SPE-63078-MS

Copyright 2000, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 2000 SPE Annual Technical Conference andExhibition held in Dallas, Texas, 1–4 October 2000.

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Abstract

This paper presents three pressure transient analysis casehistories using a wireline cased-hole formation tester (FT) aspart of an appraisal program in the Peng Lai 19-3 field,offshore China. A typical cased-hole formation test operationinvolves perforating a 1-foot interval via wireline, setting thetesting tool across the perforations with straddle packers, andpumping formation fluids through the tool to catchrepresentative samples. Although the main goal of the cased-hole wireline formation test program was to obtain fluidsamples, short pressure buildups lasting approximately 2 hoursor less were also conducted. We found the character of thepressure data and the resulting transient analyses to becomparable to those from cased-hole drillstem tests (DST’s).

Wireline formation testers have traditionally been used inopen-hole to gather formation pressures and collect fluidsamples. On a limited scale, the pressure data have providedinformation about reservoir properties from pressure transientanalysis. However, it is difficult to run these tools in sometypes of formations (unconsolidated sand, unstable shales)because of collapsing formations, differential sticking, andsand production. The Peng Lai 19-3 Field consists of a seriesof stacked, unconsolidated sandstone reservoirs having widevariations in oil PVT properties with depth. Using the cased-hole FT tool offers a significant cost saving by reducing thenumber of drillstem tests required to characterize thesestacked reservoirs. This paper will (1) describe the tool setupand procedures used to collect the fluid and pressure data and

(2) present the pressure transient analysis of the data usingtraditional methods (log-log and semi-log techniques).

Introduction

Frimann-Dahl1 compared the open-hole FT to the DST byapplying conventional transient analysis methods to the FTpressure data. However, he did not observe spherical flow inthe transient data and found high geometric skins thatsometimes concealed flow regimes. The high skins alsolimited the accuracy of the analysis due to gauge resolutionproblems. Pop et al.2 also applied conventional transientanalysis techniques to FT data. The analysis of spherical flowin the FT was introduced by Stewart and Whitman3. Alongwith others4-5, they found difficulties in permeabilitydetermination due to limited gauge resolution and high skinfactors. Many authors 6-12 have discussed the use of multipleFT probes to measure vertical permeability.

The cased-hole FT was used throughout the appraisal phase ina recently discovered field in Bohai Bay, People’s Republic ofChina. Twenty-five tests in seven wellbores were run at PengLai (PL) 19-3 field using this tool. After drilling the discoverywell at PL 19-3, fluid properties, formation permeabilities, andreservoir pressures were found to vary extensively.

The Lower Minghuazhen and Guantao formations consist ofmany poorly consolidated to unconsolidated sandstone layersover an interval up to 2000 feet thick. The formations areshallow, with the top of the Lower Minghuazhen between2500 and 3000 feet. The reservoirs are normally pressured,with gradients of approximately 0.434 psi/ft from surface.Pressures obtained during open-hole FT operations revealedmultiple pressure systems vertically within each wellbore aswell as areally across the field. In one well, as many as eightseparate pressure cells were identified from open-hole FTpressure analysis. Temperatures are relatively low from anoperational standpoint, ranging from 120° F to 150° F. NoH2S was found in any of the reservoirs, and CO2 has only beenfound in two wells in the middle of the field.

SPE 63078

Using the Cased-hole Formation Tester Tool for Pressure Transient AnalysisS.M. Hurst, SPE, Phillips Petroleum Company; T.F. McCoy*, SPE, Phillips Petroleum Company; M.P. Hows,Schlumberger

* currently with Vintage Petroleum Inc.

2 S.M. HURST, T.F. MCCOY, M.P. HOWS SPE 63078

Reservoir fluid samples obtained from several drillstem testsand extensive cased-hole formation testing show that fluidproperties also vary significantly. The oil is very heavy,ranging from 11° to 21° API, with gas-oil ratios (GOR’s)ranging from 50 to 300 scf/stb. In most cases, oil-bearingzones can be identified from resistivity logs. However,several intervals that were identified as water bearing based onlow resistivities were later found to flow 100% oil.

Reservoir properties – primarily formation permeability – varyas much as fluid properties and cannot be reliably inferredfrom standard open-hole logs. Permeabilities derived fromDST pressure transient analyses range from 100 md to severalDarcies, with mobilities ranging from 1 md/cp to 150 md/cp.

To properly characterize the field and plan for development,an extensive appraisal program was required. This programobtained numerous high-quality fluid samples, formationpermeabilities, and reservoir pressures in enough zones to planfor future development. The costs of gathering this datawould have been excessive using only conventional drillstemtests. Open-hole formation testers were unable to collect high-quality fluid samples or reliable mobility data. Thus, thecased-hole FT was added to supplement the data-gatheringprogram.

