Formation sampling and testing on wireline dates back nearly 40 years. Recent developments, however, may thrust the

58

The MDT Tool: A Wireline Testing Breakthrough

Nick ColleyBritish Gas Exploration & Production LtdReading, England

Tim Ireland United Kingdom Nirex LtdHarwell, England

Patrick ReignierTotal Oil Marine plcAberdeen, Scotland

Simon RichardsonMarathon Oil UK Ltd.London, England

Jeffrey JosephLondon, England

WELL TESTiNG

In this article, Acoustic TeleScanner, CQG (CombinableQuartz Gauge), FMI (Fullbore Formation MicroImager),Formation MicroScanner, MAXIS (Multitask Acquisitionand Imaging System), MDT (Modular Formation Dynam-ics Tester), MicroSFL, RFT (Repeat Formation Tester), andZODIAC (Zoned Dynamic Interpretation Analysis andComputation) are marks of Schlumberger.For their help in interpreting some of the data used inthis article, thanks to: Mike Pearson and Graeme David-son, Schlumberger Evaluation and Production Services(UK) Ltd, Aberdeen, Scotland; and Heather James andRachel Kornberg, Schlumberger Evaluation and Produc-tion Services (UK) Ltd, London, England.1. Zimmerman T, MacInnis J, Hoppe J, Pop J and Long T:

“Application of Emerging Wireline Formation TestingTechnologies,” paper OSEA 90105, presented at the8th Offshore Southeast Asia Conference, Singapore,December 4-7, 1990.

Wireline formation testers have evolvedthrough a series of innovations. The firsttools to be introduced, in the 1950s, con-centrated on fluid sampling. Then in 1975,the RFT Repeat Formation Tester added thecapability to repeatedly measure formationpressure during a single trip. Today, wirelineformation test tools are used to determineformation permeability from pressure tran-sients created by a known drawdown pulse.Now comes the next evolutionary step: theMDT Modular Formation Dynamics Tester(next page).

The MDT tool offers multiple samplingduring a single wireline run and rapid pres-sure measurement using a new-generation

quartz gauge that stabilizes quickly to accu-rately measure formation pressure.Improved electrohydraulic control moreeasily minimizes the drawdown pressuredrop, enhancing delicate sampling opera-tions. A variable drawdown volumeimproves permeability measurement, espe-cially in tight formations.

Further, the tool can be configured to pro-vide a range of options not previously avail-able from a wireline tester. For example, bymonitoring the fluid resistivity as it is drawninto the tool and rejecting contaminatedfluid, the operator can ensure that onlyuncontaminated formation fluid samples arecollected. Or, by measuring pressure inter-ference during drawdown, horizontal andvertical permeabilities can be determined.

As the name suggests, the MDT systemcomprises a number of modules. This articleexplains the modules and how they work,and, using field examples, shows how thesemodules can be configured to collect data.1

Oilfield Review

59

nThe Modular Formation Dynam-ics Tester in multi-probe mode.

Tom ZimmermanHouston, Texas, USA

Ian TraboulayMontrouge, France

Astley HastingsAberdeen, Scotland

April 1992

technique to the forefront of testing strategy.

The Basic ToolAt the center of most MDT configurationsare four modules making up the basic tool.

Electrical module—This moduleprovides the power to drive allthe downhole electronics and a1-kilowatt supply for the electro-hydraulic system.

Hydraulic power module—Thisprovides hydraulic power to theprobe modules (see below).

Single-probe module—Thismodule establishes pressure andfluid communication betweenthe tool and the formation. A

hydraulically-operated retractable probeembedded in a circular rubber packer isforced through the mudcake to make a sealwith the formation. Two opposing backuppistons on the other side of the tool push theprobe against the formation and help main-tain a good seal. The pistons also center thetool body in the well, reducing the risk ofdifferential pressure sticking. An advancedelectrohydraulic system means that theMDT probe can be set up to three timesfaster than previous testers.

