26 Oilfield Review

Innovations in Wireline Fluid Sampling

Alastair CrombieBritish Petroleum ExplorationSunbury, England

Frank HalfordAberdeen, Scotland

Mohamed HashemShell Offshore Inc. New Orleans, Louisiana, USA

Robert McNeilE.C. ThomasShell Exploration & Production TechnologyHouston, Texas, USA

Gus MelbourneSugar Land, Texas

Oliver C. MullinsRidgefield, Connecticut, USA

Fluid samples provide the first look at a well’s production,

and operators need to be confident that the few liters of fluid

retrieved from their wells are representative of the reservoir.

New developments in wireline sampling technology are help-

ing to make informed economic decisions.

Good formation fluid samples are of greatimportance to those involved with the task ofproducing a reservoir. A representative sam-ple may often be as useful as results frompetrophysical logs. In recent years, modernwireline formation testers have increasinglybeen used to collect formation fluid samplespreviously obtained only from drillstem(DST) tests or production tests.

In comparison with DST and productiontests, downhole sampling operations are eas-ier to plan, and require less lead time. Otheradvantages are reduced environmental andsafety risks, elimination of surface testingequipment and lower total cost. In addition,wireline formation testers are highly selec-tive, allowing a series of reservoirs to betested during a single trip into the well.Samples can be taken at low drawdown pres-

sure for greater control, ensuring the physicalstate and behavior of the fluid is minimallydisturbed by the sampling process itself.

This article concentrates on state-of-the-artsampling, with descriptions of how recentinnovations have overcome some of the tradi-tional problems of downhole sampling. Wewill look at several ways technology has metsome of the challenges of sampling:• Downhole fluid analysis that improves the

ability to minimize sample contaminationand help determine in-situ oil properties.

• A new sampling technique that reducesthe pressure shock to the formation fluid.

• Fluid-flow modeling studies that led toimproved sampling techniques—shorten-ing sample time while reducing ultimatecontamination levels.

• Sample retrieval to the surface withoutchanging fluid phase.

Autumn 1998 27

Why Sample?Formation fluid sam-ples are needed for a varietyof reasons. Reservoir fluid samples areevaluated in the laboratory to establish theirphysical and chemical properties, such as thehydrocarbon type and the pressure, volumeand temperature (PVT) behavior of the reservesin place. These properties help form the foun-dation for planning efficient field develop-ment. The investment in facilities andprocessing depends on the amount, types andflow characteristics of fluids in the reservoir.

A standard set of measurements per-formed on a fluid sample from an oil reservoirwould include PVT relationships, viscosity,

composition, gas/oil ratio (GOR), differentialvaporization, and a multistage separationtest. Fluid samples also provide the infor-mation needed to help with planning andspecial treatments required for production,such as hydrogen sulfide [H2S] removal,waxing tendencies, asphaltene content,metallurgy and refining trials.

Hydrocarbon composition can vary signifi-cantly within an oil field and must be ade-quately described. Compositional propertiesare important in verifying the saturatedhydrocarbon concentrations that relate to the

For help in preparation of this article, thanks to ChrisBesson, Edo Boek and Andrew Meredith, SchlumbergerCambridge Research, Cambridge, England; GrahamBirkett, Oilphase, Aberdeen, Scotland; Andrew Kurkjian,Schlumberger Oilfield Services, Sugar Land, Texas, USA; Charles W. Morris, Schlumberger Wireline &Testing, Houston, Texas, USA; Rod Siebert, SchlumbergerWireline & Testing, New Orleans, Louisiana, USA;Carsten Slot-Petersen, Statoil Efterforskning ogProduction A/S, Copenhagen, Denmark; and Tony Smits,Schlumberger Wireline & Testing, Fuchinobe, Japan.CMR (Combinable Magnetic Resonance), CQG (Crystal Quartz Gauge), Low Shock Sampling, MDT(Modular Formation Dynamics Tester), and OFA (Optical Fluid Analyzer) are marks of Schlumberger. RCI (Reservoir Characterization Instrument) is a mark of Baker Atlas.

28 Oilfield Review

paraffin that is produced (above). Thesewaxes can cause blockage problems in pro-duction facilities and in cold subseapipelines. Asphaltene precipitation also pro-duces tar-like solids that can come out ofsuspension in crude oil when pressures arereduced within the formation, in productiontubing and in surface facilities. Asphaltenecontent is, therefore, an important parameterin choosing optimal completion designs.

Water samples are critical in establishingfactors fundamental to the production andprocess design. These include scaling,hydrate formation tendencies, compatibilitywith possible injected water, corrosivity,metallurgy of tubulars and design of thewater-handling plant.

Challenges in SamplingThe objective of fluid sampling is to obtain arepresentative sample of the reservoir fluid.The principal operational challenges associ-ated with wireline fluid sampling include:finding the best zones for sampling, con-necting to the formation, obtaining sufficientquantities of acceptably low filtrate contam-inated samples and transporting unalteredfluid samples back to the surface.

Zone selection—Knowing where to makethe connection to the reservoir fluid is criti-cal. Conventional resistivity-density-porositylog and core data help identify potential payzones. Frequently, the operator knows thetarget reservoirs, and other openhole logsmay be helpful in identifying the best zonesin the well for sampling. For example,nuclear magnetic resonance (NMR) logssuch as those from the CMR CombinableMagnetic Resonance tool are particularlyuseful for determining zones that will be pro-ductive (see “Integrated Answers MaximizeSampling Efficiency,” page 34).

