formation testing and sampling through casing

Formation Testing and Sampling Through Casing

An innovative testing tool drills through steel casing, cement and rock to measure

reservoir pressures and collect formation-fluid samples. Unlike other cased-hole

devices, this new tool plugs the hole it drills, isolating the formation from the wellbore

after testing. This unique sealing capability allows operators to resume production

without costly casing or cement repairs.

New cased-hole sampling and testing tool. The CHDT tool has four modules, including a power cartridge, a controlmodule, a cased-hole probe module and a sample-unit module. The power module provides power from the wirelinecable. The control module runs the drilling and pressure-testing stages of operations. The probe module anchorsthe tool, seals it to the casing, and drills and plugs the hole. The sampling unit recovers fluid samples. A coin is shownfor scale next to the plugs in the upper right photograph.

51381schD07R1 6/3/02 9:40 AM Page 46

Keith BurgessTroy FieldsEd HarriganSugar Land, Texas, USA

Greg M. GolichAera Energy LLCBakersfield, California, USA

Tom MacDougallRosharon, Texas

Rusty ReevesStephen SmithKevin ThornsberryChevronTexacoNew Orleans, Louisiana, USA

Brian RitchieDevon Canada CorporationCalgary, Alberta, Canada

Roberth RiveroPetróleos de Venezuela S.A.Caracas, Venezuela

Robert SiegfriedGas Technology InstituteDesPlaines, Illinois, USA

For help in preparation of this article, thanks to PatriciaBonilla and Juan Ceballos, Caracas, Venezuela; KimiCeridon, Chuck Fensky, Mario Flores, Gus Melbourne, Joe Nahas, Dwight Peters and Brian Sidle, Sugar Land,Texas, USA; Beth Clark, New Orleans, Louisiana, USA; TrentHunter and Alan Salsman, Calgary, Alberta, Canada; Mike Kasecky, Anchorage, Alaska, USA; Karl Klaudi, BelleChasse, Louisiana; and Alan Sibbit, Houston, Texas.ABC (Analysis Behind Casing), ADN (Azimuthal DensityNeutron), ARC (Array Resistivity Compensated), Cased HoleRFT, CBT (Cement Bond Tool), CHDT (Cased Hole DynamicsTester), CHFR (Cased Hole Formation Resistivity), CQG(Crystal Quartz Gauge), ELANPlus, GPIT (General PurposeInclinometry Tool), LFA (Live Fluid Analyzer), MDT (ModularFormation Dynamics Tester), OFA (Optical Fluid Analyzer),RFT (Repeat Formation Tester), RSTPro (ReservoirSaturation Tool for PS Platform string) and USI (UltraSonicImager) are marks of Schlumberger. Monel is a mark of Inco Alloys International, Inc.

Spring 2002 47

Exploration and production companies evaluateoil and gas wells in many ways. Perhaps themost familiar evaluation methods are openhole-logging techniques, pioneered 75 years ago bySchlumberger. These techniques use surfacerecording and control equipment with a wirelinecable to convey measuring devices downhole andreturn signals to surface. Measurements andlogs can be gathered while drilling using tech-niques developed through the 1990s.1 Formationevaluation by logging cased wells is a less com-mon endeavor because measuring formationproperties through casing and cement is difficult.In spite of these obstacles, cased-hole measure-ments have contributed vital information sincethe 1930s.2 Newest in the cased-hole formation-evaluation toolkit is the ability to measure pressure and collect fluid samples from casedwells without compromising casing integrity and future producibility.

Reservoir pressure is one of the key propertiesthat engineers, geologists and petrophysicistsuse to characterize zones of interest. It can bemeasured in several ways, some of which alsoallow collection of formation-fluid samples.Devices like the MDT Modular FormationDynamics Tester tool routinely collect fluid samples and measure formation pressures inuncased boreholes. Held stationary while takingmeasurements, these openhole devices may runthe risk of sticking in difficult or overpressuredhole conditions or highly deviated boreholes.

Openhole drillstem tests (DSTs), which determinethe productive capacity, pressure, permeabilityand extent of a hydrocarbon reservoir, involveisolating the zone of interest with temporarypackers. Next, valves on the testing tool areopened to produce reservoir fluids through thedrillpipe, allowing the well to flow. Finally, thetesting specialist shuts the well in, closes the

valves, unseats the packers and trips the testingtools out of the hole. Depending on the testrequirements and goals, drillstem tests may lastless than one hour or extend several days orweeks; there might be more than one flow periodand one pressure buildup period. Like wirelineformation-tester operations, openhole DSTs alsopose mechanical risks, such as sticking.

When the risks of openhole formation testersor openhole drillstem tests appear prohibitive,exploration and production companies sometimesopt to run casing and forgo openhole pressuremeasurements. Thus, the ability to sample fluidsand test pressures in newly cased holes can becritically important.

Determining pressure and fluid type behindcasing is also valuable in older wells. Reservesbehind casing may have been bypassed for avariety of reasons, but these zones should be evaluated to guide field development andavoid premature well abandonment. In addition,data from cased wellbores help operators plan infill wells and monitor the progress of secondary-recovery operations, such as water,gas or steam injection.