After hydraulic connection is made, for-mation pressure can be measured by eithera strain gauge or the highly accurate CQGCombinable Quartz Gauge. First-generationquartz gauges employed in the earlier for-mation testers like the RFT tool are accuratebut respond slowly to pressure and, particu-larly, temperature transients. These gaugeshad to stabilize for up to 30 minutes, slow-ing operation and providing only static pres-sure measurements. However, the CQGgauge stabilizes in seconds, removing thislimitation (next page, top and see “GaugesThrough the Ages,” page 23).

To ensure that a good seal has been estab-lished between probe and formation, a’pretest’ is carried out, which yields a draw-down pressure transient. Formation fluid isdrawn into a chamber at a rate and volumecontrolled from surface. Up to 20 milliliters(mL) can be extracted against a differentialbetween the mud weight and the flowingformation pressure of up to 20,000 psi. An

60

unlimited number of pretests may be carriedout using different drawdown rates and vol-umes to optimize the transient.

The temperature of the fluid entering thetool may be measured and the fluid’s natureassessed. Inside the MDT probe module’sflowline, electrodes measure fluid resistivity.The first fluids to flow out of the formationare usually mud and mud filtrate. These arefollowed later by formation fluid. As long asthere is a resistivity contrast between the for-mation fluid and the mud, the transitionbetween fluids can be detected. Based onpretest results and fluid analysis, the engi-neer may elect to take samples.

Sample chamber modules—Anycombination of sample chamberswith capacities of 1 and 2.75 gal

[3.8 and 10.4 liters] can be assembled. Asingle flowline serves all the chambers—fluid routing is controlled from surface. Asingle, 6-gal [22.7-liter] chamber can bemounted at the bottom of the tool. Theoreti-cally, the tool can handle 12 separate 1- or2.75-gal chambers , but weight and lengthconsiderations keep the practical limit toabout six chambers. The sample chamberscan be located above the probe module,allowing sampling to take place just 0.53 m[21 in.] from the bottom of the well.

Other modules may be added to this basictool to substantially increase its capabilities.

Multisample module—Each ofthese modules can collect six450-mL [0.12-gal] samples, suit-

able for PVT (pressure-volume-temperature)laboratory analysis, from one or moredownhole locations during a single trip.Each sample is stored in an individual con-tainer that can be removed intact at surfaceand safely and legally transported for analy-sis without fluid transfer. Up to two modulesmay be included in an MDT test string. Toensure a representative sample of formationfluid, initial flow shown to be contaminatedby the fluid resistivity monitor is discarded.

To take a sample, an isolation valve in theprobe module is opened, allowing commu-nication between the formation and the topof the sample chamber. During the pretestpressure measurement, this valve is closedto limit flowline storage effects. Formationfluid is drawn into each sample chamber bya piston that strictly controls the pressure orflow rate under real-time MAXIS MultitaskAcquisition and Imaging System control,helping to prevent monophasic samplesfrom becoming multiphasic.

Pumpout module—As thename suggests, this modulepumps formation fluid that has

entered the tool out into the borehole. Themodule is used to dump contaminated fluidprior to sampling. It has to pump against thedifferential between formation flowing pres-sure and hydrostatic pressure in the well-bore. At a differential of 800 psi, the modulepumps at about 0.6 gal/min [38 mL/sec].

Flow control module—Thismodule provides 1-liter pressuredrawdown tests with accuratelycontrolled pressure or flow rate

(1 mL/sec to 200 mL/sec). In this way, alarger drawdown than that offered by thepretest can be controlled from surface, giv-ing extended transients and thereforeimproved formation pressure measurementand permeability determination.

Multiprobe module—Added tothe basic probe module, thiscreates a tool with three

probes—a sink for drawing fluid and twopressure-observation probes, the horizontalprobe opposite the sink, and the verticalprobe 70 cm [28 in.] above the sink.

