 8 - 11, 1997. Discussion of this paper is invited and may be presented at the meeting if filed in writing with the technical program chairman priorto the conclusion of the meeting. This paper and any discussion filed will be considered for publication in CIM journals. Publication rights are reserved. This is a pre-print and is subject to correction. ABSTRACT transmissibility (high liquid saturation) was on the order of This paper presents a case history of characterization of a only 20 feet in radius. gas condensate reservoir usingpressure transient analysis. Our study included sensitivity analysis to determine the pressure transient tests from wells in this field led to test data effect of selected variables on pressure transient test plots with complex shapes. Specifically, the pressure response. Production time prior to shut-in proved to be derivative in a typical test flattened at intermediate shut-in particularly important. Longer production periods prior totimes (after wellbore storage effects diminished) and then shut-in can modify the shape of the derivative curve plot but trended downward. This curve shape indicates lower mobility near the wellbore and increased mobility some do not change the possible erroneous interpretations resulting _from essentially perfect fits of test data with distance away. Usingconventional interpretation techniques, this pressure derivative response may be interpreted composite reservoir models. (erroneously) as a composite reservoir with low INTRODUCTION transmissibility in a region with radius of almost 500 feet near the well, surrounded by a region of higher Analysis of well tests from gas condensate reservoirs is a transmissibility, and a positive skin factor.significant challenge for engineers. If pressure drops below the dew point near the wellbore during the test a condensate In this study, we modelled well tests in this field with a fully ring will accumulate immediately around the well. This can compositional reservoir simulator. We demonstrated that we cause a significant loss in well productivity. The formation can reproduce the observedtest behaviour in a homogenous of this ring is documented by McCain and Alexander'. In reservoir. The decrease in pressure derivative is caused by this paper, we report an investigation of the effect of the reservoir fluid property changes with pressure, and the condensate ring on pressure transient analysis and document apparent positive skin factor is a result of liquid condensing the distinctive behaviour of the pressure derivative caused byin the formation near the wellbore. The region with reduced the ring.

THE PETROLEUM SOCIETY PAPER 97-54

Reservoir Evaluation of a Gas CondensateReservoir Using Pressure Transient Analysis

A.M. Aly, w.o. McCain, Jr., N.C. HillS.A. Holditch & Associates, Inc

W.J. LeeTexas A&M University

This paper is to be presented at the 48th Annual Technical Meeting of The Petroleum Society in Calgary. Alberta, Canada, June 8 - 11,1997. Discussion of this paper is invited and may be presented at the meeting if filed in writing with the technical program chairman priorto the conclusion of the meeting. This paper and any discussion filed will be considered for pUblication in CIM journals. Publication rightsare reserved. This is a pre-print and is subject to correction.

ABSTRACTThis paper presents a case history of characterization of a

gas condensate reservoir using pressure transient analysis.Pressure transient tests from wells in this field led to test dataplots with complex shapes. Specifically, the pressurederivative in a typical test flattened at intermediate shut-intimes (after wellbore storage effects diminished) and thentrended downward. This curve shape indicates lowermobility near the wellbore and increased mobility somedistance away. Using conventional interpretation techniques,this pressure derivative response may be interpreted(erroneously) as a composite reservoir with lowtransmissibility in a region with radius of almost 500 feetnear the well, surrounded by a region of highertransmissibility, and a positive skin factor.

In this study, we modeled well tests in this field with a fUllycompositional reservoir simulator. We demonstrated that wecan reproduce the observed test behavior in a homogenousreservoir. The decrease in pressure derivative is caused byreservoir fluid property changes with pressure, and theapparent positive skin factor is a result ofliqUid condensingin theformation near the wellbore. The region with reduced

transmissibility (high liquid saturation) was on the order ofonly 20feet in radius.

Our study included sensitivity analysis to determine theeffect of selected variables on pressure transient testresponse. Production time prior to shut-in proved to beparticularly important. Longer production periods prior toshut-in can modify the shape ofthe derivative curve plot butdo not change the possible erroneous interpretationsresulting from essentially perfect fits of test data withcomposite reservoir models.

INTRODUCTIONAnalysis of well tests from gas condensate reservoirs is a

significant challenge for engineers. If pressure drops belowthe dew point near the wellbore during the test, a condensatering will accumulate immediately around the well. This cancause a significant loss in well productivity. The formationof this ring is documented by McCain and Alexanderl . Inthis paper, we report an investigation of the effect of thecondensate ring on pressure transient analysis and documentthe distinctive behavior of the pressure derivative caused bythe ring.

