a revolution in reservoir characterization

7/27/2019 A Revolution in Reservoir Characterization

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A revolution in reservoir

characterization

Wireline formation testers have evolved through a series of

innovations and small refinements. The new Modular Formation

Dynamics Tester (MDT*) tool now offers major innovation - multiple

sampling during a single wireline run, and rapid pressure

measurement using new generation quartz gauges that stabilise

quickly to measure formation pressure. Multiple, uncontaminated

fluid samples, fast and accurate pressure surveys, determination of

permeability anisotropy and even a mini drillstem test on wireline are

all within the reach of the engineer today.

In this article Cosan Ayan, Adrian Douglas and Fikri Kuchuk show

some of the initial applications of the MDT tool.

Special Contribution - Anya Radeka for thorough and challenging field testing of the MDT

tool in the Middle East while with the Technique Department in Dubai.


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44 Middle East Well Evaluation Review

When wireline formation testerswere introduced, almost 40years ago, there was one simple

objective - fluid sampling. The first wire-line testing tool, the Formation Tester,was introduced in 1955, specifically to col-lect reservoir fluid samples, but couldonly collect one sample per trip in the

well. This tool was replaced first by theFormation Interval Tester (FIT*) andthen, in 1975, by the Repeat FormationTester (RFT*) tool.

The arrival of the RFT tool allowedoperators to devise new applications forwireline testing. The fluid sampling capa-bilities of the RFT tool often played a sec-ondary role to the repeat pressuremeasurements which this tool made pos-sible for the first time.

The most recent step of this evolu-tionary progression is the developmentof the Modular Dynamics FormationTester (MDT*) tool. As a replacement for

the RFT tool, the MDT tool offers signifi-cant improvements in pressure measure-ment, thanks to its Combinable QuartzGauge (CQG*) and improved samplingcapabilities (figure 3.1).

The collection of condensates andcritical fluids at the sandface, one of themost difficult downhole sampling opera-tions, can be carried out quickly and effi-ciently using the new tool with verysmall pressure drawdowns.

Recently, the MDT tool was used todetermine lateral hydraulic continuity ina Middle East sandstone reservoir. Thetool was run in a horizontal well using

the Tough Logging Conditions (TLC*) sys-tem. Deployed in its basic configuration,the MDT tool generated a pressure pro-file (figure 3.2) which indicated a lowporosity interval between x280 ft andx350 ft, which acted as a flow barrier, andconsequently a significant pressure differ-ential had developed across this interval.

One of the most important improve-ments offered by the new tool is the abil-ity to control a multitude of tool functionsfrom the surface. The MDT tools singleprobe module contains a 20 cc pre-testchamber. However, the size of this cham-ber can be adjusted from the MAXIS-500*(wellsite surface instrumentation) acqui-sition unit.

Electric powermodule

Sample modules

Hydraulic powermodule


Probe moduleProbe module

Samplemodules

Electric powermodule

Multi-sample modules

Pump-outmodule

Optical fluid analysis module

Flow control module

Dual probe module

Dual-packermodule

Fig. 3.1: A MODEL OF MODULARITY: Thestandard MDT with the single probe moduleand multiple sample chambers. The singleprobe module offers a variable pre-testchamber and a new CQG (Combinable QuartzGauge) which provides fast and accurate

pressure measurements. The optional modulesprovide permeability anisotropy, mini DST(drillstem test), sampling and fluididentification capabilities. The tool's modulardesign enables engineers to select the modulesrequired for a particular operation.

This feature allows the engineer toreduce chamber volume for faster testsin tight zones where flow rates are verylow. Another type of surface pre-test is toset the maximum allowable pressuredrop during the test. This prevents gasliberation around the probe in tight for-mations.


4/14

45Number 16, 1996.

Figure 3.3 shows two pre-tests whichwere carried out at the same depth. Thefirst used a pre-test chamber size of 7 ccand achieved stabilized build-up pres-sures in five minutes. The other, whichfilled a 20cc chamber, required 17min-utes to reach formation pressure. Theoption of variable pre-test chamber sizemeans faster surveys and helps the engi-

neer to avoid dry/incomplete tests inlow-permeability zones.

Fluid contacts

The depths at which water is overlainby oil (the oil-water contact) and oil isoverlain by gas (the gas-oil contact) arevery important reservoir parameters.Once we have an accurate picture ofthe reservoirs internal boundaries wecan estimate actual volume of oil andgas in place. This is clearly very impor-tant in the early stages of field develop-ment, when the emphasis is on

identifying overall reservoir extent. Thewell completion methods selected tominimize gas-water coning will dependon the locations of the gas-oil and oil-water contacts.