The system is usually configured with theflow control module, drawing 1 liter of for-mation fluid through the sink probe to setup a pressure disturbance in the formation.Analysis of transients measured at the twoobservation probes yields vertical and hori-zontal permeability estimates and enhancespressure gradient information.

Dual-packer module—Thismodule, still under developmentand awaiting commercial intro-

duction in late 1992, has two packers, about86 cm [34 in.] apart. These are inflated bythe pumpout module to isolate a zone ofborehole from the column of mud. Thisallows drillstem tests (DSTs) and, if the probemodule is included, interference tests to becarried out. The packers allow zones to betested where the probe cannot seal—likefractured and fissured formations. The largerarea of reservoir isolated by the packers,compared to a probe, allows a greater flowrate to be achieved, increasing the depth ofinvestigation to perhaps 30 m [100 ft].

Oilfield Review

Peak Error

Stabilization time

0

Strain gauge 4 psi

Strain gauge

CQG gauge2.5 psi

CQG gauge

Conventional quartz gauge

–1 psi

+1 psi

Conventional quartz gauge 15 psi

Conventional quartzgauge, 39 min

Time, min

Strain gauge 17 min

Pre

ssur

e, p

si

CQG gauge, 18 min

8010

7995

798024 48

nComparing thestabilization char-acteristics of CQG,conventional quartzand strain gauges.This example of a10°C thermal shockat a constant pres-sure of 8000 psishows how the CQGgauge stabilizesmuch more rapidlyand has a muchsmaller peak errorthan a conven-tional quartz gauge.

Comparison of Pressure Gradients Derived fromMDT tests and DSTs

Zone

Upper

Middle

Lower

MDTpsi/ft

0.092 flowed gas 0.625 0.047

0.367

0.455

0.848

1.052

flowed oil

flowed water

0.367

0.441

DSTResult

SurfaceSG

DSTpsi/ft

The MDT Tool in ActionPressure measurement—The basic single-

probe configuration can measure reservoirpressure with a high degree of accuracy.Reservoir fluid pressure measurements canbe plotted versus true vertical depth (TVD)and used to infer the position of gas/oil andoil/water contacts.

The speed and accuracy of measuringpressure was recently proved in a well oper-ated by Marathon Oil UK Ltd in the UKNorth Sea. The MDT tool was deployed totake pressures at 45 depths in the well, ofwhich 33 provided usable pretest data (thefriable nature of the formation adverselyaffected the rejected measurements). In allcases, the CQG gauge stabilized rapidly,tracking the strain gauge included in thedownhole package, but producing muchmore accurate measurements.

Plotting the data versus TVD showsstriking linear trends corresponding to gas,oil and water (next page). The oil/water con-tact correlates precisely with that indicatedby openhole logs. The interpreted fluidsagree well with those observed during sub-sequent cased-hole DSTs (see “Comparison

April 1992

of Pressure Gradients Derived from MDTtests and DSTs,” above).

The MDT pressures from this well (Well 2)were combined with pressures gatheredusing an RFT tester in Well 2 and adjacentWell 1. Marathon, for the first time, wasable to demonstrate that the field containedtwo different gas accumulations—the twowells had each penetrated a different accu-mulation. Previous data had not provedaccurate enough to make this distinction.

Detailed plots of the data clearly revealedgas, oil and water gradients (page 63, top).The data from the water leg of the test inWells 1 and 2 overlie each other—to beexpected in this normally-pressured envi-ronment. However, if Wells 1 and 2 pene-trated the same gas-bearing interval, thereservoir pressure at any given depth in thatinterval would be the same in both wells.The formation pressure data gathered by theMDT and RFT tests showed that this was not

the case, with a 22-psi discrepancy betweenthe two wells. Because the data quality hadbeen shown to be highly accurate, separategas intervals were diagnosed.

Before accepting this diagnosis, one otherpossibility had to be eliminated: that thesand in Well 1 was not gas-bearing but oil-bearing. This scenario was discounted onthe basis of density and neutron logs whichshowed a clear gas effect.