This paper describes the cased-hole FT tool and proceduresused during the appraisal program at PL 19-3 field andpresents pressure buildup results obtained during the cased-hole FT tests. Two other evaluation tools used at PL 19-3field during the appraisal phase – specifically drillstem testsand open-hole formation testers – are compared to the cased-hole FT.

Tool Description

The cased-hole FT tool run at Bohai Bay was identical to theopen-hole FT tool, though configured with packers instead ofa probe (Figure 1). The tool consists of the followingcomponents, from top to bottom: gamma ray and collarlocator, a multisampler module with monophasic chambers,large-volume sample chambers, the pump out module, thefluid analyzer module, the packer module, and a bleed port.For water zones, the probe module was added to the tool stringto be able to use the resistivity cell.

The multi-sample module was used to collect monophasicsamples. Six sample chambers, each capable of capturing a250-cm3 sample suitable for full PVT analysis, were mountedin a single carrier. Fluid was directed into the specifiedsample bottles by surface commands. This made it possible totake multiple samples during one tool set, at various timesduring fluid flow, or to fill single sample bottles at variouswell depths.

Large-volume sample chambers were run in variouscombinations using the available volumes of 1, 2.75, and 6gallons. Due to length and weight limitations, four chambersper trip were the most that could be practically run onwireline. Fluid was directed to the selected chamber byelectromechanically actuated throttle (seal) valves, controlledfrom the surface. To prevent excessive pressure drops, thevalve could be throttled to maintain a specified flowlinesampling pressure.

The pump-out module’s primary purpose was pumping thesampled fluid from the formation into the wellbore. The fluidtype was monitored from surface while pumping. When fluidquality was representative of the reservoir, the pump outputwas directed to a sample chamber and a formation fluidsample captured. The pump-out module was also used toinflate and deflate the straddle packer and to pump betweenthe packers.

The fluid analyzer module was used to differentiate betweengas, oil, and water and the percentage of each phase. Thismodule uses optical analysis techniques to identify the fluidtype in the flowline. Optical absorption spectrometry in thenear infrared range differentiates oil and water. Reflectionmeasurements detect gas by using the difference in liquid andgas refractive indices.

The dual-packer module employed two inflatable packers toisolate the borehole interval for testing. Spacing betweenpackers was variable but the typical distance was about 3 feet(93 cm). This provided greater flow area than was possibleusing the open-hole FT probe. Thus, fluids could bewithdrawn at higher flow rates, without dropping below thebubblepoint pressure. Extension mandrels were also usedwhen appropriate, increasing the spacing by an additional 2feet and allowing a 3-foot perforation interval instead of theusual 1-foot. However, this also increased the amount ofpump time due to the increased volume between the packerelements. In this particular formation, the increasedperforation interval did not significantly reduce the drawdownand was not worth the added pump times.

A bleed port was placed at the bottom of the tool string toequalize pressures across the pump-out module. This wasnecessary to avoid damaging the pump-out when reversing thepumping direction.

Standard Test Procedure

We developed a standardized procedure at Bohai Bay toobtain high-quality fluid samples and pressure data suitablefor transient analysis. The following section describes thisprocedure.

A 1- to 3-foot interval within a larger zone was selected forperforating. The larger zone had to be isolated by cementfrom adjacent sands to prevent crossflow. The highest

SPE 63078 USING THE CASED-HOLE FORMATION TESTER TOOL FOR PRESSURE TRANSIENT ANALYSIS 3

permeability interval within this larger zone was normallyselected for perforating. However, this selection was balancedwith the need to minimize formation cleanup. Better cleanupcould be achieved by placing the perforations in a thinner zoneor near a bed boundary.

Most of the tests were run in mud. Because formationpressures were so low (approximately 0.434 psi/ft fromsurface), the mud systems were primarily viscosifiedpotassium chloride with some barite added for weightingmaterial. All lost circulation materials were circulated outbefore the job, ensuring no debris to plug the flowlines,pressure gauges, and valves. Mud weight was cut back tominimum required for the intervals to be tested, as experiencehad shown that higher mud weights could damage orcompletely plug the perforations. In addition to cleaning themud system, a casing scraper run was made to ensure thecasing was free of all cement. The casing scraper removedanother potential source of debris from the wellbore, as well asensuring a clean surface to seat the packer. Properlyconditioning the mud and casing were critical for a successfuljob.