Connecting to the reservoir—There are sev-eral commercially available wireline forma-tion tester tools that can take formation fluidsamples. Baker Atlas developed theReservoir Characterization Instrument (RCI),which uses a probe and a dual-pump systemto obtain multiple formation fluid samples.The RCI features a downhole phase pressureestimation to aid fluid sampling.1 This devicetraps a volume of fluid inside the tool, and byexpansion or contraction of the fluid vol-ume, the pressure response is used to assessliquid and gas phase compressibility. Theseare used to evaluate the pressure that willflash the fluid to gas.

The most recent wireline formation testertool developed by Schlumberger is the MDTModular Formation Dynamics Tester tool (nextpage, top).2 This modular tool system consistsof a hydraulic sonde and probe module,pumpout and flow control module, an OFAOptical Fluid Analyzer module and varioussample chamber modules. Liquid componentsare identified using near-infrared spectroscopyand gas is detected with measurement ofpolarized light reflection.3 The basic MDT probemodule contains a variable-rate and volumepretest chamber, flowline fluid resistivity mea-surement, temperature sensor and two pres-sure gauges including a fast, high-precisionCQG Crystal Quartz Gauge instrument thatallows sensitive monitoring of drawdownpressures during the sampling process. Samplefluids and contamination levels are accuratelymonitored in the flowline by the OFA modulewhich will be discussed in more detail later inthis article. The basic tool can be combinedwith one or more sample chamber modulessuch as the Modular Reservoir MultisampleModule (MRMS) that can accommodate six450-cm3 [27-in.3] sample bottles and largersample chambers ranging to 22,700-cm3

[1385 in.3] (next page, bottom).Obtaining PVT-Grade Samples—After con-

nection has been made to the formation, thesampling process involves pumping formationfluid through the tool to the borehole, or flow-ing into chambers carried as part of the tool.The first fluid to flow is mud filtrate from thenear-borehole environment. Depending on anumber of factors, such as the filtrate invasiondepth and time spent pumping, the samplewill contain a mixture of mud filtrate andvirgin formation fluid. Since the objective is toobtain formation samples with sufficientlylow levels of mud filtrate contamination forPVT analysis, the first question is what level offiltrate contamination is acceptable?

100% Oil-base mud filtrateReservoir fluid

1 wt% OBM filtrate10 wt% OBM filtrate40 wt% OBM filtrate

Com

pone

nt fr

actio

n, w

t%

Component

C1

C3

nC4

nC5

Ben

zene

Tolu

ene

Eth

ylbe

nzen

e

C9

C11

C13

C15

C17

C19

C21

C23

C25

C27

C29

C31

C33

C35C2

iC4

iC5

C6

C7

C8

Xyle

nes

C10

C12

C14

C16

C18

C20

C22

C24

C26

C28

C30

C32

C34

C36

0.01

0.10

1

10

100

■■Sample compositional analysis. Weight concentrations are shown on the Y-axis for atypical formation hydrocarbon sample contaminated with varying concentrations of oil-base mud (OBM) filtrate. Each component on the X-axis represents the number of carbon atoms in the principal hydrocarbon type; for example, C3 represents propane[C3H8]. Crude oils obtained from different reservoirs have widely different characteristics.Some are black, heavy and thick like tar, and others are brown or nearly clear with lowviscosity and low specific gravity.

1. Michaels J, Moody M and Shwe T: “Wireline FluidSampling,” paper SPE 30610, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 22-25, 1995.

2. Smits AR, Fincher DV, Nishida K, Mullins OC,Schroeder RJ and Yamate T: “In Situ Optical FluidAnalysis as an Aid to Wireline Formation Sampling,”paper SPE 26496, presented at the 68th SPE AnnualTechnical Conference and Exhibition, Houston,Texas, USA, October 3-6, 1993.

3. For more on the use of the OFA module and gasdetection in the MDT tool: Badry R, Fincher D,Mullins O, Schroeder B and Smits T: “DownholeOptical Analysis of Formation Fluids,” OilfieldReview 6, no. 1 (January 1994): 21-28.

4. Roffy MG: “Preliminary Investigation into the Effectsof Oil Based Mud Contamination on PVT PropertyPrediction,” BP Internal Report, September 1998.

Autumn 1998 29

When fluids are immiscible, contamina-tion should be kept low in order to collect asufficient volume of virgin formation fluid,and to prevent excessive partitioning ofsome of the oil components to either thewater phase or to an emulsion. Nevertheless,in the immiscible case, the fluids are gener-ally separable. Contamination becomesmuch more critical when fluids are miscible.In this case—either crude oil and oil-basemud filtrate or connate water and water-basemud filtrate—contamination must be suffi-ciently low to allow identification of virginfluid properties. Oil-base mud filtrate in acondensate is extremely difficult, becausethe small amount of liquid that drops out ofgas mixes with the filtrate to make a highlycontaminated liquid.

These are areas of continuing research.Recently BP Exploration in Sunbury, Englandconcluded an initial study of the effects ofoil-base mud filtrate contamination on thepredictive ability of PVT analysis.4 With asingle stock-tank oil recombined withmethane at a known GOR, samples weremixed with various levels of an oil-base mudsimulating contamination levels from 1% to40% by weight. A basic suite of PVT experi-ments, as mentioned above, were performedon each mixture. Equations-of-state weredeveloped from the PVT data. These equa-tions were then used to estimate uncontami-nated fluid sample properties, and theseresults were compared to known propertiesof the original uncontaminated fluids.

The comparisons show that for the crudeoils and the mud used in this study, the abil-ity to predict GOR and saturation pressure towithin 5% required mud filtrate contamina-tion to be less than 20% by weight. The levelof filtrate that is tolerable depends on thePVT precision requirements of the end-usersuch as the reservoir engineer, and also thenature of the reservoir fluid itself.