HYP(ps

ia)

HYP(ps

ia)

RHOB(G/C3)

95

45

2.9

5

-.15

NPHI

2000

4000

x250

x300

x350

x400

x450

x500

x550

Fig. 3.2: SIDEWAYS GLANCE: An MDT tool-derived pressure profile and the density-neutron log recorded in a horizontal well in a Middle East sandstone.The MDT tool was run in this well to verify hydraulic continuity throughout the reservoir. The density-neutron plot shows a relatively low porosityinterval from x280ft to x350 ft. Unfortunately, it is not apparent from these logs whether or not the zone is a permeability barrier. However, the formationpressure measured with the MDT tool gives a clear indication of pressure discontinuity along the well trajectory.

100 200 300 400 500

1100

1102

1104

1106

1108

1110

Time (sec)

Pressure

(ps

i)

7 cc pre-testat x120 ft

100 200 300 400 500

1100

1102

1104

1106

1108

1110

Time (sec)

Pressure

(ps

i)

20 cc pre-testat x120 ft

Fig. 3.3: TIME SAVER:Stabilization times canbe reduced by loweringthe volume withdrawnduring pre-tests. Pre-teststaken at the same depth

show that while a build-up preceded by 7ccdrawdown (a) stabilizesin five minutes, it takes

17 minutes to reachformation pressurewhen withdrawing 20ccduring drawdown (b).

(a)

(b)


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Density-Neutron Pressure (psi) Resistivity

TVD

7200

7100

Water

Oil

Gas

GR

compensated, ensuring an excellentdynamic response. A few minutes can besaved during each test and, when manypre-tests are performed, the minutes addup to hours of rig time.

Sweet success in sour gas

Home Oil and partners recently drilled acarbonate test well in Alberta, Canada.The hydrocarbon target was a gas zonerich in natural gas liquids and highly toxichydrogen sulphide (H2S). The reservoirwas highly dolomitized and contained alot of vugs. This vuggy character meant

that conventional logging could not iden-tify fluid gas contacts precisely, with dis-crepancies between logging runs ofapproximately 9m.

It is vital that the exact contact depthsare known in order to estimate reserves -a particularly important consideration insour gas reservoirs. Reservoirs with ahigh H2S content require special scrub-bing facilities which may be too expen-sive to install on a small field. Anover-estimate of reserves could encour-age development of an uneconomicfield, while an under-estimate mightresult in a missed opportunity.

Fig. 3.4: FLUID FINDER:Formation pressurescan be used to definefluid type at any givendepth within thereservoir and to locatefluid contacts.

Fig. 3.5: GAUGE THE DIFFERENCE: In thisexample the module was equipped with aconventional quartz gauge and the CQG. Thisallowed a direct comparison between the twopressure datasets during each pre-test. Theconventional gauge (a) had not reachedformation pressure after 150 seconds, while theCQG (b) was fully stabilized after just 100seconds.

The excellent resolution and accuracypossible with quartz gauges makes themthe obvious choice for determining thesefluid contacts (figure 3.4). Conventionalquartz gauges, however, require long sta-bilization periods when subjected to sud-den pressure and temperature changes,such as those encountered during thepre-testing of oil and gas wells.

Strain gauges have a better dynamicresponse (i.e. they give a stable readingmuch sooner) than the conventionalquartz gauge. However, they are notaccurate enough for most fluid gradientdeterminations. The CQG offers the

dynamic behaviour of the strain gaugecoupled with the accuracy of a quartzgauge (figure 3.5).

The CQG owes its exceptionaldynamic response to the fact that temper-ature and pressure measurements aremade with a single quartz resonator. Thisbreakthrough was achieved by forcingthe resonator to oscillate simultaneouslyin two different modes (frequencies). Onemode is dominantly pressure-sensitive,while the other is influenced mainly bytemperature. This means that the adia-batic effect introduced by pressure varia-tion is immediately sensed by the

temperature mode and automatically

In this case the operator decidedthat a wireline testing tool was requiredto help identify these key contacts. Itwas expected that the reservoir would

provide very few opportunities forpacker seats. Home Oil decided thatany data which could be gatheredshould be of the highest quality. TheMDT tool was run with two H2S samplechambers, the single probe module andthe Optical Fluid Analyzer (OFA*).