Intervals were perforated in a single or multiple runs, usuallywith 4-1/2” casing guns at 12 shots per foot. The cased-holeFT tool was then run on wireline to the perforated intervaldepth. Both gamma ray and a collar locator tool were used forimproved accuracy of depth correlation. Multiple intervalscould be tested in a single run, limited only by the numbers ofsamplers and operational limits on the tester tool components,primarily the pump-out module and seals.

All perforation and FT operations were run under a wirelineblowout preventer (BOP) which was tested to 1000 psi beforeperforating. FT operations require pumping hydrocarbons intothe wellbore above the packers. Large amounts of gas or lightoil could reduce the hydrostatic pressure in the wellbore andpossibly result in well control problems. Although the riskwas considered minimal in this particular environment due tothe high-gravity, low-GOR oil, we considered these preventivemeasures to be good practice.

Once at depth, the pressure gauges were allowed to stabilize inorder to acquire a good hydrostatic pressure before setting thepacker. This did two things: it verified that both quartz andstrain pressure gauges were reading correctly; and it ensured apressure which could be used as reference once the packer wasdeflated.

After seating the packers against the casing, the formation waspumped out at the lowest pump speed until communicationwith the formation was confirmed and the flowing pressuredropped below estimated formation pressure. At that point thepump was stopped and the interval seal valve closed untilpressures stabilized. This initial buildup provided formationpressure, as well as confirming a good packer-to-casing seal.The pressure derivative on a log-log plot, rather than direct

pressure measurement, was used to identify packer leaks andconfirm communication with the formation. A very slow leakcould not be seen by monitoring pressures only, and largerleaks were often difficult to detect until pressures continued toclimb at the end of the buildup. If a leak was detected, thepackers were inflated to a higher pressure and the buildup testre-run. Occasionally it was necessary to deflate the packersand re-set them at a higher pressure to get a positive seal.

Sampling flow was started once initial pressure was obtainedand a good packer-to-casing seal verified. The formation waspumped out at lowest pump speed until a stable flowingpressure was established. If the pressure drawdown wassmall, pump speed was gradually increased in increments of100 RPM. High pressure drawdowns could cause significantformation damage and potentially ruin the test.

Pumping continued until fluid samples were as clean aspossible. At that point, a combination of monophasic andlarge-volume fluid samples were collected. As this was awater-based mud system, contamination was only a minorissue since water and hydrocarbon could be separated in thelabs. The primary concern was to collect sufficienthydrocarbon volume in the sampler for PVT analysis. Oil andwater fractions were determined from the fluid analyzer,which was found to be very accurate in its prediction of oilversus water fractions. Oil breakthrough typically occurredafter pumping 30 liters, or in approximately 2 to 3 hours at300-rpm pump speed. This corresponded to the volumebetween the packers. Cleanup would then continue foranother 6 to 10 hours, or until oil fractions were high enoughto fill the samplers. A 75 to 80% oil fraction would yieldenough oil volume in the monophasic samplers for PVTanalyses. Pump times depended upon permeabilities and fluidproperties, as well as thickness of the zone sampled andcement isolation. Very viscous oil or low-permeability zonescould require up to four times more pump volumes.

Once all samples were collected, pumping continued to ensurea stable flow period before the pressure buildup test. Thepump was then stopped and the interval seal valve closed toconduct a pressure buildup test. The seal valve was closed tominimize leakage past the pump, as the pump itself did notalways provide a positive pressure seal. To prevent early timedata from being distorted, the pump was stopped first and theseal valve closed almost simultaneously. Changing thesequence or delaying the seal valve resulted in poor data andmade interpretation difficult. A minimum shut-in period of 2hours gave the best results in these particular formations.

Average FT pump time lasted approximately 12 hours per test.An additional 6 hours were required to correlate on depth, setand deflate the packer, acquire initial pressure, and conductthe final buildup test. Perforating took 2 to 3 hours perinterval, and rig up / rig down of the MDT tool ranged from 2to 4 hours. Thus, for these relatively shallow formations withmoderate mobilities and heavy oil, test time for a single


interval ranged from 18 to 24 hours. Several intervals couldbe tested during a single run, which eliminated some of the rigup / rig down time. Up to 3 intervals at a time were testedduring a single run without coming out of the hole to servicethe tool. Experience showed that this was the upper limit ofthe tool’s capabilities.

Comparison of Test Methods

As appraisal drilling progressed at PL 19-3 field, we quicklyrecognized that the test program would be more extensive thanoriginally expected due to the complexity of the field. Thecased-hole formation tester was first used on the secondappraisal well to determine fluid type in a low resistivity zone.Its use gradually expanded from providing information aboutfluid types to collecting PVT-quality fluid samples and finallyto obtaining information about reservoir flow properties.Problems with both the open-hole formation tester anddrillstem tests led to greater reliance upon the cased-hole FT.