A drill stem test (DST) can include a series of productionand shut-in periods, and thus can produce particularly"interesting" pressure derivative curves in gas condensatereservoirs. The test that we analyzed and discuss in thispaper was from a multi-flow period, multi-shutin periodDST.

Although many papers discuss fluid flow in gascondensate reservoirs, we found none that propose adequatemethodology to determine formation properties from analysisof well test data from gas condensate reservoirs. Bourbiaux.2investigated depletion behavior in gas condensate wells usinga parametric modeling study. Carlson and Mye~ studied theeffect ofcondensate drop out on the performance offracturedwells and presented some information on well test analysis offractured gas condensate reservoirs. Afidick, et aZ.4 presenteda case study of a gas condensate reservoir. Jones, et aZ. spresented a two-phase analog that can be used for build upanalysis from wells producing below the dew point pressure.Raghavan, et aZ.6 analyzed several buildup tests to evaluatetechniques presented in the literature. Recently, Yadavalliand Jones7 presented single phase methods that can be usedto interpret hydraulically fractured gas condensate reservoirs.

In this paper we present a detailed analysis and study of atest from a reservoir in South America. We found that use ofa fully compositional simulator (history matching) wasrequired to analyze this test properly. We initially attemptedto use conventional well testing software and techniques(composite reservoir model); these techniques proved to beinadequate at best and misleading at worst.

PRELIMINARY WELL TEST ANALYSISTo perform preliminary pressure transient analysis using

commercial welltest analysis software, we treated thereservoir fluid as a single-phase gas with gravity equal to thatof the recombined sample. The DST we discuss in this paperhad five flow and shutin periods. In the discussion thatfollows, we focus on the second shut-in period because it wasthe longest and thus had the most "complete" response. Wenote, however, that the test data plots had the same generalshape in all shutin periods.

Fig. 1 shows the pressure data obtained during thesecond shutin period in the DST. Fig. 2 shows the pressureand pressure derivative plots. The pressure derivative flattensat intermediate times (after wellbore storage effects havediminished); then, it moves downward. Using commercialwelltest analysis software, we obtained a good match of thedata using a composite reservoir model with a ''mobilityratio" of 0.1. This indicated lower transmissibility (kbJu) ormobility (kIu) in a cylindrical ring with radius of 471 ftcentered at the well and increased mobility starting at a radiusof471 ft from the well. Fig. 3 is a semi-log plot of test data.

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It complements the pressure derivative analysis; the resultsare presented in Table 1. The match we obtained with acomposite model also indicated an apparent positive skinfactor (s = + 6). One feature of the actual test did not appearin the composite model match. At the longest times in thetest, the derivative began to flatten again.

Similar shapes of pressure derivative plots were observedin analyses of other well test data from the same and similarfields in the region. It is implausible that wells in these fieldswould always be drilled in lower permeability rocksurrounded by higher permeability rock. Therefore, wedecided to investigate a more reasonable interpretation. Weconcluded that it was essential to model the gas condensatefluid behavior using a compositional reservoir simulator.

COMPOSITIONAL RESERVOIR SIMULATIONWe used a fully compositional reservoir simulator (with

the Peng-Robinson equation of state for eight pseudo-components) to model the pressure behavior from this well.Fig. 4 shows the relative permeability curves we used in thissimulation (from a similar field in the area). Table 2summarizes reservoir properties for our base case.

In the simulation, we included all five flow and buildupperiods in the DST, but we concentrated on the second (andlongest) shutin period in an attempt to understand thebehavior ofthe pressure derivative.

We used a homogenous radial reservoir with isotropicpermeability of 3 md and no wellbore damage to model thepressure behavior. Initial reservoir pressure was 5300 psiaand saturation pressure was 5285 psia. Fig. 5 shows thepressure derivative match. This match shows flattening atintermediate times (after wellbore storage effects havediminished) followed by a downward slope. In thesimulation, these effects were caused totally by the PVTbehavior of the reservoir fluid - no zones of differentpermeabilities were included in the model. The PVTbehavior of particular importance proved to be liquidcondensation near the well during production andrevaporization during shut-in, coupled with small liquidsaturations at distances remote from the well.

To understand the effect of the fluid behavior on thereservoir pressure behavior, we studied cell pressures andcondensate saturations around the well. Specifically, westudied pressure and oil saturation data at the wellbore and atradii of 0.5, 2., 6.5, 20, 60.5, 182 and 500 ft into thereservoir. Fig 6 shows these reservoir model cell pressures.Fig. 6 shows that the DST production and shut-in sequencereduced pressures significantly below the dew point only to aradius of about 20 ft. The first flow period lasted about 14hours; the first shut in period lasted about seven hours; the

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