In this case the MDT tool recordeddata which allowed engineers to deter-mine the reservoir fluid contacts andcaptured representative fluid samples.

x474.8

x474.6

x474.4

x474.2

x474.8

30 60 90 120 150 30 60 90 120 150

x474.6

x474.4

x474.2

x474.8

x474.6

x474.4

x474.2

x474.8

x474.6

x474.4

x474.2

Delta time secDelta time sec

Pressures

(Raw

an

dsmoo

the

d)ps

ia

Pressures

(Raw

an

dsmoo

the

d)ps

ia

(a) (b)


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47Number 16, 1996.

One wireline testing technique involvesthe collection of numerous point pressuremeasurements to establish a pressure gra-dient which defines reservoir fluid type.

The restrictions imposed by limited preci-sion in strain gauge measured pressuresand uncertainty related to depth, have, inthe past, confined this technique to thickreservoirs.

A high-precision quartz gauge intro-duced in 1980 allowed gradients to bemeasured in thinner beds, but depthplacement uncertainty and long stabiliza-tion times made this unattractive.

By running fast-response, high-preci-sion quartz gauges, the MDT tool has over-come the stabilization delay inherent inprevious quartz gauges. The tandemassembly (figure 3.6b) removes depth

uncertainty because the separation dis-tance is fixed. Reservoir fluid density canbe determined over 8ft thick intervals oreven 2.3 ft intervals, when conditions arefavourable.

A new technique, which compensatesfor the uncertainty between the pairedgauges by normalization to a downholemeasurement of the mud pressure gradi-ent, allows the operator to double thenumber of pressure points obtained ateach station, offering a major time savingon traditional contact determinationmethods.

Using this method, reservoir fluid den-

sity can be quickly and accurately deter-mined over short intervals (table 1). Thisprovides a direct hydrocarbon determina-tion independent of water resistivity (Rw)invasion or lithological model.

The emergence and refinement of newtechniques indicate that log analysts aredetermined to explore the full potential ofthe MDT tool.

IT TAKES TWO TO TANDEM

Station (ft) Log Pressure derived fluidinterpretation density (g/cc)

A x390 Oil 0.6B x446 Oil 0.4C x452 Oil 0.5D x457 Oil 0.4E x465 Oil 0.6

Oil-water

contact

F x539 Water 0.9G x573 Water 1.0

Table 1: Multiplestations and theinterpretations basedon readings fromquartz gauge andstrain gauge spaced2.3 ft apart.

Pressure (psi)

550

450

Dep

th(ft)

x425

x550

650

x575

x700x700

x825

GAS

OIL

WATER

Fluid density from pressuregradient (g/cc)

0.6

0

1.2

Gas - oil - water

Fluid density from pressure gradient (g/cc)

0.6

Gas

Oil

Water

OIL

0

X450

X575

1.2

WATER

2.3ft

Table 1 - Fluid density determinations

Sour gas exploration/developmentcalls for special evaluation techniques,and in a climate of growing environmen-tal awareness, restrictions on acid gasflaring can severely limit productiontests.

The quality of the MDT tool resultsallowed the operator to cancel an expen-

sive production test. Home Oil consid-ered the quality samples and fluid con-tact determination provided by wirelineformation testing an effective and afford-able alternative to production testing.

The MDT tool can contribute to well-site safety and help to protect the envi-ronment. These issues are particularly

important when production tests on sourgas are to be carried out in populated orenvironmentally sensitive areas.

Fig. 3.6: TANDEMPRESSUREGAUGES: A large number ofsingle probe pressuremeasurements (left) allow thereservoir gradient to beestablished statistically. Thesegradients (or fluid density)indicate the fluid type present.When a quartz gauge and a straingauge are used together (below),with a spacing of just 2.3 ft, thevertical resolution improvessignificantly. These examples areplotted with the same depth scale.Two quartz gauges would havegiven even greater precision.

(a)

(b)


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0

1800

2400

3000

3600

4200

4800

Pressure,p

sig

0

Time (sec)

Pre-test chamber volume: 20.1cc Gauge: BSG1 Res: 0.040psi

Depth: X586.08 ft

Mud Pressure before test = 4762.12 psigMud Pressure after test = 4761.44 psigLast build-up pressure = 3893.20 psigDrawdown mobility = 8.9 md/cp

600 900 1200 1500 1800 2100 2400

Res

istivity,ohmm

0

30

24

18

12

6

Fig. 3.7: PUMP,THROTTLE ANDSAMPLE: After pumping9 litres of mud filtrate inthis well, the flowlineresistivity cell (blackline) shows an increase.The pumpout modulewas stopped and

reservoir fluid directedinto a sample chamber.During sampling, thethrottle valve keepssampling pressurearound 3500 psia (redline). When opened atthe PVT laboratory, thesample chamber wasfound to containhydrocarbon gas and500cc water.