Open-hole versus Cased-hole FT. The open-hole FT wasused extensively at PL19-3 field to gather formation pressures.However, its utility for collecting fluid samples and formationmobilities was limited.

The open-hole FT when equipped with a probe module wasunsuited for collecting fluid samples in these formations.High pressure drawdowns often accompanied open-holesampling operations. This was attributed to damage fromformation collapse, fines migration, and invasion around thewellbore. Heavy, viscous oils reduced mobilities and added tothe problem of high pressure drawdowns. Sampling pressuresbelow the bubblepoint compromised the quality of formationfluid samples. The high drawdowns also resulted in sandproduction, causing the FT probe, screens, and flowlines toplug and requiring numerous trips out of the well to clean thetool. High viscosity oil could also plug screens and preventflow into the tool.

Open-hole FT mobilities in these formations were unreliable.This was attributed to formation damage, altered saturations,and limited radii of investigation. If the formation is highlyinvaded or damaged, the relatively shallow radius ofinvestigation of the open-hole FT will not extend into virginreservoir. Mud filtrate invades the region investigated by theFT test, changing fluid saturations and altering effectivepermeability. Fines and other mud contaminants can plug thepore space and cause near-wellbore damage. Collapsingformations induced by high pressure drawdowns can affectpermeability results unless the radius of investigation extendsfar enough beyond the region to see that section as skindamage.

The open-hole FT could be configured with dual packers,similar to the cased-hole tool, which would expose a largerinterval and result in lower pressure drawdowns. However,this increased the operational risks in open-hole. FT

operations require taking many data points, with the toolremaining stationary at each point for long periods. Sloughingshales and unconsolidated sands made the wellbore veryunstable. Pressure differentials between the mud weight andpore pressure could cause the tool or wireline cable to stick.Any one of these factors could result in losing the tool itselfor, at the minimum, lead to a costly recovery operation.

Tests using the cased-hole FT did not experience the highpressure drawdowns seen in open-hole operations using aprobe module. This was primarily due to the greater flow areain perforated casing and the use of the dual packer module.By keeping flowing pressures below bubblepoint pressure,fluid samples were representative of that in the reservoir. Thereduced drawdowns also prevented sand production.

The greater flow area, reduced drawdowns, and extendedpump times from the cased-hole FT gave better estimates offormation mobility. A relatively high and stable flowingpressure allowed longer flow periods with the cased-hole FT,increasing the radius of investigation.

Finally, the operational risk was minimal. Unlike the open-hole environment, casing eliminated the problems withunstable formations or differential sticking.

Drillstem Tests versus Cased-hole Formation Tests.Drillstem tests can evaluate large volumes of the reservoir thatare beyond the range of open-hole logs and whole cores.Many DST’s were run in the PL 19-3 field to acquireformation pressure, mobility, and fluid samples. These testshad varying degrees of success depending uponpermeabilities, oil properties, and sand stability. In addition,DST’s were limited by time and cost to only a few of the mostimportant zones.

High viscosities and low GOR’s made it difficult to flow theoil naturally to surface. The column of heavy oil was nearlyequal to formation pressure, causing it to load up as the fluidlevel reached surface. GOR was too low to provide anybenefits as gas broke out of solution near the surface.Conversely, GOR was too high for pump tests that weretypically conducted at Bohai Bay in these formations. Withlower mobility formations, high pressure drawdowns wererequired to lift oil to surface. This made sand production aconstant concern due to the highly unconsolidated formations.

High pour points and viscosities caused numerous problems atsurface, particularly during the winter months when surfacetemperatures remained near freezing. In addition to hinderingsurface handling operations, it also affected the flowrates as itapplied additional backpressure that could be ill afforded.Heat tracing the lines was expensive and time-consuming anddid nothing to increase temperatures between the sea floor andwellhead.


The problem of adequate deck space, always a considerationduring any drillstem test, was compounded by the inability toburn the heavy oil. As the weather in Bohai Bay wasunpredictable and sometimes too hostile to allow offloadingtanks for days at a time, sufficient tankage was required ondeck to hold enough produced fluid for the length of thecleanup and flow period.

Even the simplest DST required large amounts of equipmentand personnel. A typical DST in this field would run five toseven days long. Many of the problems outlined above couldbe addressed, but the costs of these solutions started tooutweigh the benefits of the DST.

The cased-hole FT solved many of the problems with a DST.There was no need to flow fluids to surface, eliminating all ofthe problems associated with producing heavy oil. Since thetool was positioned directly across from the perforations, fluidsamples could be collected at near reservoir conditions.Pressure drawdowns were kept to a minimum, preventingpressures from dropping below bubblepoint and avoiding sandproduction.