The CHDT Cased Hole Dynamics Testerdevice is the first tool to penetrate casing, mea-sure reservoir pressure, sample formation fluidsand plug the test holes in a single trip (previouspage). Schlumberger and the Gas TechnologyInstitute (GTI) developed the CHDT tool jointly aspart of a GTI initiative to develop new ways toevaluate cased wells.3

In this article, we review precursors to theCHDT tool, describe how the new tool operatesand discuss some of the challenges in developinga cased-hole tester. Field examples demonstratethe wide variety of applications in which this toolcontributes to formation evaluation.

1. Bargach S, Falconer I, Maeso C, Rasmus J, Bornemann T,Plumb R, Codazzi D, Hodenfield K, Ford G, Hartner J,Grether B and Rohler H: “Real-Time LWD: Logging forDrilling,” Oilfield Review 12, no. 3 (Autumn 2000): 58–78.

2. Schlumberger: Cased Hole Log InterpretationPrinciples/Applications. Houston, Texas, USA:Schlumberger Educational Services, 1989.

3. Gas Technology Institute—formed in 2000 by the combi-nation of Gas Research Institute and the Institute of GasTechnology—is an independent US technology companythat provides research, technical services and trainingon topics related to natural gas, energy and the environ-ment. For more information:http://www.gastechnology.org/.

51381schD07R1 6/24/02 11:25 AM Page 47

Testing Cased WellsAs a first attempt to meet operator needs for fluidsamples and pressure measurements in casedholes, Schlumberger modified the RFT RepeatFormation Tester tool in the 1980s.4 The resultingCased Hole RFT Repeat Formation Tester toolperforates steel casing with a shaped charge. Aswith all perforations, the length of the perfora-tion tunnels cannot be controlled or predictedwithout knowing details of the casing, cement,formation pressure and lithology, which generallyare not available (above left). After testing andremoval of the Cased Hole RFT tool from the

well, the perforation tunnel may be covered by apatch, a plug or a cement-squeeze operation.This tool can test two stations per trip.

While this cased-hole tester allows operatorsto gather important pressure data, fluid-samplequality may be suboptimal because there is nomeasurement of the fluid properties prior to collecting a sample, and there is no pressure-drawdown control once the sample-chambervalve is opened. Returning the well to a produc-tive state may be difficult because achieving ahigh-quality casing seal can be complicated and

time-consuming. In addition, perforation entry-hole burrs on the casing wall can impede futureoperations (top right). The Cased Hole RFT toolhas a larger external diameter than the CHDTtool, so it cannot be used in small-diameterwells. Also, the Cased Hole RFT tool cannot becombined with MDT modules.

Recently, the MDT tool was used to collectsamples through perforations in cased holes.5

The Cased Hole RFT device and the MDT toolboth served as important milestones on the pathto the CHDT tool, since these tools addressedmany problems of openhole testers and openholedrillstem tests.

The CHDT tool overcomes the limitations ofthe Cased Hole RFT tool by drilling precise, con-sistent sampling tunnels (above). At the sametime, the CHDT tool can evaluate up to six sta-tions per trip, tripling the capability of the earlier

48 Oilfield Review

4. Burgess KA, MacDougall TD, Siegfried RW and Fields TG:“Wireline-Conveyed Through-Casing Formation TesterPreserves Casing Integrity,” paper SPE 72371, presentedat the SPE Eastern Regional Meeting, Canton, Ohio, USA,October 17-19, 2001.

5. For more on fluid sampling using the MDT tool in casedholes: Hurst S, Hows M and Kurkjian A: “Cased-HoleTester Provides Field Testing Alternative,” Oil & GasJournal 99, no. 24 (June 11, 2001): 49–52.

> Model of cased-hole tester and CHDT results. A cased and cemented sec-tion of Berea sandstone was perforated with a traditional cased-hole testerand also drilled with the CHDT tool (top). The lengths of Cased Hole RFT per-foration tunnels cannot be controlled. In contrast, the CHDT tool drills preciseand consistent tunnels (bottom).

Casing burrs

> Jagged perforation entry holes from a cased-hole tester.

> CHDT tunnels and plugs. The CHDT tool drillssmooth holes through casing, cement and forma-tions. CHDT plugs fit snugly in the holes.

Hurst S, Hows M and Kurkjian A: “Cased-Hole TesterProvides Field Testing Alternative,” Oil & Gas Journal 99,no. 25 (June 18, 2001): 50–52.

6. For more on fluid sampling using the MDT device:Andrews RJ, Beck G, Castelijns K, Chen A, Cribbs ME,Fadnes FH, Irvine-Fortescue J, Williams S, Hashem M,Jamaluddin A, Kurkjian A, Sass B, Mullins OC, Rylander Eand Van Dusen A: “Quantifying Contamination UsingColor of Crude and Condensate,” Oilfield Review 13, no. 3(Autumn 2001): 24–43.

51381schD07R1.p48.ps 5/21/02 2:05 AM Page 48

Spring 2002 49

tool. It is the first purpose-built tool for cased-hole formation testing that can acquire multipleformation pressures, retrieve high-quality forma-tion-fluid samples and restore pressureintegrity—all in a single, cost-effective opera-tion (below left). The tool can be conveyed onwireline, on drillpipe or with a tractor, which is a device used to convey tools in highly deviated wells.