It is thought that volatile oils and conden-sate gases require a much lower level of con-tamination if the sample is to be of use.Recently several projects have been initiated,in Norway, the UK and the USA to learnmore about the effects of oil-base mudcontamination on predicting hydrocarbonproperties. One such project is being con-ducted at Heriot-Watt University, Edinburgh,Scotland. Understanding the limitations ofcollecting openhole samples from wellsdrilled with oil-base mud is essential.

■■The MDT Modular Formation Dynamics Tester tool in single-probe mode.A retractable, hydraulically operated probe embedded in a circular rubberpacker is forced through the mudcake to make a seal with the formation.Two opposing backup pistons on the opposite side of the tool help push theprobe against the formation and maintain a good seal. Keeping the toolbody centered in the borehole minimizes the risk of differential sticking.

■■Modular Reservoir Multisample Module. The multi-sample module is a singlecarrier with six 450-cm3 sample bottles connected to a common flowline andis run as part of the MDT toolstring for PVT sampling. The sample bottles arecontrolled from the surface and can be filled individually at different depthsand times, providing multiple discrete fluid samples for PVT analysis.

30 Oilfield Review

Sample deployment—Bringing samples tothe surface while maintaining their initialreservoir properties is a major concern. Asfluid enters the tool, care must be exercisedto maintain a low drawdown. This will pre-vent the sampling pressure from droppingbelow the formation fluid bubblepoint ordewpoint. If solids precipitate in the samplechamber or the fluid outgasses on its way tothe surface, then the sample transfer mayyield fluids that will not accurately representthose in the reservoir. The subsequent processof transferring samples from downholesample chambers to transportation containerscan lead to gas components escaping to theatmosphere or solids being left in the down-hole sample chamber.

Experience has shown that once samplefluids undergo phase changes while beingbrought to the surface, it can be difficult torecombine the separated components backtogether. For example, asphaltene precip-itation will lead to solids that stick to thechamber walls. Also, if leakage occurs fromthe multiphase fluid, the overall compo-sition changes. However, pumping atdownhole hydrostatic or low differentialpressures into special pressurized samplechambers helps maintain reservoir fluids intheir original state. See page 40 for a discus-sion of a special single-phase chamber thatcan pressurize the sample as it is brought tothe surface to retrieve monophase samplesfor PVT analysis.

Optical Fluid Analysis—The Key to Sample QualityThe OFA module provides the flowline fluidmeasurements needed to distinguish samplecontamination in a wide range of complexenvironments. This module uses a combina-tion of visible and near-infrared absorptionspectrometry to record the intensity of lighttransmitted through the MDT tool flowlinefluid at various wavelengths (left).

Light from a high-temperature tungstenhalogen lamp passes through a rugged sap-phire window into the flowline of the MDTtool. After the light passes through the fluidsample, it exits through another sapphirewindow into ten optical filters that split thetransmitted light into narrow-wavelengthbands over a broad spectral range from about475 nanometers (nm) at the ultraviolet edgeof the visible spectrum to over 2000 nm inthe near-infrared portion of the light spec-trum. This is the heart of the spectrometer.

Photodiode detectors attached to eachfilter measure for each band the reduction in light intensity due to the fluid flowing inthe flowline. The observed light transmissionis controlled by the amount of light bothscattered and absorbed in the fluid sample.In the spectrometer measurement, the trans-mission is characterized by the opticaldensity of the fluid.

The reduction in light transmission scalesexponentially with the optical density of thefluid. Therefore, an optical density of zeromeans no loss in light transmission intensity,and an optical density of 2 means a hun-dredfold loss in light intensity. The range oftransmission in the OFA measurement isscaled from 0 to 3, which means the ana-lyzer is sensitive to a 1000-fold reduction inlight transmission.

Gas evolution during sampling must beavoided, which means sampling pressuresshould be above bubblepoint pressure.5 TheOFA module has a gas detector, whichchecks for the presence of gas in real time in the MDT tool flowstream. Samplingconditions, particularly pressures, can bedetermined for which no gas evolves in thecrude oil, which allows a representativesample to be collected.

Fluid flow

Gas

Gas detector

Lamp

Liquid detector

Light-emitting diode

Water

Comments

Colorchannels

Water,oil

channels

Optical density

Inflate packer

Packerpretest

Startpumpout

Pumpingfiltrate

Pumping oil

Stoppumping

Start sample

Throttling

Changethrottle

Seal sample

Oil

■■OFA spectrometer and gas detector. Asformation fluid flows through the flowlinein the gas detector, a polarized lightbeam focused on a sapphire window in the flowline reflects into an array ofphotodiodes that detect whether gas orliquid is flowing past the window. In the liquid analyzer, a light beam passesthrough the flowline measuring fluidabsorption with filters sensitive to radia-tion in ten wavelength bands from ultra-violet through near infrared. The outputof each filter is plotted as an opticaldensity in the OFA log as the samplefluid is pumped through the analyzer.

Autumn 1998 31

Optical Properties of Wellbore FluidsThe transmission of light through the fluidsample results from the combined effect oftwo distinct processes—scattering andabsorption. Both of these processes affectlight transmission and the optical densitymeasurement, and can depend on the wave-length of the light.

Absorption—Absorption is a process inwhich photons disappear while inducingspecific molecular excitations in the samplefluid. Crude oil can absorb light of particularwavelengths through both vibrational andelectronic excitation.6 The absorption spec-trum of crude oil exhibits a series of absorp-tion peaks with diminishing intensity atshorter wavelengths (right).