Fig. 3.8: SWEEPINGCLEAN? Two openholelog evaluations usingthe original formationwater and sample waterresistivity. In this MiddleEast example, thepumpout module wasused to displace themud filtrate and samplethe water, whichproved to be a mixtureof formation andinjection water. Logevaluation based onformation waterresistivity suggests poorsweep efficiency. Whenthe actual waterresistivity (measuredusing the MDT tool)was substituted in theequation, a moreaccurate andencouraging result forsweep efficiency wasobtained.

SW for RW = .018(PU)0 100.00

GR0 100

1:500ftSW for RW = .047

(PU)0 100.00

Oil (RW = .047)SW for RW = .047

(PU)

0 100.00

Water

Electronic powermodule


Power module

Sample module

Sample module

Pumpout module

Oil (RW = .018)

Clean sampling at a rangeof depths

One of the main objectives for wirelineformation testers has always been, andwill continue to be, reservoir fluid sam-pling. Conventional tools can collect upto two samples with each run into theborehole. Unfortunately, the quality ofthese samples is often impaired by thepresence of mud filtrate associated withinvasion during drilling.

Conventional wireline testers cannotevaluate the purity of fluid entering thechamber during sampling. The chambershave to be returned to the surface beforethe operator can determine whether ornot the samples are useful.

The MDT tool has overcome these dif-ficulties - up to 12 sample chamber mod-ules can be connected to the tool.However, weight limitations (determined

by well conditions and cable strength)generally restrict the number to six. Themulti-sample module contains a set of sixchambers, each with a 450cc capacity,and so can provide additional fluid sam-ples during a single trip. This flexibilityallows the operator to sample at a vari-ety of depths and produce a profile ofthe reservoirs fluid properties. The sur-face unit can use the resistivity cell onthe probe module, or the Optical FluidAnalysis module, to identify fluids (mudfiltrate, oil, water and gas) before takingsamples. The resistivity cell often has dif-ficulties in identifying fluids when a well

has been drilled in oil-based muds andmay, in some cases, be unable to differ-entiate oil from gas. The optical fluid ana-lyzer has been designed to cope in thesecircumstances, identifying mud filtrate,oil, water and gas quickly and accu-rately.

The final obstacle to the collection ofclean samples is mud filtrate invasioninto the formation. Fortunately, the MDTtool has a solution. Mud filtrate can bedisplaced by the pumpout module, aminiature downhole pump whichpushes unwanted fluids into the bore-hole before sampling begins.

Bubbles and dew

Having eliminated contaminants such asmud filtrate from the sample our atten-tion turns to the sample itself. To obtainthe high-quality samples suitable for PVTwe must avoid phase changes duringsampling.

Throttle valves prevent gas flashingor liquid dropout during sampling. Thesevalves, under the control of the surface


8/14

49Number 16, 1996.

CO C C C i-C n-C i-C n-C C C2 1 2 3 4 4 5 5 6 7+

Sample 1

Sample 2

Sample 3

Sample 4

Component%

0.01

0.1

1

10

100

Component

Fluid flow OilGas

Gas detectorLamp

Liquid detector

Light-emittingdiode

Water

computer, automatically keep the sam-pling pressure above a specified value toensure representative samples, limitingdrawdown during sampling. A key factorin achieving a small drawdown is the for-mation mobility: the best control oversampling drawdown is achieved in highmobility formations.

Another sampling application is the col-lection of pure formation water samples.The tools pumpout capability has pro-vided, for the first time, the means to cap-ture pure water samples in situ.

Pumpout in action

A sample taken from a reservoir in theUnited Arab Emirates provides a clearexample of the effectiveness of thepumpout module. Figure 3.7 shows thepressure at the flowing probe along withthe flowline resistivity curve.

After pre-testing the formation, the

pumpout module is used to pump fluidsfrom the formation into the wellbore.The low resistivity of the fluid indicatesthat mud filtrate is being pumped. Afterpumping approximately 8 litres, a spikedevelops in the flowline resistivitycurve, indicating hydrocarbon flow.