Operationally, the cased-hole FT is less complex than a DST.There are less than a dozen modules in a cased-hole FT toolstring, compared to the multiple components in a DST string.Surface requirements are minimal for a cased-hole FT test,consisting of the wireline unit and well control equipment, incontrast to the surface equipment needed for a DST.

The stacked zones in the PL19-3 field required multiple testsfor proper evaluation. A cased-hole FT test can be conductedin 1 day. This means that more zones can be tested for thecost of a single DST.

Cased-hole FT Benefits and Drawbacks. Cased-hole FTtesting offers the following benefits: (1) high qualitymonophasic samples representative of reservoir fluids; (2)sufficient volumes of surface samples to evaluate on site andto perform limited assay analysis; (3) determination ofproductivity and formation permeability or mobility from flowperformance and pressure buildup tests; (4) increased flowarea compared to open-hole FT probe, to reduce drawdownand prevent sand production or collapse; (5) very little risk oflosing the tool compared to an open-hole environment; (6)ability to test multiple formations in a short period of time; (7)greatly reduced time and costs compared to a conventionalDST; (8) ability to evaluate fluid types and fractions downholeto monitor for clean up; (9) direct measurement of pressures atperforation depth rather than extrapolating with an estimatedfluid gradient; (10) limited surface equipment requirementscompared to a DST; (11) ability to change intervals andtesting methods in relatively short time periods; (12) simplerand less complex system than for a DST.

At the same time, cased-hole FT testing is limited by: (1)uncertainty of pay thickness contributing to total flow; (2)

need for excellent cement isolation; (3) perforation intervallimits of 1 to 3 feet; (4) operational constraints affected byreliable servicing and maintenance of the tool; (5) limitedreservoir volume investigated for PTA; (6) need to run casing.

While the cased-hole FT is not expected to supplant the needfor conventional testing methods – in particular drillstem testsand open-hole formation testers – it nevertheless can be avaluable addition to the evaluation of a field. The ability toget pressure buildup data was an unexpected benefit fromwhat originally started as an attempt to get fluid samples.

Field Cases

The following examples illustrate the type of pressure datacollected with the cased-hole FT from oil reservoirs at PL 19-3. A summary of the tests and analysis results is presented inTable 1. As more experience was gained with this testmethod, we continued to modify the procedure to acquirebetter data and expand the scope of the tool. These examplesare representative of the twenty-five pressure buildup testsconducted in this area.

Case 1The first example was in an 11-foot zone containing 15.4° APIoil. Open-hole logs over the tested zone are presented inFigure 2. Open-hole and mud logs indicated thatpermeabilities might be too low to allow for a successful DST.The FT was run to determine if a DST should be conducted.

A 1-foot interval was perforated in a 2-foot bounded layerwithin the larger zone. The FT packers were inflated acrossthe perforated interval, and initial pressure was obtained bypumping out the formation for a short period and then shuttingin until pressures stabilized. The formation was then pumpedat the minimum speed of 300 RPM until the oil fractionstabilized at 40%, for a total pump time of 8 hours. Pumpspeed was not increased throughout the 8-hour pump time dueto the high pressure drawdowns caused by the low formationmobility. After pumping for 8 hours with little change in theoil fraction, two monophasic and 2.75 gallons dead oilsamples were collected. Final pressure drawdown wasapproximately 380 psi, which was at or above the assumedbubblepoint pressure. The pump was then stopped and theseal valve closed for a pressure buildup test lasting 2 hours.

The pressure buildup data from the final buildup was analyzedusing log-log derivative and semi-log techniques. Rates werecalculated from pump displacement, and any inefficiency inthe pump that might affect calculated rates was considerednegligible. Analysis showed a low mobility of 4.3 md/cp,assuming only the single 2-foot layer was contributing. Thederivative plot showed that there were no partial penetrationeffects, and a skin value of +2 confirmed this observation.Thus, a finite-radius, infinite-acting model was used tosimulate the pressures during the test.


This infinite-acting model matched observed pressures duringthe last hour of the flow period and during the final buildup.However, simulated pressures were lower than pressuresduring the initial buildup and could not match the decliningpressures observed throughout the sampling flow. In addition,initial pressure from the model was nearly 20 psi less than thatobtained from the initial buildup. The cased-hole FT initialpressure of 2144 psia did agree with formation pressure fromthe open-hole FT. The final buildup test was either giving afalsely low formation pressure, possibly due to changes in thereservoir away from the wellbore, or the initial pressures fromboth cased and open-hole FT were supercharged.

In order to match both initial formation pressure and thedeclining pressures during the flow period, two parallelboundaries at 30 feet and 100 feet had to be introduced in themodel. This final model gave simulated results that weremuch closer to observed data. The observed pressure data andthe model results are presented in Figures 3 through 5.