The largest oil peak that can be seen in theOFA spectrometer is at 1725 nm. This peakcorresponds to exciting molecular vibrationsinvolving hydrogen-carbon bonds. Suchvibrational peaks—located at discrete wave-lengths, or energies—are analogous to theresonant frequencies exhibited by mechani-cal springs or tuning forks. Since the hydrogen-carbon chemical groups of all oils andasphaltenes are similar, these vibrationalpeaks are comparable for most oils.Materials that are black, such as tar, absorbthe entire spectrum of visible light throughmany different molecular vibrational andelectronic excitations. In these cases, theabsorbed energy is converted into heat.

Water exhibits strong vibrational absorp-tion peaks observed in the spectrometer at1445 and 1930 nm. Therefore, just as anastronomer can tell what elements exist inthe upper atmospheres of shining stars bythe existence of absorption lines in theircontinuous spectra, oil and water can bereadily differentiated by virtue of their dif-ferent absorption peaks. Thus careful analy-sis of the relative contributions in thenear-infrared spectral channels helps deter-mine the oil and water fractions in the MDTflowline (right).

5. The bubblepoint of a system is the state characterizedby the equilibrium coexistence of a substantialamount of liquid phase and a small amount of gas.

6. Mullins OC, Mitra-Kirtley S and Zhu Y: “TheElectronic Absorption Edge of Petroleum,” AppliedSpectroscopy 46, no. 9 (1992): 1405-1411.

Opt

ical

den

sity

Channel number

Wavelength, nm

1 2 3 4 5 6 7 8 9

Crude ACrude B

Water

500 1000 1500 2000

00

1

2

3

4

Oil-basemud filtrate

Diesel

Condensate

■■Laboratory oil and water optical spectra. Water contains two significant absorptionpeaks seen in the OFA spectrometer at 1445 and 1930 nm. Oil contains a strong absorption peak at 1725 nm. Variations in the aromatic molecular components in different oils lead to differences in color—caused by increasing absorption at shorterwavelengths—that differentiate one oil from another.

Oil cut from flowmeters

Oil

fract

ion

from

OFA

spe

ctro

met

er

Low flow rate(150 cm3/min)

High flow rate(700 cm3/min)

1

0

0.2

0.4

0.6

0.8

0 0.2 0.4 0.6 0.8 1

■■Verifying OFA module oil-cut measurements. The relative contributions of water and oil absorption to the OFA near-infrared spectrum are used to determine the relative volumes of water and oil in the flowline. Laboratory measurements on fresh water andlight hydrocarbon (kerosene) demonstrate the OFA module oil cut (oil volume flow ratedivided by total flow rate) calibration, with good agreement—within 10%—at low flowrates, and slightly larger errors at higher flow rates.

32 Oilfield Review

Scattering—Scattering is a nonabsorbingprocess in which a beam of light, or pho-tons, interact with particles and moleculesin the fluid and are deflected from thebeam, thereby reducing optical transmis-sion. The extent of scattering depends onthe size of the scattering particles relative tothe wavelength of light.

When particles are large compared to thelight wavelength—but still can be very smallto the eye—the light is simply reflected fromthe particle surface. For instance, white paintis an excellent scatterer of light and isopaque to light transmission. In this case,scattering intensity is not dependent on theparticular wavelength or color. Sand and

other particulate material in the flowline cancause scattering. With sufficient numbers ofscattering surfaces, no transmission of lightcan take place in the OFA flowline.

If the particles are small compared to the wavelength of light, then the intensity of scattering increases with decreasingwavelength. This process is known asRayleigh scattering, and it explains why thesky, diluted skim milk or cigarette smokeappear blue. For example, mud solids—which originate from clay particles rangingfrom less than 400 nm to 4000 nm in size—are excellent scatterers of light over theentire range of the spectrometer (left).

Fluid Analysis for Reliable SamplingIn formations where invasion is deep, a largevolume of mud filtrate may have to beremoved before sufficiently uncontaminatedformation fluid is pumped into the samplingtool. For example, the pumpout module inthe MDT tool has a powerful pump that candischarge the contents of the flowline fluidinto the wellbore against a differentialpressure of several thousand psi. Afteridentifying a zone with high productionpotential from which a sample is to be recov-ered, the pump is operated until the opticalspectrometer measurements indicate that themud filtrate contamination level has stabi-lized at a low value. At that time, the flow-line fluid is routed to the sample chamber.The OFA module provides an accurate andreliable distinction between gas and liquid,oil and water, and crude oil and oil-basemud filtrate.

An example from the Daqing field of theSongliao basin in China shows how carefulmonitoring helped the operator obtain goodformation fluid samples in the presence of deep water-base mud filtrate invasion(next page, right).7 The test started with a nor-mal pumping rate, but during the first 10minutes, the pump-out was stopped andstarted several times because the MDT toolautomatically sensed—from fluctuatinghydraulic pressure—that the probe seal wasfailing under the differential pumping pres-sure in an unconsolidated formation. Duringthe first part of this test, some mud contami-nation entered the flowline (red on the OFAlog, track 2) followed by mostly mud filtrate(blue on the OFA log). At 270 sec into thetest, the tool probe seal had a massive failureand mud entered the flowline. Observationof these seal failures with the OFA logprompted the engineer to restart the test witha reduced pump rate, helping achieve asmooth mud filtrate cleanup profile.