At this stage, the pumpout operationis halted and a sample chamber opened.During sampling, the resistivity curveconfirms a hydrocarbon sample. Thisreal-time fluid identification eliminatesthe uncertainty and time wasted by con-ventional sampling.

Sweeping statementsFormation water resistivity is a vital inputfor open-hole log analysis. Waterfloodsweep efficiency in a Middle East reser-voir was calculated using water resistiv-ity data based on MDT tool samples.Initial estimates of sweep efficiency usingopen-hole logs were hampered by themixed salinity of water in the formation.

A very pessimistic view of sweepeffectiveness was obtained using the ini-tial connate water resistivity value of0.018/m . The MDT to ol wa s se t atx168 ft and, after pre-test, the pumpout

module produced 27 litres of fluid fromthe formation. Once the pumpout opera-tion had been completed, a one-gallon(approximately 3.8litres) sample cham-ber was opened to collect the formationwater sample. The pumpout thenpumped an additional 5.3 litres into thewellbore before a 450cc water samplewas collected in one of the multi-samplemodules bottles. Analysis of the watersamples collected in this way indicated awater resistivity of 0.047/m. Open-holelog analysis using this new value offereda much more accurate (and optimistic)view of the waterflood (figure 3.8).

Fig. 3.10: The OpticalFluid Analyzer has atwo-sensor systemwhich allows it todetect and analyzeliquids and to detectgas. This allows high-quality oil and gas

samples to be divertedinto the samplechambers after mudand mud filtrate havebeen pumped throughthe system.

Fig. 3.9: FOUR OF A KIND: The results of PVT compositional analysis on four samples fromthe same reservoir indicate a strong degree of similarity between the samples.

The multi-sample module has six450 cc chambers. These chambers canbe transported without fluid transfer atthe wellsite. Drawdown during samplingcan be controlled by throttling valvesand water cushions.

If every MDT tool sample consists ofrepresentative reservoir fluids, duplicatesamples from a particular depth shouldshow identical compositions. Four sam-ples, recovered from a reservoir fluid innear critical conditions, are shown in fig-ure 3.9. These samples were obtainedwith a maximum drawdown of just 8 psi,thanks to water cushions, the throttlingvalve and high formation mobility. Thesample chambers are designed to allowtransport of the samples to a PVT labora-tory, without transferring the sample to a

shipping bottle. The compositional analy-sis of the four samples, as well as otherfluid parameters (such as flash gas/liquidratios, bubble point and tank liquid den-sities) show excellent agreement con-firming the validity of the samples. In thepast, a large proportion of testsattempted to sample unsuitable zones.The new MDT tool offers us the chanceto examine the fluid before we collect it.This sample preview capability meansthat the correct fluids will be brought tothe surface for analysis (figure 3.10).


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Perfect permeability

Core permeability measurements havelong been focused on calculating hori-zontal values, with vertical permeabilityvalues often missing or hard to obtain.Good samples for permeability evalua-tion are often made on good core sec-

tions. The worst core sections - the partswhich represent barriers to vertical fluidmovement - have been under-sampledor ignored. Vertical permeability can bedetermined by a single well transienttest, provided that both spherical andradial flow regimes are observed, or byusing a packer to isolate the zones inquestion and conducting a vertical inter-ference test.

Pre-testing with the MDT tools 20 ccchamber gives a value for drawdownmobility for each test. These valuesreflect a combination of horizontal andvertical mobilities, often referred to as

the spherical mobility.The separate vertical and horizontal

components cannot be distinguishedfrom pre-tests and the small amount of

Flow rate, cc/sec

Pressure at thevertical probe,psia

Time(sec)Flow into sink probe

Pressure at the horizontal probe, psia

Fig. 3.11a: STEP ONE: A multiprobe test carriedout by the MDT tool acquires pressure data athorizontal and vertical probes. Flow rate datais either measured directly by the flow controlmodule or calculated from the pumpout orsampling process.

Fig. 3.11b: STEP TWO: The pressure changes,plotted against time at both probes, are used toconstruct a flow regime identification plot. This

involves pressure-pressure deconvolution andproduces a derivative plot similar to thatobtained from a well test. Spherical flow is themost common regime, with a slope of -0.5 onthe derivative curve.