Cement-bond quality is a key considerationwhen preparing for CHDT operations. If the bondis poor, communication between zones mightaffect test results. Knowing the condition of thecasing and the location of external casing hard-ware, such as centralizers, also is important.These factors can be assessed using the USIUltraSonic Imager tool in combination with theCBT Cement Bond Tool device to evaluate cementquality and casing parameters. Casing andcement thickness and rock type affect the easeand speed of drilling test holes.

As operations begin, the CHDT tool first is runto the target depth. Anchor shoes push the toolpacker against the casing to provide a sealbetween the inner surface of the casing and thetool. A packer-seal test ensures that a seal is prop-erly established before drilling into the casing.

After the seal is verified, a hybrid bit on a flex-ible drill shaft starts to drill. The drilling mecha-nism is hydraulically isolated from the borehole;the drill-bit position and pressure of the fluid sur-rounding the drill bit are monitored at surface.

The fluid around the drill bit may be completionfluid, such as brine, or oil-base or water-basedrilling fluid. As the drill bit advances through thecasing into cement, small pressure variationsresult from the differences in volumetric changesand pore pressure of the cement. As drilling continues into the cement, cleaning cycles effec-tively remove debris from the tunnel and pull thedebris into the tool. This procedure enhancesdrilling performance and reduces torque at thebit. The bit is versatile and durable for drillingsteel, cement and rock in one operation.

Once the bit encounters the formation, themeasured pressure stabilizes at reservoir condi-tions, and drilling can stop. Reducing the pressureof the fluid surrounding the bit prior to drillingenhances the pressure response when communi-cation is established with the formation, whichmakes detection of the response easier.Extending the drilled tunnel deeper into the for-mation increases the flow area for evaluatinglow-permeability formations and increases thechance of intersecting natural fractures. The toolcan drill up to 6 in. [15 cm] from the internal surface of the casing.

For drawdown analysis, the CHDT tool canperform multiple pretests at various rates withvolumes up to 100 cm3 [6 in.3]. A pretest is per-formed to obtain accurate formation-pressurerecordings. However, it also indicates if a high-quality sample may be retrieved by making a preliminary test for hydraulic seal and mobility.The CHDT pretest chamber may be filled, purgedand filled again. Performing multiple pretests atdifferent penetration depths can detect the presence of a microannulus and ensure that

formation-pressure measurements are repeatable.The wellsite pretest interpretation considers thedepth of penetration into the formation in theanalysis and incorporates either strain-gauge orCQG Crystal Quartz Gauge pressure responses.

CHDT samples are collected when suitablecommunication is established between the tooland the formation. The tool monitors resistivityfor fluid typing and can be combined with theOFA Optical Fluid Analyzer, LFA Live FluidAnalyzer and pumpout modules from the MDTtool for advanced fluid typing and contaminationmonitoring (left).6

The CHDT tool can incorporate 1-gal [3.8-L]H2S-rated sample chambers, which are suitablein most 51⁄2-in. casing. The external diameter ofsample chambers from the MDT tool is 43⁄4 in.;those sample chambers can be conveyed in wellswith 7-in. or larger casing. The sample chambersinclude the multisample module, which can holdsix bottles. The multisample bottles are 450-cm3

[27-in.3] or 250-cm3 [15-in.3] single-phase bottles.There are also 1-, 23⁄4- and 6-gal [3.8-, 10.4-, and22.7-L] sample chambers. Deploying severalchambers simultaneously increases efficiency.

After pressure testing and sampling a particular target, the CHDT tool inserts a corro-sion-resistant Monel plug to seal the hole drilledin the casing (above). This metal-to-metal seal

Length (without sampling)

Optional sample chamber

Tool OD

Casing size

Temperature

Pressure

H2S service

Maximum underbalance

Maximum holes drilled and plugged†

Drilled hole diameter

Maximum penetration

Plug pressure rating

Pretest volume

Pressure sensors

Standard CQG pressure

Sampling

Fluid identification

MDT combinability

31.2 ft

9.7 ft

4 1⁄4 in.

5 1⁄2 in. to 9 5⁄8 in.

350°F

20,000 psi

Yes

4000 psi

6 per run

0.28 in.

6 in.

10,000 psi, bidirectional

100 cm3

CQG and strain gauges

15,000 psi

PVT and conventional

Resistivity and LFA module

Yes‡

†Formation dependent ‡Combinable with MDT modules in 7-in. and larger casing (pumpout, OFA and PVT sample chambers)

> CHDT specifications. This complex yet robusttool operates in environments up to 350ºF [177ºC]and 20,000 psi [138 MPa]. Its modular designmakes it adaptable for numerous applications.

Power-cartridge

Sample-unitmoduleDrilling-control

gg

module

Probemodule

Power-cartridgemodule

Pumpout module

Multisample module

Sample-unit module

OFA module

Drilling-control module

Probe module

> CHDT combinations. The four modules of thestandard CHDT tool are shown on the left. Mod-ules from the MDT device can be combined withthe CHDT tool, as shown on the right.

> CHDT plugs. These photographs reveal howprecisely the plugs fit in the test holes.

51381schD07R1.p49.ps 5/21/02 2:05 AM 9

restores pressure integrity to the casing and israted to a differential pressure of 10,000 psi [69 MPa]. The change in original internal casingdiameter after the plug is set is only 0.03 in. [0.8 mm]; this upset, or protrusion, can beremoved without reducing the pressure rating ofthe plug.