Sampling—Traditional wireline formationtest tools are limited in recovering reservoirfluids because initial flow is usually contam-inated with drilling mud filtrate. A contami-

61

nFormation pressures measured using a CQG gauge in an MDT tester together with openhole wireline logs. In this example from aNorth Sea well, operated by Marathon Oil UK, both fluid type and contacts are clearly identifiable from the pressure profile.

Dep

th, f

t

x500

x600

x700

x800

Bit Size

Caliper

Gamma Ray

ILd

ILm

MicroSFL

∆t, FMD Laterolog Deep

Laterolog Shallow

Bulk Density Correction

Enhanced Vertical ResolutionDensity

1.95 2.95g/cm3

Neutron Porosity, Computed 45 -15p.u.

Photoelectric Factor 0 10

-0.35 0.15g/cm30 150API

10 20in∆t, STC

MicroSFL0.2 20ohm-m

0.2 20ohm-m

0.2 20ohm-m

140 µsec/ft 40

140 µsec/ft 40

20000.2 ohm-m

20000.2 ohm-m

20000.2 ohm-m

10 20in

lab—where a small volume of fluid in singlephase is rapidly exposed to atmosphericconditions and the resulting gas and liquidcollected for compositional and fingerprintanalysis. The liquid sample densities andgas/liquid ratios showed extraordinary con-sistency (see “Comparison of Sample PVTProperties,” next page, middle).

A reliable way of checking whether repre-sentative samples of a near-critical fluidhave been taken is by comparing their dew-point pressures at reservoir temperature. Theconsistency in the results obtained byobserving the sample in a windowed cell,used in the PVT laboratory to determine asample’s dewpoint, is self-evident.

Final corroboration of fluid samplingrepeatability was obtained by the gel per-meation chromatography fingerprintingtechnique, in which infrared and ultravioletdetectors are used to measure the number ofcarbon-hydrogen bonds versus alkane

nated sample can be used to prove the pres-ence of hydrocarbons, but has limited appli-cation for PVT analysis.

If water-base mud has been used duringdrilling, uncontaminated samples can begathered using the resistivity measurementin the single-probe module to detect mud inthe formation fluid and the pumpout mod-ule to eject contaminated samples. If PVT-quality samples are specified, the multisam-ple module must also be added.

A spectacular example of MDT samplingtook place in two adjacent wells in Total’sAlwyn field in the UK North Sea. The datashown here are from one of the wells. Thereservoir contains fluids that are close to thecritical point, at which they cannot bedefined as gas or liquid (near-critical fluids).These are notoriously difficult to sampledownhole, and reconstituted surface sam-ples may fail to yield consistent results. Toavoid the possibility of pumping gas into the

borehole, the pumpout module was notused. Instead, initial fluid intake wasdumped into a special 36-gal [136-liter]container attached below the 1-gal samplechambers. Because of the dump chamber’sweight and the deviation of the well, thetester was conveyed on drillpipe, ratherthan on wireline.

Through careful pressure control, the sam-ples in the first well were drawn with amaximum pressure difference of 8 psibetween formation and sample chamber, farbeyond the most optimistic expectations ofoperator or service company. Six 450-mLsamples were obtained.

Since these samples were retreived at nearvirgin conditions, results from laboratoryanalysis of four of the samples wereexpected to be more consistent than is usualfor conventionally sampled near-critical flu-ids. Expectations were exceeded. Smallflash separation was carried out in the

62 Oilfield Review

Pressure, psi

Dep

th, f

t

x500

x700

x450 x550

Gas

Oil

Water

63April 1992

molar mass. The samples had a virtuallyidentical fingerprint (next page, top). Toclinch consistency, compositional analysis ofthe samples revealed identical amounts ofthe hydrocarbon components and of carbondioxide and nitrogen (next page, far right).

Permeability measurement—Formationpermeability may be estimated by analyzingthe drawdown pressure response duringeach pretest. However, it is important thatthe rate and pressure of the drawdown becontrolled. For example, if the drawdownflow rate is too high for the formation per-meability, the flowing pressure of the fluidmight fall below its bubblepoint, ruling outanalysis of the resultant transient.