–13

–12

–11

–10

2

3

10

10

10

10

7

6

5

4

3

2

10

10

10

10

10

10

10

1

–1

–2

–3

–4

–5

–6

–7

–8

–9

10

10

10

10

10

10

10

10

10

10

10

10

1

Wavelength, m

Energy perphoton, eV

Objects of sizecomparable towavelengthCosmic

rays

X-rays

rays

Ultraviolet

Visiblelight

Radar bands

Infrared

UHF

VHF

HF

MF

LF

TVTVFM TV

RADIO

Water and hydrocarbon molecules

Sands

Gravel

Boulders

Rigs

Wells

10

10

10

10

10

10

10

10

10

ShortwaveStandardbroadcastradio

Silts

Clays

–9

–8

–7

–6

–5

–4

–3

–2

–1

■■Range of wavelengths. Visible light is only a small part of the electromagnetic spec-trum which covers the range of wavelengths from the subatomic dimensions of gammarays to beyond those of radio waves—approaching the length of many boreholes. Thewavelength, or corresponding energy, of the electromagnetic radiation determines howit interacts with matter, and dictates the most efficient means for detecting the radiation.

Autumn 1998 33

After 24 minutes of sample pumping, theflowline oil concentration stabilized. Thewater fraction in the flowline, shown in track 2, indicates a high water cut. A forma-tion fluid sample was taken and confirmedthe high 30% water cut. The fluid colorationis computed from the absorption in the visi-ble and near-infrared channels and is shownin track 3. Coloration decreased and resistiv-ity increased, shown in track 4, throughoutsample cleanup. Thus, ability to monitormud and filtrate contamination levels in theflowline before taking the sample allowedthe operator to get the most representativesample possible.

Crude ColorIn addition to the strong vibrational absorp-tion peaks in the near-infrared spectra, manycrude oils exhibit a continuous monotonicincrease in their absorption at shorter wave-lengths caused by the many overlappingexcitations from the large range of differentlight-absorbing aromatic molecules.8 Thelargest of these molecules absorbs thelongest wavelength light, but the continuousabsorption spectra tails off toward zero atlonger wavelengths because the number oflarger molecules decreases with increasingsize in crude oils (see “Origin of Colorationin Crude Oils,” page 36).

This continuous tail in the optical densityextends across the spectrum from the near-infrared through the visible spectrum and oninto the ultraviolet. For this reason, theabsorption tail in the spectrum is used toderive an index of coloration. Strictly speak-ing, the observed color of most substances isdue to both wavelength-dependent scatter-ing and electronic excitations in the mate-rial. Most crude oils possess significantcoloration (below).

7. Olesen JR: “Enhancing Hydrocarbon Recovery withNew Oilfield Technologies,” in China 1997 WellEvaluation Conference, Beijing, PRC: PetroleumIndustry Press, 1997.

8. Aromatic molecules are so named because of theirstrong odor.

Oil

Water

Highabsorbing

fluid

Fluid coloration

0.0001 0.01

0.000001 0.0001

Flowline resistivity

ohm-m0 1

Elapsedtime,

s

1755171016651620157515301485144013951350130512801215117011251080103599094590085581076572067563058554049545040536031527022518013590450

■■Daqing, China example. During the first ten minutes (elapsed time shown in track 1,starting at the bottom) of sample pumpdown in a formation with water-base mud filtrateinvasion, several seal failures were indicated by the high absorbing-fluid index (track 2).After mud started to enter the flowline at 270 s, the pump rate was reduced—leading toa more consistent sample pumping and decreasing filtrate concentration shown by thesteady reduction in water holdup (track 2), coloration (track 3) and increasing flowlineresistivity (track 4). The formation sample was taken after the water holdup in the flow-line stabilized at 1440 s.

■■Crude oil colors. Some crude oils areblack as coal, while others may be thecolor of coffee or tea, and still othersnearly colorless.

34 Oilfield Review

Wellsite efficiency is substantially increased

when MDT sampling depths are guided by CMR

results. The in-situ dynamic MDT measurements

complement the CMR continuous permeability

log, and help confirm the presence of producible

hydrocarbons. CMR and MDT data were acquired

for Statoil in a well in the North Sea.1 The reser-

voir has low-resistivity pay zones, and the 35

p.u., well-sorted, fine to very fine-grained sands,

contain iron-rich glauconite and chlorite clay

minerals (right). The microporous glauconite

reduces the reservoir’s effective porosity. The

CMR tool was used to help identify mobile oil,

and to quantify irreducible water saturation,

effective porosity and bound fluid volume.2 Core

permeability results available at the wellsite

suggested that the large high-porosity zone from

X102 to X120 m should be tested.

However, poor free-fluid signals, missing poros-

ity and short relaxation decay times seen in the

CMR log identified this and several other smaller

zones as unproductive tar zones. Without the CMR

results, core results would have prompted multiple

sample attempts throughout the tar zones. The cores

have been cleaned with a solvent that removed all

traces of the tar, changing their effective perme-

ability. With the CMR logs, good MDT samples

were obtained, enabling the operator to pinpoint a

gas zone at X102.8 m and oil at X104.2 m, just

above the thick tar zone, and to verify formation

water in a thin sand bed at X130.7 m.

The impact of the CMR data in this well was

twofold. First, it provided a better reservoir

description—identifying tar and gas zones as well

as irreducible water and free-water production.

Second, and more importantly, it helped guide

real-time operations with respect to formation

sampling—helping to identify sampling depths

and confirming the anomalous tar zone. Without

the extra information, a costly DST test would

have been likely.

Five-level averagingon CMR data

T2 distribution

T2 log meanms

T2 cutoffms0.3 3000

Density porosity

Core porosity, p.u.