Restoring the pressure integrity of the casingafter CHDT operations eliminates the costs andrig time associated with conventional plug-setting runs, cement-squeeze operations, pressuretests and scraper runs. During the life of a well,the CHDT tool may provide information that canconfirm or eliminate the need for full-scale perfo-rating by allowing cost-effective testing of zonesbefore workover or well abandonment.

The CHDT results can be integrated withother through-casing formation-evaluation tools,such as measurements from the CHFR CasedHole Formation Resistivity tool and the RSTProReservoir Saturation Tool service. The resultingcomprehensive formation evaluation, performedthrough casing, eliminates guesswork that canresult in irreversible, expensive or less-than-optimal decisions. The CHDT service provides acost-effective method to optimize recompletionplans, enhance old or incomplete log data,assess unknown pay zones and evaluate wellsfor economic potential.

The CHDT tool—even at this early stage in itsuse—has a 93% success rate for plugging holes.This reliability means that remedial action maybe necessary only 7% of the time. Remedialtechniques, such as isolation with a bridge plug,installation of a casing patch or cement-squeezeoperations, are typical contingency plans if CHDTholes cannot be plugged. A continuous challengeis to increase operational reliability (above left).Prejob preparation is a key to meeting plannedobjectives. Preparations are tailored for each jobbecause of the wide range of applications inwhich the CHDT tool is used.7

Testing and Sampling in Exploration WellsChevronTexaco drilled a challenging deepwaterexploratory well in the Gulf of Mexico, USA (left).Planning the well according to the No DrillingSurprises (NDS) initiative ensured that the wellwould be drilled and evaluated as safely andthoroughly as possible.8

50 Oilfield Review

Effic

ienc

y, %

5010 15 20 25 30 35 40 45

Number of tool runs50

Cumulative plugging-success ratio

55 60 65 70 75 80 85 90

55

60

65

70

75

80

85

90

95

100

> Improving CHDT reliability.

LOUISIANA

MISSISSIPPI ALABAMA

FLORIDA

G u l fo f

Me

xi

co

> Location of the ChevronTexaco exploration well, Gulf of Mexico, and a photograph of the compliant tower.

7. For more on CHDT applications: Burgess et al, reference 4.8. For more on the No Drilling Surprises initiative: Bratton T,

Edwards S, Fuller J, Murphy L, Goraya S, Harrold T, Holt J,Lechner J, Nicholson H, Standifird W and Wright B:“Avoiding Drilling Problems,” Oilfield Review 13, no. 2(Summer 2001): 32–51.

51381schD07R1.p50.ps 5/21/02 2:05 AM 0

Firs

t tes

t poi

ntSe

cond

test

poi

ntTh

ird te

st p

oint

0 0hr

Density Time After Bit

40 200

0 API

ARC Gamma Ray

150

0 hr

ARC Resistivity Time After Bit

40

1000 ft/hr

Rate of Penetration,Averaged over Last 5 ft

0

0.2 ohm-m

ARC Non-BoreholeCorrected Phase-Shift

Resistivity 10-in. at 2 MHz







20

0.2 ohm-m 20

0.2 ohm-m 20

0.2 ohm-m 20


Resistivity 40-in. at 2 MHz 0.2 ohm-m 20

60 p.u.

Thermal Neutron Porosity

Bulk Density, Bottom

Bulk Density

Bulk Density CorrectionBottom

0

1.85 g/cm3 2.85

1.85 g/cm3 2.85

0.8 g/cm3 -0.2

Differential Caliper

0 in. 20

ADN Rotational

Speed (RPM_ ADN)

rpm

Downhole electricalconnector for drillpipeconveyance

Swivel

Tension or compressionmeasurement

Telemetry module

Gamma ray

Inclinometry measurement ofX-, Y- and Z-axis acceleration

CHDT power cartridge

Multisample module

OFA module

Pumpout module

CHDT electronicsand control

Crossover

CHDT probe module

XX,700

XX,500

XX,500

Depth,ft

Spring 2002 51

ChevronTexaco acquired ARC Array ResistivityCompensated and ADN Azimuthal DensityNeutron logs while drilling. Suboptimal hole conditions precluded deploying other openholeformation-evaluation devices before running cas-ing, but there were two questions to resolve:whether two sand lobes were connected to eachother and a nearby producing well, and whetherthe lower target zone had an oil-water contact.

To fully evaluate the prospect, ChevronTexacoran the CHDT tool with the OFA device, convey-ing it on drillpipe for the first time. With thesetools, it would be possible to assess reservoircompartmentalization by measuring pressure andto evaluate fluid content by collecting samples. Itwas also the first CHDT job to be run from a2001-ft [610-m] tall compliant tower in 1754 ft[535 m] of water. The compliant tower was inconstant motion. In addition, it was the first timethe CHDT tool drilled through spiral pipe.

The operating environment created substan-tial concerns for the ChevronTexaco engineers.The CHDT tool drills holes that are 0.28 in.[0.71 cm] in diameter, so tool movement duringthe operations after drilling the hole could createsufficient misalignment to make the pluggingoperation impossible. The major concern wasthat the drillpipe would move and reposition thetool, so the engineers devoted considerableeffort to developing alternative plans. For exam-ple, running a squeeze packer in the drillpipeassembly, above the CHDT tool, would allow thepacker to be set in the casing to support theweight of the tool and minimize the chance thatthe tool might move.