In the MDT tester, drawdown can beaccurately controlled from surface. Theengineer has the flexibility of establishingthe flow rate and either defining the volumeof fluid to be drawn off or setting a maxi-mum pressure drop.

Measuring permeability anisotropyrequires deployment of the more sophisti-cated multiprobe system—comprising basictool, multiprobe module, flow control mod-ule and usually sample chambers. The tool’sprobes are first used to monitor reservoirpressure—information that can sometimesbe used to locate formation barriersbetween the probes. Then, near-wellboreinterference tests are run. The flow controlmodule extracts up to 1 liter of formationfluid through the sink probe. The isolationvalve between the sink valve and the flow-line is then shut, setting up pressure distur-bances in the formation. The process of cre-ating pressure disturbances can be repeatedas many times and in as many locations inthe well as necessary.

For example, in British Gas’s South More-cambe field, offshore UK, multiprobe testswere conducted at 42 locations in the wellduring a single run (next page, middle). Thisexample shows one of the tests, from awater-bearing zone below the gas. The toolwas set near low-permeability streaks identi-

Comparison of Sample PVT Properties

Sample 1 2 3 4

Liquid Density, g/cm3 0.811 0.809 0.811 0.809

1030 1028 1013 1010

397.0 397.5 397.5 396.5

Gas/Liquid Ratio, Sm3/cm3

Dewpoint Pressure,bar-gauge

Gas, Well 20.065 psi/ft

Gas, Well 1

Oil, Well 20.368 psi/ft

Water, Wells 1 and 2 0.449 psi/ft

x600

x800

x1000

x1200

x450 x550 x650 x750

Pressure, psi

Dep

th, f

t

Well 1RFT

Well 2MDT RFT

nA plot of MDTand RFT pressuresfor Wells 1 and 2 todemonstrate thatthe field containedtwo different gasaccumulations.

fied as light-colored sinusoids on the Forma-tion MicroScanner image.

The reservoir contains a lower layer withreduced permeability which is caused byplaty illite blocking the pore throats. The gasin this layer will be produced from thehigher permeability upper layer throughvertical movement. The MDT test programwas designed to measure a vertical perme-ability profile through both layers and intothe aquifer below. The test under considera-tion was carried out in the aquifer.

As the sink probe accepts fluid and is thenshut in, the horizontal probe shows animmediate and quite large pressure change(∆p), while the vertical probe registers amuch smaller and delayed ∆p. That there isa reaction at the vertical probe, however,indicates some vertical permeability. Thequestion is how much?

With an interpretation package that ana-lyzes MDT multiprobe tests, the data werematched to a formation model comprising ahomogeneous formation with upper andlower boundaries some distance from thetool. The match gave horizontal and verticalpermeabilities of 5.50 and 0.22 millidarciesrespectively.2 This proves that across thezone seen on the Formation MicroScannerimage, there is some vertical communica-tion despite a large permeability anisotropyin the formation being tested. More com-plex models are under development to allowmore sophisticated multilayer analysis.

nDetermining vertical flow characteristics in shaley sand in the South Morecambefield, operated by British Gas, to assess the likely impact of water coning. The MDTtester in multiprobe configuration was deployed to measure drawdown and builduptransients across shaly streaks identified on the Formation MicroScanner log. The tran-sients are shown with the interpretation model (orange line). Flow rate, measured usingthe flow control module, was incorporated into the match using continuous convolution.

64 Oilfield Review

384.8

303.7

222.5

141.4

60.2

–20.9718.1 796.7 875.3 954.0 1032.6 1111.3

Pressure

Time, sec

Horizontal probe

Buildup

Drawdown

Time, sec

718.1 796.7 875.3 954.0 1032.6 1111.3

Flow

rat

e, c

m3 /

sec

22.5

17.8

13.1

8.3

3.6

-1.1

Vertical probe

Formation MicroScanner MDT

Flow

∆p, p

si

nCompositional analysis of Alwynsamples corroborating that near-identical samples were captured.