CMR-FFI, p.u.

CMR 3-ms porosity, p.u.

TCMR porosity, p.u. 040

Inductionohm-m

Clean corepermeability, md

CMR Timur/Coatespermeability, md

0.1 1000

0.1 1000

Density porosity

Neutron porosity

45 p.u. -15

Borehole

6 in. 16GR

0 API 150

X100

X125

X150

Tarzones

A

B

C

Depth, m

■■CMR-MDT tool combination. The CMR tool was used to streamline MDT tool operations by identifying thebest zones to sample in a North Sea well. Missing porosity (black curve) and low levels of free fluid (solid redcurve) in track 4 and very short T2 decay times in track 5 are NMR signatures of tar seen between X105 andX111 m and at X113, X115 and X118 m. Good formation fluid samples were obtained at A (gas), B (oil) andC (water).

Integrated Answers Maximize Sampling Efficiency

1. Slot-Petersen C, Eidesmo T, White J and Rueslatten HG:“NMR Formation Evaluation Applications in a ComplexLow-Resistivity Hydrocarbon Reservoir,” paper TT, pre-sented at the SPWLA 39th Annual Logging Symposium,Keystone, Colorado, USA, May 26-29, 1998.

2. Allen D, Crary S, Freedman B, Andreani M, Klopf W, BadryR, Flaum C, Kenyon B, Kleinberg R, Gossenberg P,Horkowitz J, Logan D, Singer J and White J: “How to UseBorehole Nuclear Magnetic Resonance,” Oilfield Review 9,no. 2 (Summer 1997): 34-57.

Autumn 1998 35

Sampling with Oil-Base Muds—Reading the RainbowsA key objective of the OFA measurement isto distinguish between oil-base mud filtrateand crude oil. Achieving this objective is notas straightforward as differentiating oil andwater, where one can rely on the readily dis-tinguishable absorption peaks. Oil-base mudfiltrate and crude oil have the same basefluid, saturated alkanes. Even though syn-thetic oil-base mud may contain other chem-ical groups not found in crude oils, such asesters, they are predominantly alkane. Thesecompounds exhibit near-infrared vibrationalabsorption peaks similar to those of purealkanes. Thus, as far as using near-infraredspectral analysis is concerned, synthetic oil-base mud filtrates have the same or a similarsignature. On some occasions, crude oils areused as the base fluid exacerbating difficul-ties associated with differentiation.

Nevertheless, an obvious distinctionbecomes apparent when looking at the colorsof different crude oils and oil-base mud fil-trates. In fact, crude oil coloration extends intothe near-infrared beyond the visible range ofthe eye; the crude oil coloration in the visibleand near-infrared exhibits huge variation andis readily measured. The color of crude oilsand, to a large extent, filtrates can be charac-terized by a single parameter—coloration—that varies over many orders of magnitude.9

The electronics in the OFA module aredesigned to measure accurately slight varia-tions in coloration by using detection cir-cuitry with a high signal-to-noise ratio. Thispermits sensitive optical absorption mea-surements to be made over a wide dynamicrange. In addition, several of the spectrome-ter channels are devoted specifically to mea-surement of color, and the wavelengthlocation of these channels is optimized toenhance the color measurement. Thus, high-precision measurement of coloration duringsampling can be used to monitor the transi-tion in the MDT tool flow stream from oil-base mud filtrate to crude oil.

During sampling in a well drilled with oil-base mud, the initial flow of fluid from theformation is dominated by the filtrate, so thefirst coloration recorded is largely the color ofthe filtrate. Over time, the fraction of crude oilin the flow increases, while the filtrate dimin-ishes as the flow cleans up. The misciblemixture of crude oil and oil-base mud filtratecoloration simply reflects the correspondingfluid fractions. Thus, coloration provides acontinuous measure of cleanup.

Frequently, the initial flow in the MDTflowline exhibits rather large changes in col-oration, indicating that the fraction of filtratedecreases significantly at first. Following this,the coloration usually exhibits asymptoticbehavior over long periods. The verticalscale on individual color channels can beexpanded to assist in monitoring the asymp-totic behavior. To obtain contaminationlevels at the few-percent level, correspond-ingly small variations in coloration aredesired.10 When the coloration change withtime is sufficiently small, sampling is per-formed. With this method, sample contami-nation levels below 10% are consistentlyobtained in oil fields around the world.

Flow-Stream AnalysisIn typical cases, the method of samplingusing optical density and coloration takesplace as described above. In a well drilledwith synthetic oil-base mud, the OFA mea-surements show that base oil filtrate and other contaminants decrease rapidly asthey are pumped through the MDT tool(above). In this field example, the MDT flowstream was monitored with the OFA spec-trometer, and the responses in channels 3 to7 evolve showing crude oil as the flowcleans up. The OFA log suggests that afterabout 30 minutes of pumping, little filtratecontamination is present and colorationchannels indicate that a medium-gravityhydrocarbon sample is flowing through thetool. In this well, the optical density readingsin all channels have stabilized after 40 min-utes, indicating that additional pumping

would not significantly reduce contam-ination further. A formation sample wascollected at this time. After being pumpedinto a sample chamber held at wellborehydrostatic pressure, the sample fluid stayedsingle phase. Laboratory analysis of therecovered sample confirmed low syntheticoil-base mud contamination—less than 15%.

In some cases, different behavior isobserved related to the optical scatteringprocess discussed earlier. For particle sizesthat are large compared to the wavelength oflight, the scattering is independent of wave-length. For example, when the MDT loggingtool is lowered into the well, the flowline fillswith mud. The OFA module records themaximum optical density on all channels.No light gets through the sample because oflight scattering by the mud solids. After themud in the flowline is flushed, filtrate andformation fluids are obtained which gener-ally do not have suspended solids, so thescattering diminishes to zero.