Eventually, ChevronTexaco ruled out all of thealternative plans, and instead opted to monitordownhole accelerometers for 30 minutes beforebeginning the drilling process. The X-, Y- and Z-accelerometers are a part of the GPIT inclinome-try tool, which may be included in the CHDT toolstring. It monitors the acceleration of the downhole tool in the X-, Y- and Z- directions. Bywatching the Z-axis in particular, the loggingengineer can tell if the tool is moving. In addition,wellsite personnel monitored head tension andhydrostatic pressure and ensured conditions ofdrillpipe-neutral weight before the CHDT toolstarted the drilling sequence.

ChevronTexaco wanted to drill, test and plugthree holes (right). The first test point would bedrilled for a pressure measurement to determineif the upper sand lobe encountered in this wellwas the same sand found in the nearby produc-ing well. The formation pressure measured in thesecond test point would indicate if the lower

> Deep objectives. The well trajectory exceeded 24,000 ft [7315 m] measured depth and penetratedtwo sand sections. The upper sand predicted in the well prognosis was expected to be the samesand found in a nearby producing well (first test point). The formation pressure measured in the sec-ond test point would indicate if the lower lobe of the upper sand also was connected to the produc-ing zone in the nearby well. The third test point would show whether there was a water contact inthe lower target sand, or if the decreasing resistivity measurement was due to changes in lithology.The fluid sample from the third point would be sent for pressure-volume-temperature (PVT) analysis.The CHDT tool string used in this operation is shown to the right of the logs.

51381schD07R1.p51.ps 5/21/02 2:05 AM Page 51

lobe of the upper sand also was connected to theproducing zone in the nearby well. The third testpoint would show whether there was an oil-water contact in the lower target sand, or if thedecreasing resistivity measurement was due tochanges in lithology. The fluid sample from thethird point would be sent for pressure-volume-temperature (PVT) analysis.

ChevronTexaco was willing to assume therisk that the tool might not be able to plug theholes because it needed pressure measurementsfrom the first two points to plan field develop-ment. Before the job began, the companydecided that if the plugs could not be set, then itwould squeeze the first two holes with cementand leave the third hole open.

The operation proceeded flawlessly and with-out any lost time: the three holes were drilled,tested and plugged successfully. ChevronTexacowas able to complete the well as planned andperform a fracture-stimulation treatment in thelower zone. The well was put on production andcontinued to produce 10,000 BOPD [1600 m3/d]five months later. More significantly, the operatorobtained answers to pertinent questions aboutthe field. The first test confirmed the sand wasconnected to the offset well (right). The secondinterval, which was water-bearing, proved not tobe connected to the upper sand or the offsetwell. Surprisingly, the third test indicated thatthe deepest sand was oil-bearing rather than wetin the lower portion of the interval.

While the CHDT operations were successful,the job proved to be demanding. For example,ChevronTexaco wanted to collect six fluid sam-ples from the third point. The plan was to drill thehole, take samples at 30-minute intervals andobtain a sample with minimal contamination,while always retaining a sample in case theprobe became plugged. The probe becameplugged because of the unconsolidated nature ofthe sand. The engineer reversed the pump tounclog the probe. This operation pumped bore-hole fluid into the formation, but retracting theprobe from the casing was not desirable.Retracting and resetting the probe might nothave allowed successful realignment of the plugwith the drilled hole. Nevertheless, the samplescollected suggested that the zone was oil-bear-ing, not wet.

ChevronTexaco was impressed with the per-formance of the CHDT tool and the information itprovided. The fact that all three of the holes weresealed successfully and passed pressure testswas particularly important to the operator. The

52 Oilfield Review

7000

6000

Pres

sure

, psi

Time, sec

Mud pressure before test, psi: Mud pressure after test, psi: Latest buildup pressure, psi: Drawdown mobility, mD/cp:

5739.75 5740.62 4772.89 833.1

5000

4000

3000

2000

1000

0 1000 2000 3000 4000 5000 6000 7000 80000

First Point

Pretest volume: 31.3 cm3

Seal check

Seal check

Seal check Seal check

Retract

Plug

Retu

rn to

hyd

rost

atic

Plug

-sea

l che

ck Re

cycl

e pr

etes

t

Succ

essf

ul p

lug-

seal

che

ck

Drill

0.7

in.

10-c

m3 p

rete

st

30-c

m3 p

rete

st

Drill

2.1

in.

30-c

m3 p

rete

st

7000

6000

Pres

sure

, psi

Time, sec


5772.82 5773.36 5335.95 175

5000

4000

3000

2000

1000

0 1000 2000 3000 4000 5000 60000

Second Point


Seal check

Pressure stabilizationPlug

Retract

Drill

0.5

in.

Drill

2.4

in.

20-c

m3 p

rete

st

20-c

m3 p

rete

st

Recy

cle

pret

est

Plug

-sea

l che

ck

Retu

rn to

hyd

rost

atic

7000

6000

Pres

sure

, psi

Time, sec


5927.71 5926.31 5569.57 24.6

5000

4000

3000

2000

1000

0 1000 2000 3000 4000 50000

Third Point


Seal check

Pressure stabilization

Begin pumpoutDrill

0.6

in.

Drill

1.1

in.