The primary objectives of the FT test were to obtain fluidsamples and to determine if a DST should be conducted. TheFT recovered both high-quality monophasic and dead oilsamples. Since pressure transient analysis of the FT builduptest confirmed that the formation did indeed have lowmobility, the DST was cancelled.

Case 2The second example is from a thicker and more permeable payzone with no nearby bed boundaries to limit inflow to the 1-foot perforated interval. The FT test was conducted in aninterval that would also be drillstem tested. The DST intervalcovered two separate zones. The top zone was ahomogeneous, unconsolidated sand approximately 30 feetthick. The lower zone was approximately 145 feet thick,although only 45 feet of that contributed to flow. The FT testwas conducted in the lower zone, at the top of the pay sandpackage. Figure 6 shows the open-hole logs across the DSTinterval. There was poor cement isolation across both upperand lower zones. Before the test, cement squeezes wereperformed between the two sand bodies as well as above andbelow the entire package. The FT was run before the DST inorder to obtain good bottomhole samples. Sampling attemptsin some of the previous drillstem tests had been unsuccessful,due to sand production, inadequate clean up, or high pressuredrawdowns. Oil gravity was 17.6° API, as determined fromlater analysis of the recovered samples.

The same procedure used for Case 1 was again followedduring this FT test. One exception was that pump speed wasincreased during the sampling flow period from 400 to 800RPM due to very low pressure drawdowns. This interval tooka longer time than normal to see oil breakthrough and to getoil fractions high enough for sampling. This was attributed tothe lack of cement isolation. After pumping for 10 hours, the

oil fraction had stabilized at 70%, and three monophasic and3.75 gallons dead oil samples were collected. Pressuredrawdown was approximately 20 psi at the end of thestabilization flow, ensuring that sampling pressure was wellabove the assumed bubblepoint pressure. Once all sampleswere collected and flowing pressures again stabilized, thepump was stopped and the seal valve closed for a pressurebuildup test lasting 2 hours. A conventional DST followed theFT test.

The pressure buildup data from this FT test was analyzedusing log-log derivative and semi-log techniques. Again, rateswere calculated from pump displacement, and any inefficiencyin the pump was considered negligible. Analysis showed arelatively high mobility of 34.4 md/cp, assuming that theentire 45-foot lower sand was contributing. In contrast to theprevious example, spherical flow was clearly seen on a log-logderivative plot during this buildup test, as indicated by anegative half-slope starting at approximately 0.01 hours. Atotal skin value of +15 appeared to confirm this interpretation,although it is recognized that damage could also be a factor.

A limited-entry, infinite-acting model was used to simulate thetest data. Vertical permeability can be determined if thelimited-entry model is correct and if the total zone thicknessand position of the perforated interval within the zone areknown. In this case, the vertical permeability was 2 timesgreater than radial permeability. Two other FT testsconducted in this well had similar results, with verticalpermeabilities greater than horizontal despite core and log dataindicating the opposite. The lack of cement isolation acrossthe zones may be the cause of this questionable analysis. Themechanical skin value was set to zero, causing all of the skinto be attributed to limited entry effects.

Simulated pressures matched observed pressures during mostof the test. The first part of the sampling flow does not matchdue to changing saturations as mud filtrate was pumped fromthe formation and replaced with reservoir fluid. Formationpressure from open-hole FT agreed with the cased-hole FTinitial buildup and with the extrapolated pressure from thefinal buildup test. The observed pressure data and the modelresults are presented in Figures 7 through 9.

Both monophasic and dead oil samples were recovered by theFT, achieving the most important objective of the testprogram. Pressure transient analysis of the FT buildup testgave formation mobility and effective skin. Pressure analysiswas complicated by the poor cement isolation across thisinterval and the uncertainty about net pay contributing to thetotal flow.

Since the DST included the FT interval, a comparison can bemade between the two techniques. The FT permeability of2900 md is consistent with the DST permeability of 2700 md.This comparison is made knowing that there are uncertaintiesabout which intervals are actually contributing.


The ability to get representative fluid samples using the cased-hole formation tester was confirmed after comparing PVTanalyses from samples taken using both the FT and aconventional DST. Studies are currently underway to validatepressure buildup test results from cased-hole formation testersand compare them to other permeability indicators, such asconventional drillstem tests, whole cores, and magneticresonance imaging logs.

Case 3The third example was in a 3-foot interval isolated above andbelow by thin shale beds within a larger 82-foot zone. Figure10 presents the open-hole logs across the test interval. Cementisolation appeared to be good across the entire zone. As thisreservoir was expected to contain 13° API oil with highviscosity and since permeabilities appeared to be low, thedecision was made to run the cased-hole FT rather than aDST.