9. Mullins OC: “Method of Distinguishing BetweenCrude Oils,” US Patent No. 5,266,800 (November30, 1993).

10. Hashem MN, Thomas EC, McNeil RI and MullinsOC: “Determination of Producible HydrocarbonType and Oil Quality in Wells Drilled with SyntheticOil-Based Muds,” paper SPE 39093, presented at theSPE Annual Technical Conference and Exhibition,San Antonio, Texas, USA, October 5-8, 1997.Felling MM and Morris CW: “Characterization of In-Situ Fluid Responses Using Optical Fluid Analysis,”paper SPE 38649, presented at the SPE AnnualTechnical Conference and Exhibition, San Antonio,Texas, October 5-8, 1997.

Opt

ical

den

sity

Elapsed time, min

Channel 3

Channel 4

Channel 5

Channel 7

0 10 20 30 40 50 60

0

0.2

0.4

0.6

0.8

■■Oil-base mud field example. Optical density curves from several OFA spectrometerchannels are plotted as a function of pumping time. Initially mud is in the flowline, and the responses in all channels show a high optical density. Immediately after flowcommences, mud is flushed from the flowline and the optical density seen in all channels decreases. The optical density spikes are associated with the pump strokesreleasing mud solids trapped in the MDT tool flowline. At long times, the change in coloration seen in channel 3 is very slight, and the flow is approaching pure crude oil.

36 Oilfield Review

In some examples, large optical densityspikes occur after filtrate flow starts. Thesespikes are associated with MDT pumpstrokes that occur when flow is disrupted. Bycareful analysis of MDT pressure pulses andoptical density spikes, along with flow rates,the spikes have been traced to dislodgedmud and pieces of mudcake within the flow-line. As expected, the spikes diminish inamplitude with time. The effect of thesescatterers on OFA logs produces a clear-cutsignature—large optical densities arerecorded on all channels.

In certain other cases, optical density logsobtained in the Gulf of Mexico by Shell Oilshow that oil-base mud filtrate extractedfrom the formation exhibits optical scatteringat all wavelengths. That is, when filtrate ispresent in the flowline, there is a large scat-tering signal in every channel (next page,left). By analyzing many logs and the con-tents of sample bottles, it was discovered thatthis scattering essentially labels or “tags” thefiltrate. When significant scattering is presentin the extracted sample, filtrate contamina-tion is high; when little scattering is present,contamination is low. This scattering isthought to result from fine mud solids invad-ing with the filtrate and is prevalent for casesof high-permeability formations and thosedrilled with high overbalance (up to 5000 psi[34 MPa]). The scattering, which labels theoil-base mud filtrate, is quite different fromthe previously observed optical densityspikes. In those cases, the filtrate had no mudsolids or scattering particles, and the filtratecoloration was measurable.

Thus, there are two sources of scattering:optical density spikes from mud within theflowline that gets dislodged with flow disrup-tion, and from mud solids which invade withthe filtrate and appear continuously in time inproportion to the filtrate concentration. Thescattering produced by the solids in the filtratecan preclude measurement of filtrate color.Nevertheless, the same coloration methodcan be used to detect the presence of filtrateand measure the evolution toward uncontam-inated crude oil. As shown in the Shell exam-ple, the optical density produced by thescattering diminishes asymptotically.

The asymptotic behavior is virtually identi-cal to that of the coloration and can be mon-itored in the same way to decide when tosample. One can select a color channelwhere oil shows low optical absorbancy(often reservoirs are known to produce lightoils with little or no coloration at longerwavelengths) to quantify the contaminationlevel. The maximum logged optical densityin this channel at an early time in the draw-down is defined as corresponding to 100%

Most crude oils have no significant electronic

absorption peaks in their visible spectra. Instead,

their coloration is characterized by a continuously

increasing absorption at shorter wavelengths which

extends into the ultraviolet range. For the purpose

of understanding this source of coloration, crude oil

can be considered to consist of aromatic hydrocar-

bons and saturated hydrocarbons.1

Aromatic compounds, an important component

of crude oil, consist of molecular rings with alter-

nating double and single carbon-carbon bonds.

Electrons are free to roam in these molecules,

and the electron wavelengths are commensurate

with the size of the molecule.2 Thus, the size

of the molecules impacts the range of optical

absorption wavelengths seen in fluids containing

these compounds. The smallest common aromatic

molecule is benzene, which is colorless, and the

largest commonly known aromatic is graphite.

While not found in crude oil, graphite illustrates

that large aromatics possess strong absorption

across the entire visible spectrum from ultraviolet

to infrared wavelengths—leading to its character-

istic black color.

Asphaltenes along with other aromatic com-

pounds found in crude oils contain moderately

large polycyclic aromatic ring systems—with an

average of seven rings in a molecule—yielding

significant light absorption in the visible and near-

infrared spectrum. This produces the characteris-

tic dark coloration of heavy, low API gravity crude

oil.3 Resins, the next heaviest component of crude

oil, also absorb in the visible spectrum. The con-

centration of asphaltenes and resins varies con-

siderably, producing the wide range of coloration

in crude oils. These are the highest density com-

ponents and, as such, high-density crude oils rich

in asphaltenes are quite dark. Correspondingly,

light oils lacking heavy components are lightly

colored. The correlation of coloration with API

gravity is approximate because other components

(such as waxes) can affect crude oil density but

not coloration.