20-c

m3 p

rete

st

20-c

m3 p

rete

st

Set

Set

Set

> CHDT pressure plots from a Gulf of Mexico well. All tests proceeded without incident.

51381schD07R1.p52.ps 5/21/02 2:05 AM Page 52

Spring 2002 53

next well drilled in the field had similar hole prob-lems, and the CHDT tool was run again, this timeto drill, test and plug five holes. ChevronTexacobelieves that the CHDT device provides an oppor-tunity to acquire key reservoir data in wells whereopenhole logging is not feasible.

In Alaska, USA, the CHDT tool was used tomeasure pressure and collect five fluid samplesfrom an exploration well during the winter of2000 to 2001 after hole conditions prevented useof an openhole sampling tool. All holes wereplugged successfully, and casing integrity wasverified by mechanical integrity tests. In Alaskaas in the Gulf of Mexico, the CHDT device hashelped operators acquire pressure data and high-quality PVT samples to fully evaluate challengingexploration prospects.

Cased-Hole Testing for Reservoir ManagementPressure data are especially valuable when oper-ators formulate long-term reservoir-managementplans. In these situations, companies want togather data without permanently altering thecasing or cement in their producing wells.Perforating with explosive charges and thenrepairing the holes with cement squeezes, com-mon procedures when using other cased-holeformation testers, are less desirable than drillingsmooth sample holes and plugging them. AeraEnergy LLC employed the CHDT tool in five wellsto determine formation pressures, evaluatedepletion and plan infill wells. These wells pro-duce oil from a diatomite formation in SouthBelridge field, California, USA (above left).9

As in all CHDT deployments, Aera developedextensive prejob plans. Cased-hole CBT logs andultrasonic imaging logs were acquired to deter-mine the condition of the cement and casingintegrity. A junk basket and gauge ring also wererun to ensure safe passage of the CHDT tool tothe target zones. Rig blowout preventers and killpumps were available at all times in case thesample hole drilled encountered higher pressurethan expected and the casing was not plugged.By choice, no fluid samples were collected.

In each of three wells, six tests were con-ducted on a single trip. In two additional wells,twelve tests were conducted in two trips. Allholes were plugged successfully. Pressure gradi-ents were identified in each well to ascertainbypassed zones and zonal connectivity (left). Asfluid was withdrawn from the formation into the

Los Angeles

Kern County

San Francisco

CALIFORNIAUSA

Bakersfield

South Belridge field

0

0 100 200 300 km

100 200 miles

> South Belridge field, California, USA. The field produces oil from the Belridgediatomite formation.

1200

1600

2000

2400

Dept

h, ft

2800

32000 25 50 75 100 300 700 1100

Pressure, psiAPI1500 1900 0 60 120

Gamma Ray Pressure Profile Drawdown Mobility

Mobility, mD/cp180 240

> Openhole gamma ray log, pressure profile and drawdown-mobility profile from a South Belridgewell. A comparison of the measured pressure profile (blue curve of center plot) with the initial pressureprofile (red line) illustrates zones with significant to little depletion. The mobility profile (right) confirmedpotential zones of high and low productivity.

9. Diatomite is a soft, silica-rich sedimentary rock comprising diatom remains. Diatomite, which forms mostcommonly in lakes and deep marine areas, can be anexcellent reservoir rock.

51381schD07R1.p53.ps 5/21/02 2:05 AM Page 53

pretest chamber at a measured flow rate, the toolalso measured buildup and drawdown pressures.These measurements allowed real-time analysisof each pretest to estimate drawdown mobilityfor the specific zones tested. The pretest pres-sure interpretation assumes spherical flow of aslightly compressible fluid in a homogeneous

formation.10 There was good repeatability on suc-cessive pretests at each pressure-test depth (below).

The depletion measured in the CHDT tests isbeing used to guide infill-well placement (bottom).On the basis of CHDT data, Aera now is reconsid-ering the current well spacing in that portion ofthe field.

Monitoring Reservoir Pressure in Infill WellsDetermining the rates of depletion in distinctreservoir zones is a difficult task, but one that isvital to optimizing production. In the past, reser-voir pressures were obtained using openhole RFTdevices, or by individually completing and testingseparate reservoir units in cased holes. In cer-tain fields in Alberta, Canada, these methods are uneconomical.

Recently, a carbonate reservoir in a matureAlberta gas field was evaluated with the CHDTtool. The Dunvegan Debolt reservoir comprises800 ft [240 m] of interbedded limestone, dolo-stone, shale and anhydrite. Production comesfrom 15 dolostone zones that typically have lessthan 30 ft [10 m] of vertical separation. All gaszones are completed at the same time, and pro-duction is commingled; historical well-pressuredata represent an average value of all producingzones in a well.

The Dunvegan field, discovered in the 1960sand developed in the 1970s, is approximately50% depleted. A key challenge in all subsequentinfill-drilling programs is to optimize infill-welllocations. Currently, infill locations are selectedon the basis of predicted pressure or depletionrate, so knowing the pressure of each zone isvaluable to the operator, Anderson ExplorationLtd., now Devon Canada Corporation.

Devon drilled Well 7-3 during its 2001 infill-drilling program in the Dunvegan field (next page,top). The company decided to measure pressurein eight zones using the CHDT device. Unliketheir openhole counterparts, cased-hole deviceslike the CHDT tool can be run from a crane or service rig and do not require having a drilling rigon standby, which means that acquiring theCHDT data is economically practical in thismature field.