Pr

essure

deriva

tive

Time (sec)

Spherical flowslope = -0.5

Horiz. mobility = 5.46 md/cpVert. mobility = 2.58 md/cpPhi*Ct = 1.42E-06 (1/psi)

1/time (sec)

0.00.250.50.751.01.251.51.752.0

De

lta-pressure

(ps

i)

Spherical AnalysisDeconvolved vert. pressureDeconvolved horiz. pressure

Pressure at vertical probePressure at horizontal probeFlow rate

Fig. 3.11c: STEPTHREE: For sphericalflow, a spherical timefunction plot isgenerated. This isachieved by usingpressure-ratedeconvolution to

obtain first estimatesfor horizontal andvertical mobilities andthe porosity-compressibilityproduct. For an infinitemedium, the maximumpressure change at thevertical probe isinversely proportionalto the horizontalmobility. The arrivaltime of the pressuredisturbance is afunction of verticaldiffusivity.

fluid withdrawn from the formationmeans that the drawdown mobility esti-mate applies to a relatively small areaaround the probe. The danger of sam-pling small areas is that they may beaffected by formation damage close tothe probe, gas breakout in tight forma-

tions, fines migration and probe plugging.


10/14

51Number 16, 1996.

A larger withdrawal and the use ofmore than one probe eliminates most ofthese near-probe effects, allowing us toevaluate important formation propertieson a larger scale. These include horizon-tal and vertical mobility (which is perme-ability divided by viscosity), and theporosity-compressibility product.

Four steps to findingformation properties

Using the dual probe module, the singleprobe module and the flow control mod-ule, repeated vertical interference testscan be performed along the wellbore.The flow control module takes 1 litre offormation fluid into a chamber, displac-ing a piston in the process.

During the test, flow rates are moni-tored (figure 3.11a). Acquired flow rateand pressure data from the observationprobes can be analyzed to yield forma-tion properties. The pressure change atthe probes is used to construct a flowregime identification plot (figure 3.11b).For spherical flow, a spherical time func-tion plot is generated by using pressure-rate deconvolution to estimate thehorizontal and vertical mobilities (figure3.11c). The best match betweenobserved and calculated pressures isobtained by using a model coupled to aparameter estimator (figure 3.11d).

The multiprobe configuration hasbeen used offshore in the Middle East toquantify vertical communication

through calcite and dolomite zones. Theopenhole logs and test locations areshown in figure 3.12. Four tests wereconducted in this well using one single-and one dual-probe module. The flowrate sources were both pumpout andflow control modules. Tests 1 and 3showed no response at the verticalobservation probe which was 2.3 ftabove the active (or sink) probe. Thisindicates that a geological feature is act-ing as a barrier for the duration of thetest.

Fig. 3.11d: STEPFOUR: In an effort toget the best matchbetween observedand calculatedpressures the initialestimates are used ina model coupled to aparameter estimator.

The final match isshown usingpressures at thehorizontal andvertical probes.

Verifications

Reconstructed horizontalPressure at horizontal probeReconstructed verticalPressure at vertical probeFlow rate

0

-15

0

15

30

De

lta-pres

sure

(ps

i)

Flow

rate

(cc

/sec

)45

60

75

-3

0

3

6

9

12

15

40 80 120Delta-time (sec)

160 200 240 280

Horiz. mobility = 5.34md/cpVert. mobility = 2.78md/cpPhi

*Ct = 1.96 E-06 l/psi

BS

Pump out

MUD CAKEFrom CALI to BS

Gamma ray (GR)(GAPI)

Caliper (CALI)(IN)

Bit size (BS)(IN)

Tension(TENS)(LBF) Neutron porosity (NPHI)

(V/V)6.0 16.0 0.0

2000.0

0.45 -0.15

6.0 16.0

PhotoElectric Factor (PEF)(.....)6.0 16.0

Bulk Density Correction (DRHO)(G/C3)6.0 16.0

0.0 100.0Bulk Density (RHOB)

(G/C3)

RHOB-NPHIfrom RHOB to NPHI

0.0 100.0

Test 2

kh/ = 47.1md/cp

kv/ = 18.8 md/cp

c = 1.97 x 10 /psit-6 -1

Test 4

kh/ = 33.0 md/cp

kv/ = 11.0 md/cp

c = 5.00 x 10 /psit

-7 -1

Multiprobe test 2

Multiprobe test 4

Flow control & pump out

Multiprobe test 3, two attempts

Multiprobe test 1, two attempts

Flow control and pump out

Flow control

Fig. 3.12: Thisexample shows theresults of somemultiprobe tests. Inthis carbonatereservoir, theobjective was toquantify verticalcommunicationacross dolomitic andcalcite-rich zones.Test locations aremarked on theopenhole logs.