An 1100-psi drawdown was required to break down theperforations and establish communication with the formation.Once communication was established, flowing pressuresimmediately increased 1000 psi and stabilized for the rest ofthe sampling flow. All of the 7 intervals tested in this wellhad similar problems establishing communication with theformation during initial drawdown. Formation damage due toincompatibilities with the mud and invasion was believed tobe one of the major causes. Contaminants in the mud system,such as lost circulation materials, were believed to be anothercontributing factor.

Initial formation pressure was obtained by pumping out for ashort time period and then shutting in until pressuresstabilized. The formation was then pumped at minimumspeed of 300 RPM until the oil fraction stabilized, or for atotal time of 12.5 hours. When oil fractions stabilized atapproximately 80%, two monophasic and 2.75 gallons deadoil samples were collected. Final pressure drawdown wasapproximately 164 psi, which was at or above the assumedbubblepoint pressure. The pump was then stopped and theseal valve closed for a pressure buildup test lasting 2 hours.

Analysis of the final pressure buildup demonstrated that thezone had a low mobility of 7.9 md/cp, assuming a 3-foot payinterval. The derivative plot showed possible spherical flowoccurring for a short time period, although the skin value of+5.5 could have been caused by formation damage. A limitedentry model was finally used to simulate the test, as this typeof model was required to match the derivative data. All of theskin damage could be attributed to limited entry effects.Vertical permeability was very low – 6 md, compared to aradial permeability of 2400 md – as was expected in this zone.

Simulated and observed pressures agreed throughout the test.There was a slight discrepancy between initial and final

formation pressures as determined from the two buildup tests.This 7-psi difference could be attributed to superchargeeffects. The observed pressure data and the model results arepresented in Figures 11 through 13.

Conclusions

The ability to obtain fluid samples and reservoir mobilityusing a wireline formation tester reduced testing costs andallowed for better characterization of a complex field duringits appraisal phase. In addition to collecting high-quality fluidsamples, this tool provided pressure data that could beanalyzed using classical pressure transient analysis techniques.The resulting reservoir mobilities appeared to be reasonablewhen compared to other permeability indicators, althoughadditional study is required to verify this observation. Thetool was especially useful in this area due to operational andlogistical problems conducting drillstem tests and open-holeformation testers.

Acknowledgements

We thank Phillips Petroleum Company and Schlumberger forpermission to publish this paper. We also thank ChineseNational Offshore Oil Company for their assistance andsupport during this project.

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3. Stewart, G and Whitman, M.: “Interpretation of the PressureResponse of the Repeat Formation Tester,” paper SPE 8362presented at the 1979 SPE Annual Technical Coverence andExhibition, Las Vegas, Sep. 23-26, (1979).

4. Goode, P.A. and Thambynayagam, R.K.M.: “Influence of anInvaded Zone on a Multiple Probe Formation Tester,” paperSPE 23030 presented at the SPE Asia-Pacific Conference, Perth,Nov. 4-7, (1991)

5. Jensen, C.L. and Mayson H.J.: “Evaluation of PermeabilitiesDetermined from Repeat Formation Tester Measurements Madein the Prudhoe Bay Field,” paper SPE 14400 presented at the1985 SPE Annual Technical Coverence and Exhibition, Lasvegas, Sep. 22-25, (1985).

6. Dussan V, E.B. and Sharma, Y.: “An Analysis of the PressureResponse of a Single-Probe Formation Tester,” paper SPE16801 presented at the SPE Annual Technical Coverence andExhibition, Dallas, Sep. 27-30, (1987).

7. Kuchuk, F.J., et. al.: “Multilayer reservoir Testing withMultiprobe Wireline Formation tester,” paper SPE 36176presented at the 7th Abu Dhabi International PetroleumConverence and Exhibition, Abu Dhabi, Oct. 3-6, (1996).


8. Shah, P.C., e.al.: “Interpretation of the transient PressureRecorded by a Multiprobe Wireline Formation tester in aLayered Reservoir,” paper SPE 25663 presented at the MiddleEast Oil technical Conference and Exhibition, Bahrain, April, 3-6, (1993).

9. Goode, P.A., Pop, J.J. and Murphy III, W.W.: “Multiple ProbeFormation testing and Vertical Reservoir Continuity,” paperSPE 22738 presented at the 1991 SPE Annual TechnicalCoverence and Exhibition, Dallas, Oct. 6-9, (1991).

10. Goode, P.A, and Thambynayagam, R.K.M.: “Analytic Modelsfor a Multiple Probe Formation Tester,” paper SPE 20737presented at the SPE Annual Technical Coverence andExhibition, New Orleans, Sep. 23-26, (1990).