Prior to running the tool in the hole, the teamreviewed CBT and USI logs to assess cementquality and confirmed that the zones to be testedwere isolated from each other. Pressure mea-surements from eight zones were acquired in twowireline descents of the CHDT tool. The mea-surements demonstrated that six of the eightzones in the infill well consisted of reservoir-quality rock; the other two intervals—Tests 4 and5—are inconclusive because the zones were relatively tight or may be supercharged (nextpage, bottom).

Since the composition of the gas in the fieldwas well-known, there was no incentive toacquire samples. After the formation pressure

54 Oilfield Review

10. For more on the interpretation technique: Burgess et al,reference 4.

1600

1400

Pres

sure

, psi

Time, sec

Mud pressure before test, psi: Mud pressure after test, psi: Latest buildup pressure, psi:

1041.11 1040.98 1002.07

1200

1000

800

600

400

0 500 1000 1500 2000 2500 30000

RetractPlug

Recycle pretestRecycle pretest

Set

Casing- seal

check

Casing- seal

check

Drill 2.52 in. 40-cm3 pretest

> South Belridge CHDT operations. The repeatability of multiple pretests atone point in this well shows that operations progressed smoothly. Real-timeanalysis of CHDT pressure data helped Aera evaluate depletion to optimizeinfill drilling.

2500

2000

1500

Dept

h, ft

Pressure

Well A Well B Well C Well D

1000

500

0

> Comparison of measured (blue) and initial (red) pressure profiles in fourstudy wells. In a fifth well, the CHDT tool was run in a different formation afterthe company reviewed the pressure and mobility profiles of the four wellsshown here. In managing the reservoir, the CHDT tests provided valuableinformation for secondary-recovery strategy.

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Spring 2002 55

was measured, all of the holes were pluggedsuccessfully. Since all of the potentially produc-tive zones in the well would be perforated afterCHDT testing, successful plugging was not a crucial aspect of this job.

The pressure data revealed that one zone—Test 3—was more depleted than Devon sus-pected, suggesting drainage by another nearbywell. Another zone—Test 6—had a higher-than-expected pressure. Devon incorporated theseresults into their field model, which has led tonew opportunities for optimizing well placementas the infill-drilling program proceeds.

The value of CHDT data in the Dunvegan fieldis high: Devon can improve the number and loca-tions of infill wells continuously. The companysaves about C$1 million each time it avoidsdrilling an unnecessary well. Devon also seeks toincorporate new data as quickly as possible toimprove its infill-drilling operations rather wait-ing until the end of a drilling campaign; CHDTdata offer immediate information for input tofield models. Because Dunvegan infill-well locations are selected on the basis of reservoir-engineering interpretations rather than seismicdata, CHDT data are important for analyzing wellperformance and calculating material balance.Because the CHDT tool acquired the necessarydata while minimizing cost and risk, it is likely tobecome a standard component of Dunvegan wellevaluations in the future.

Edmonton

Dunvegan field

Calgary

ALBERTA

0

0 200 400 600 km

200 400 miles

> Location of Dunvegan field, Alberta, Canada.

Test 164090

Dept

h, m

Test 25949

Test 35043

Test 7 74199

Test 86888

Test 69446

Test 413,704

Test 514,015

Pressure, kPa

XX30

14,000 16,00012,00010,00080006000

XX40

XX50

XX60

XX70

4000XX90

XX80

Wellbore hydrostatic pressure

Anticipated pressure range

Moved Hydrocarbon

ELANVolumes

1 vol/vol 0

Lithology

Water

Gas

Dolomite

Calcite

Anhydrite

Clay

> Reservoir depletion. CHDT pressure measurements (green symbols) from eight zones in Dunvegan Well 7-3 indicate variousstages of depletion in the Debolt reservoir. Lithology, determined using ELANPlus software, appears at right. The red line showswellbore hydrostatic pressure. Pressure measurements were expected to fall in the zone shaded in lavender. Tests 4 and 5 werelikely influenced by the tight nature of the formation, or might be supercharged. CHDT measurements clearly demonstrate adepleted interval in Test 3 and higher-than-expected pressure in Test 6.

51381schD07R1.p55.ps 5/21/02 2:05 AM Page 55

Testing Old Wells in South AmericaIn an unconsolidated, oil-bearing sandstone inthe Sur field in southern Venezuela, two zonespenetrated by a slightly deviated well were eval-uated during CHDT operations (right). The opera-tor, Petróleos de Venezuela S.A. (PDVSA), wantedto determine the formation pressure. To preparefor testing and sampling operations, the teamevaluated the integrity of the cement and con-firmed that there was good isolation between thezones to be evaluated.