11/14


Delta-time (sec)

De

lta-pressure

(ps

i)

Flow

rate(cc

/sec

)

0 40 80 120 160 200 240 280 320

6.0

5.0

4.0

3.0

2.0

1.0

0

-1.0-1.5

0.0

1.5

3.0

4.5

6.0

7.5

Verifications

Reconstructed horizontalPressure at horizontal probeReconstructed verticalPressure at vertical probeFlow rate

Horiz. mobility = 33md/cpVert. mobility = 2.78md/cpPhi

*Ct = 5E-07 l/psi

Fig. 3.13: FLOWCONTROL TEST:Rates from the flowcontrol module,observed andsimulated pressureresponses at bothprobes during test 4(see figure 3.12).

Fig. 3.14: FOUR PROBE FASHION: Thisconfiguration, popular in some parts of the

Middle East, is intended to quantify verticalcommunication across thick zones which arebelieved to be flow barriers.

Verticalprobe 2

Verticalprobe 1

Sink probeHorizontalprobe

MoblilityV2 (MD/CP)

0.0 20.0

Formation PressureV2 probe (psia)

2800.0 3000.0

Formation PressureV1 probe (psia)2800.0 3000.0

Moblility,V1 (MD/CP)0.0 20.0

Moblility,Sink probe

0.0 20.0

Moblility, Hor. probe(MD/CP)

0.0 20.0

Formation PressureSink probe (psia)

2800.0 3000.0

Formation PressureHor. probe (psia)

2800.0 3000.0

Fluid %

50 (PU) 0

Porosity and Fluid

Analysis by Volume

Unmoved

Moved

Water

Clay

Dolomite

Limestone

Porosity

Anhydrite

Formation Analysis

by Volume

Matrix %

100 (PU) 0

Multiprobe Test -1Across D2

Multiprobe Test - 2Across D2-A

Multiprobe Test - 3 Multiprobe Test - 4

Across D3x200

Fig. 3.15: The four probeMDT configuration wasused at four locations inthis well. The objectivewas to quantify verticalcommunication acrossstylolitic zones. Stylolitesare thin, irregular rockboundaries whichdevelop in somelimestones (andevaporites). They arecaused by pressure

dissolution and re-deposition of existingsedimentary material.

Tests 2 and 4 produced responses atboth monitor probes. Test 2 used thepumpout module as the flow rate source.

Test 4 was conducted through thesink probe, using the flow control mod-ule. Figure 3.13 shows the flow controlrates and observed and simulated pres-sure responses at the monitor probes.

The results from these tests show thatthe vertical permeability is about onethird of the horizontal permeability. Thisinformation will help reservoir engineersto set up their reservoir simulationmodel.

Sometimes, operating companies needto know the extent of vertical communica-tion across suspected barriers. Thick bar-riers can be accommodated by increasingthe spacing of the multiprobe from 2.3 ft to10.3 ft with the addition of a fourth probe.In this configuration the spacing between


12/14

53Number 16, 1996.

two vertical probes is 8 ft. This arrange-ment (figure 3.14) has not been widelyused in the Middle East.

In this recent test, the configuration

was used onshore, with all three flowrate sources (flow control, pumpout andsample chamber modules). The objec-tive was to identify the barrier propertiesof stylolite horizons in a carbonatesequence. The four tests carried out onthese horizons are presented in figure3.15.

The Fullbore Formation MicroImager(FMI*) images for the zones where test 3and test 4 were carried out are shown infigure 3.16. The probe locations areclearly indicated on these images.

Fig. 3.16: These FMIimages from tests 3and 4 (see figure 3.15)show the type ofheterogeneity whichcannot be fullyidentified usingopenhole logs. Theseimages, taken after the

MDT survey, show theexact position of eachprobe during thesurvey.

In test 3, a 3.5 litre volume waspumped - causing a pressure drop at thefirst vertical probe. The test continuedwith activation of the pumpout module

from the first vertical probe. However,the probe was situated in a tight zoneand the tool was reset for test 4.

The tool was moved 0.6 ft down thewell before the start of test 4. The firstvertical probe was activated, pumping10.5 litres of formation fluids. A pressuredrop of 0.7psi was observed at the sec-ond vertical probe.

x188.0

x190.0

x192.0

x194.0

x196.0

x198.0

x200.0

x125

x150

x175

x200


13/14


Figures 3.17 and 3.18 show therecorded and modelled responses atvertical and sink probes. Results from allof the transients are summarized inTable 2. Note the response seen at thevertical probe, in test 1, which was 10.3ftabove the sink probe.