11. Head, E.L. and Betties, F.E.: “Reservoir AnisotropyDetermeination With Multiple Probe Pressures,” JPT Dec. 1993,p. 1177-84.

12. Badaam, S.A., et. al.: “Estimation of Formation Properties UsingMultiprobe Formation Tester in Layered Reservoirs,” paper SPE49141 presented at the 1998 SPE Annual Technical Coverenceand Exhibition, New Orleans, La, Sep. 27-30, (1998).


Electrical powermodule

Sample Chambermodule

OFAmodule

Pumpoutmodule

Packermodule

Sample Chambermodule

Bleedport

Multisamplermodule

Fig. 1 – Typical Cased-hole Formation Tester Tool String.

Table 1 – Summary of Cased-hole FT Tests and Analysis Results

Case 1 Case 2 Case 3Oil Gravity 15.4 deg API 16.5 deg API 11.8 deg API

Viscosity 30 cp 85 cp 300 cp

Net Thickness 2 feet 45 feet 45 feet

Final Pressure Drawdown 384 psi 20 psi 164 psi

Type ModelHomogeneous, Parallel Boundaries

Limited Entry, Infinite-Acting

Limited Entry, Infinite-Acting

Initial Formation Pressure 2155 psia 1528 psia 1760 psia

Mobility 4.3 md/cp 38 md/cp 7.9 md/cp

Radial Permeability 130 md 2940 md 2390 md

Vertical Permeability n/a 5770 md 6 md

Effective Skin + 1.6 + 15 + 5.5

Boundaries 30 & 100 feet none noneDepth of Investigation 40 feet 150 feet 80 feet


Fig. 3 – Log-log derivative plot for Case 1. The model includestwo parallel boundaries at 30 and 100 feet. Model pressures areshown as solid line. Observed pressures are displayed as circles,with pressure derivatives as squares.

4880

4885

4890

4895

4900

4905

4910

4915

4920

0 20 40 60 80 100 120 140 160

4880

4885

4890

4895

4900

4905

4910

4915

4920

0 5 10 15 20 25 30 354880

4900

4920

1 10 100

GRx880

Resistivity Porosity

FTPerforation

SP

x920

Fig. 2 – Open-hole logs for Case 1, across FT zone.


Fig. 4 – Semi-log plot for Case 1. The model includes two parallelboundaries at 30 and 100 feet. Extrapolated pressure matchesformation pressure obtained from open-hole FT. Model pressures areshown as solid line, with observed pressures as circles.

Fig. 5 – History plot for Case 1, comparing observed and simulated pressuresversus time. Model includes two parallel boundaries at 30 and 100 feet. Modelpressures are shown as solid line, with observed pressures as circles. Pumprate is displayed as thick solid line at bottom of plot.

Initial buildup

Sampling


Fig. 7 – Log-log derivative plot for Case 2, using a limited-entry, sphericalflow model. The observed pressures are shown as circles, with the pressurederivative displayed as squares. The model is shown as a solid line. Thespherical flow derivative is displayed to show the region of the testundergoing spherical flow.

spherical flow

X250

FTPerforation

GRSP PorosityResistivity

X500

Fig. 6 – Open-hole logs for Case 2, across DST and FT interval.


Fig. 8 – Semi-log plot for Case 2. The limited-entry, spherical flow model isshown as a solid line, with observed pressures displayed as circles.

Fig. 9 – History plot for Case 2, comparing observed versus simulatedpressures versus time. The limited-entry, spherical flow model is shown as asolid line, with observed pressures displayed as circles. Pump rate is shownas a thick solid line on the bottom of the plot.

400 rpm pump rate 600 rpm pump rate 800 rpm pump rate

Initial buildup

Sampling

Oil breakthrough


Fig. 11 – Log-log derivative plot for Case 3. The limited-entry model is shownas a solid line, with observed pressures displayed as circles and derivativeas squares. A spherical flow derivative is plotted to show the region that isunder the influence of spherical flow.

probable spherical flow

X000

FTPerforation

GRSP PorosityResistivity

X060

Fig. 10 – Open-hole logs for Case 3, across FT zone.


Fig. 12 – Semi-log plot for Case 3. The limited-entry, spherical flow model isshown as a solid line, with observed pressures displayed as circles.

Fig. 13 – History plot for Case 3, comparing observed versus simulatedpressures versus time. The limited-entry, spherical flow model is shown as asolid line, with observed pressures displayed as circles. Pump rate is shownas a thick solid line on the bottom of the plot.

oil breakthrough

300 rpm – constant pump rate

sampling

initial buildup

Documents

SPE-63078-MS