Sample 1Sample 2

Sample 3Sample 4

CO2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7+

Composition mole %0.01 0.1 1 10 100

Com

pone

nt

nGel permeationchromatographfingerprints ofnear-critical fluidsshowing thatrepeatable sam-ples have beencaptured fromTotal’s North SeaAlwyn field.

10 102 103 104

C-H

bon

ds

Equivalent alkane molar mass, g/mol

IR response

UV response

Sample 1Sample 2Sample 3Sample 4

65April 1992

2. Goode PA and Thambynayagam RKM: “AnalyticModels for Multiple Probe Formation Tester,” paperSPE 20737, presented at the 65th SPE Annual Techni-cal Conference and Exhibition, New Orleans,Louisiana, USA, September 23-26, 1990.Goode PA and Thambynayagam RKM: “Influence ofan Invaded Zone on a Multiple Probe FormationTester,” paper SPE 23030, presented at the SPE Asia-Pacific Conference, Perth, Australia, 4-7 November1991.Goode PA, Pop JJ and Murphy WF III: “Multiple-ProbeFormation Testing and Vertical Reservoir Continuity,”paper SPE 22738, presented at the 66th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas,USA, October 6-9, 1991.

3. Hegeman PS, Hallford DL and Joseph JA: “Well TestAnalysis with Changing Wellbore Storage,” paper SPE21829, presented at 1991 Rocky Mountain RegionalMeeting and Low Permeability Reservoirs Symposium,Denver, Colorado, USA, April 15-17, 1991.

Mini-DSTs With the Dual PackerModule—The experimental MDT packermodule may open up a radically new direc-tion for wireline testing, in which a smallzone can be tested yielding data that can beinterpreted using traditional techniques.With use of a transient test lasting just a fewminutes, formation information may bedetermined with a depth of investigation oftens of meters.

In a recent test for UK Nirex Ltd andBritish Nuclear Fuels plc in West Cumbria,England, an MDT tool with dual-packermodule was positioned over a naturallyoccurring fracture. The fracture wasidentified on both FMI Formation MicroIm-ager and Acoustic TeleScanner images (left).Several fluid samples were taken from thefracture, with a buildup pressure transientlasting about 6 minutes recorded betweeneach. The first buildup illustrates the qualityof the CQG gauge pressure data—both finalinterpreted log-log and generalized Horner-type plots are shown (below and see “Test-

102

∆p a

nd D

eriv

ativ

e, p

si

103

101

100

Radial flow regime

Pressure change

Pressure derivative

Pressure and derivative

∆p, p

si

400

300

200

100

0

∆t, hr

Generalized Horner

10-4 10-3 10-2 10-1 10-0

nLocating a suitable fracture for testingusing images from the Acoustic TeleScan-ner (left) and FMI Fullbore FormationMicroImager (right).

ing Design and Analysis,” page 28). Thederivative data were usable without smooth-ing and the radial-flow regime plateauclearly emerges at the end of the 6-minuteperiod.

Analysis, with Schlumberger’s ZODIACZoned Dynamic Interpretation Analysis andComputation program, provided an excel-lent match for the test, yielding estimates forparameters such as formation transmissivityand reservoir pressure. The match shownuses a new model for a situation in whichwellbore storage changes during the courseof the test3 —in this case, the changing well-bore storage is associated with fluid storedwithin the predominantly horizontal fractureitself, within the packed-off wellbore andwithin the tool’s flowline.

From this analysis, storage was found tohave stabilized at about five orders of mag-nitude smaller than would have beenobtained by conventional DST. It is mainlyfor this reason that radial flow can developafter just 6 minutes of shut-in. —CF, HE

nPlots of data froma mini-DST carriedout using the MDTpacker module.The radial-flowregime plateauclearly emerges at the end of the 6-minute test.