Mini drillstem testsDefining pressure points for fractured,vuggy, very tight or highly-laminated for-mations has often presented problemsfor wireline formation testers.

The dual packer module availablewith the MDT tool provides a much big-ger flow area - isolating 3 ft of formationbetween two inflatable packers. The areaopen to flow is then three orders of mag-nitude larger than a conventional probe.This allows larger flow rates and lessdrawdown than can be achieved withthe probe.

Tests conducted with the dual packermodule can be thought of as mini drill-stem tests on wireline. The radius ofinvestigation may reach tens of feet in atest completed within a few minutes.

The Dual Packer Module helps toovercome the testing problems encoun-tered in highly fractured reservoirs. FMItool and Ultrasonic Borehole Imager*(UBI) tool images (figure 3.19) wereused to identify a suitable test zonewhich contains a fracture. A log-log plotof pressure and pressure derivative anda generalized superposition plot (figure3.20) show measured data and the simu-

lated pressure response produced bythe Schlumberger ZODIAC* (ZonedDynamic Interpretation Analysis andComputation) well testing package. Thecorrelation between measured and theo-retical data is excellent.

pressure at sink probereconstructed sink

horiz. mobility = 1.4 md/cp

vert. mobility = 1.5 md/cp

phi*Ct = 1.06E-06 1/psi

0

54

48

42

36

30

24

18

12

6

0

200 400 600 800 1000 1200 1400 1600 1800

Delta - time (sec)

De

lta-pressure

(ps

i)

Fig. 3.17: THE VERTICAL MATCH: The response at the vertical probe, 8 ft above the active probe,was matched using a homogeneous model. The reservoir parameters are presented in Table 2.

Fig. 3.18: SINK MATCH: During the pumpout test from the first vertical probe, the sink probe, 2.3 ftbelow, acts as an observation probe. The figure shows the pressure match at the sink probe. Thereservoir properties are presented in Table 2.

Table 2: Summary of reservoir properties

Test kh/, md/cp kv/, md/cp ct, 1/psi

1 (2.3 ft) 11.1 5.20 1.41E-062 (2.3 ft) 5.20 0.70 1.30E-062 (10.3 ft) 12.0 0.30 2.00E-073 (2.3 ft) 1.60 1.90 1.03E-064 (2.3 ft) 1.40 1.50 1.06E-06

4 (8 ft) 21.9 0.15 3.00E-07

0.000

0.070

0.140

0.210

0.280

0.350

0.420

0.490

0.560

0.700

0.630

0 200 400 600 800 1000 1200 1400 1600 1800

Delta - time (sec)

De

lta-pressure

(ps

i)

response at vertical 2reconstructed vertical 2

horiz. mobility = 21.9 md/cp

vert. mobility = 0.153 md/cp

phi*Ct = 3.0E-07 1/psi


14/14

55Number 16, 1996.

Fig. 3.19: Using the UBI (left) and FMI (right)tools, suitable test zones can be selected andtested (essentially a mini drillstem test) usinginflatable packers.

Wellbore storage using the MDT toolis five orders of magnitude smaller thana conventional DST. This allows fullcharacterization of the tested intervalafter only 6 minutes of shut-in. Thesemini DSTs are more efficient than con-ventional DST tests and offer additionaladvantages in relation to environmental

and safety issues.Formation testing has come a long

way in the last 40 years. Sophisticatedpressure measurement and fluidretrieval have become commonplace,but, as always, the quest continues formore information, gathered faster andwith greater accuracy.

Pressure Change

Log-log plot

100

101

102

103

10-4

10-3

10-2

10-1

100

t (hr)

10-4

10-3

10-2

10-1

100

pandderivative(psi)

Pressurederivative

Radial Flow Regime

Superposition Plot

400

300

200

100

0

p(psi)

The next step in the evolutionary pro-cess of formation testing will be deter-mined by the operators. The RFT tool,after all, was designed primarily for fluidsampling, but its pressure measurementcapabilities were generally consideredmore important.

As the MDT tool replaces older sys-

tems, log analysts will find ways toexploit the new technology and will ulti-mately control the way in which thispowerful new system is developed.

Fig. 3.20: This figureshows the log-log plotof pressure andpressure derivativeand a generalizedsuperposition plot forboth measured andsimulated pressureresponse. Note the

excellent matchwhich has beenobtained usingconventional pressuretransient techniques.

a revolution in reservoir characterization

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