PDVSA also wanted to recover fluid samples,but the unconsolidated nature of the formationmade it unlikely that fluid samples could beretrieved. The operator believed that the value ofpressure measurements alone made CHDT oper-ations worthwhile, but decided to increase thelikelihood of collecting a fluid sample by applyingthe low-shock sampling technique.11

A disadvantage with conventional formationtesters is that the sampling process can create apressure shock in the formation and fluid. At themoment the chamber is opened, a sudden pres-sure decrease occurs, and an associated surge offluids commences when the formation is openedto sampling chambers at atmospheric pressure.In addition, high flow rates can loosen matrixgrains, causing plugging in the flowline.12

The low-shock sampling technique wasdeveloped to limit pressure drawdown duringfluid-sampling operations. The shock is mini-mized by pumping formation fluids into the test-ing tool against piston chambers held at boreholepressure, as opposed to drawing formation fluidinto chambers at atmospheric pressure. Beforethe sample chamber is opened, the pumpoutmodule flushes filtrate from the formation back tothe wellbore. The flowline fluid can be monitoredusing the OFA module to determine when a low-contamination sample can be recovered, and thefluid flow can then be diverted into a samplechamber without interrupting the flow pattern.

The well being tested was drilled in March1998 and originally was completed in one zone.Because of high water production, PDVSAdecided to test an additional zone to determinethe formation pressure and the type of fluids pre-sent in the zone. A sand sample from the wellindicated that the formation was highly porous,poorly consolidated and would probably clog thetesting tool.

Sample collection was attempted twice, butwas unsuccessful because sand clogged the tool.Pressure measurements were recorded, and bothholes were plugged successfully (right). The pres-sure data were immediately useful to PDVSAbecause a lower-than-expected pressure mea-surement indicated that neighboring wells were

56 Oilfield Review

A

nd

es

G

ui a

na

Hi

gh

l an d s

Mo

un

t a i n s

VENEZUELA

TRINIDAD ANDTOBAGO

San Cristobal

Caracas

C a r i b b e a nS e a

Sur field

0

0 300 600 km

200 400 miles

> Location of the Sur field, Venezuela.

4000

Pres

sure

, psi

Time, sec


3095.52 3088.742023.24 938

1000

1500

2000

2500

3000

3500

500

0 1000 2000 3000 4000 5000 6000 70000


Seal check

Seal

che

ckHydrostatic pressure

Drill andpressure test

Hydrostatic pressure

Clogged flowline

Drill 2.5 in.

Drill

1 in

.

Cement-isolationcheck

> Testing in Venezuela. This plot of pressure versus time shows reservoirpressure was lower than expected. Late in the test, the flowline clogged, preventing sample recovery.

51381schD07R1.p56.ps 5/21/02 2:05 AM Page 56

Spring 2002 57

depleting one of the zones (above). By not perfo-rating a low-pressure reservoir, the companysaved over $250,000. Following this operation,formation pressures in two other old wells in thesame area were evaluated using the CHDT toolwith 100% plugging efficiency.

The Foundations of Formation EvaluationBehind CasingThe CHDT tool has been operational for more thanone year, including a rigorous field-testing stagein which it demonstrated its capabilities in a num-ber of challenging environments (left). Successfuldevelopment of this intricate electromechanicalsystem reflects years of engineering teamworkand innovation.

Behind-casing formation evaluation nowincludes nuclear and acoustic porosity, resistivity,rock mechanical properties, lithology, elementalanalysis and borehole seismic measurements.These measurements, along with data from theCHDT, CHFR and RSTPro devices, are part of thelarger ABC Analysis Behind Casing initiative,which offers complete formation evaluation incased holes.13 These services allow operators toobtain data in new wells in which logging-while-drilling or openhole logs are unavailable or inadequate, to assess bypassed pay in olderwells or to monitor reservoirs for depletion pro-files and changes in saturation or pressure.

As cased-hole formation-evaluation servicesand products mature and become more readily available worldwide, the industry willcontinue to seek more diverse applications forthese measurements. —GMG

11. For more on the low-shock sampling technique: Crombie A, Halford F, Hashem M, McNeil R, Thomas EC,Melbourne G and Mullins O: “Innovations in WirelineFluid Sampling,” Oilfield Review 10, no. 3 (Autumn 1998):26–41.

12. Newer CHDT tools, developed after the Venezuela wellwas tested, incorporate a filter to eliminate sandingproblems when sampling unconsolidated formations.

0 Gamma Ray, API Resistivity, ohm-m200 0.2 2000

> CHDT test points (red circles) in a producing well in Venezuela.

25,000

20,000

15,000

10,000

Mea

sure

d de

pth,

ft

5 10 15 20 25 30 35 40

Wel

l dev

iatio

n, d

egre

es

5000

0

100

80

60

40

20

0

90

70

50

20

10

0.6

0.5

0.4

0.3

Thic

knes

s, in

.

5

Standard block and bit

10 15 20 25 30 35 40

0.1

0.2

0

CHDT Casing Thickness

Temperature350

300

250

200

Tem

pera

ture

, °F

5

0

0

0 10 15 20

Number of jobs

Number of jobs

Number of jobs25 30 35 40

100

50

150

0

CHDT Depth and Deviation

> Diverse conditions in which the CHDT tool has operated successfully,including depth and deviation (top), casing thickness (center) and temperature (bottom).

13. For more on the CHFR tool: Aulia K, Poernomo B,Richmond WC, Wicaksono AH, Béguin P, Benimeli D,Dubourg I, Rouault G, VanderWal P, Boyd A, Farag S,Ferraris P, McDougall A, Rosa M and Sharbak D:“Resistivity Behind Casing,” Oilfield Review 13, no. 1(Spring 2001): 2–25.

51381schD07R1 06/03/2002 03:40 PM Page 57

formation testing and sampling through casing

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