In saturated hydrocarbons, the term saturated

refers to the molecule being saturated with chemi-

cally bound hydrogen. Thus, there are no double

bonds in this dominant class of hydrocarbons.

Saturated hydrocarbons are colorless because

they consist of C-H bonds and single C-C bonds;

the electrons in these bonds can be excited only

by absorption of very high energy, far ultraviolet

light, but not by lower energy visible or near-

infrared light. Examples include the smallest

saturated alkane, methane. Even large saturated

hydrocarbons such as waxes are colorless (or

white if they are large enough to scatter light)

if obtained in their pure state. Thus, saturated

hydrocarbons have no bearing on the observed

coloration of crude oils except to dilute the col-

ored aromatic components.

Thus, coloration results from the broad contin-

uum of electronic excitations in the aromatic com-

ponent of crude oils. Crude oils and oil-base muds

have widely ranging concentrations of aromatic

molecules, and the change in coloration with time

during sampling is the basis for distinguishing

between an OBM filtrate and a crude oil sampled

with the MDT tool.

Origin of Coloration in Crude Oils

1. The aromatics molecules are ring structures, whereas thesaturates are typically long molecular chains. In crude oils,molecular weights of the largest components of the aro-matics and of the saturates can reach 1000 atomic massunits. The structure of asphaltenes, the largest aromaticsin crude oil, is an area of active research.

2. The motion of an electron bound in an atom can bedescribed as a wave whose wavelength is related to itsmomentum. In 1924, the French physicist Louis deBroglie proposed the idea that matter behaves like waves.

3. Mullins OC and Sheu EY (eds): Structures and Dynamicsof Asphaltenes. New York, New York, USA: Plenum Press(in press).

Autumn 1998 37

filtrate. With this assumption, the relativereading in this channel itself records the rel-ative level of contamination. When it isreduced to 10% of the original value, thecontamination is considered to be 10%.

Determining Oil Properties in SituShell Oil Company recognized that col-oration can be used to characterize oil prop-erties such as GOR and API gravity.11 Theseare important new applications for opticalfluid analysis, and use of spectral informa-tion to determine compositional and phaseproperties of the formation hydrocarbons isan area of continuing active research.

GOR—By measuring differences in colortransmission in the lowest four optical spec-trometer channels, a hydrocarbon opticalproperty index was derived. This indexshows an excellent correlation with GOR(top right).

This correlation was used to evaluate sam-ples from a number of formations in the Gulfof Mexico. Laboratory PVT analysis of thesamples agrees with the field results and val-idates the technique. A high GOR means alarge gas fraction, which indicates that the

Elapsed time, s

Opt

ical

den

sity

Channel 2Channel 3Channel 4

Channel 5Channel 6

300 400 500 600 700 800 900 1000 11000

0.5

1.0

1.5

2.0

2.5

3.0

■■Oil-base mud example with fines scat-tering. Optical density curves from theOFA channels are plotted as a function of pumping time in a Shell well drilledwith oil-base mud. The mud filtratecauses scattering—increasing the opticaldensity. In addition, spikes occur frommud dislodged from within the MDT flowline with pump strokes.

1

10,000

100010 100

HOP index

GO

R, s

cf /S

TB

GOR = 812e0.114 (HOP)

■■In-situ GORfrom OFA analy-sis. An empiricalcorrelationbetween the OFA-derivedhydrocarbonoptical property(HOP) index andknown gas/oilratios (GOR) wasused to estimatethe GOR in anumber of off-shore wells in theGulf of Mexico.

1

40

35

30

2510 100

COP index

Oil

grav

ity, °

AP

I

API = 24e0.028 (COP)

■■In-situ API fromOFA analysis. A correlationbetween the OFA-derived crude oil opticalproperty (COP)index and knownstock tank APIgravity was usedto estimate duringsampling the APIgravity of the cor-responding stocktank oil in a number of off-shore wells in theGulf of Mexico.

11. Hashem et al, reference 10.

crude oil is low in high-carbon-numbercomponents such as asphaltenes, thus mak-ing the oil more transparent in the visiblechannels. Methane also acts to dilute thecolor of the oil.

API gravity—A similar empirical approachwas used to determine in-situ API gravity. Bycomparing the fluid absorption response inthe visible wavelength channels with theresponse in the longer near-infrared wave-length channels—associated with oil—acrude oil property index was obtained. Thisindex shows a remarkable correlation withdecreasing API gravity of the stock tank oil(above). As the crude oil API gravitydecreases, heavy components such as denseasphaltene fractions increase, leading to anincrease in absorption at shorter wavelengthsand a subsequent decrease in the color-based crude oil property index.

Log-derived values of API gravity and GORare extremely useful. They can be used asearly indicators in the planning cycle,whereas more exact PVT data will be deter-mined in the laboratory after samples havebeen brought to the surface. In-situ oil prop-erties are important because they reflect thetrue nature of the downhole reservoir fluidbefore any changes can take place as fluidsare brought to surface. These indicators areuseful in the remaining formation evaluationprogram if unexpected crude oil propertiesare uncovered. Correlations between thesemeasurements and subsequent laboratoryPVT values help reduce the uncertainties ofthe OFA-derived GOR and API measure-ments in a given well and reservoir. Suchoperational advantages have allowed Shellto reduce rigtime and sampling costs in off-shore wells.

38 Oilfield Review

Low Shock Sampling TechniqueConventional sampling can “shock” the for-mation at the moment the chamber isopened, and the pressure drawdown to theformation can be violent and causeextremely high flow rates at the probe. Theorigin of many sampling problems is a sud-den pressure change during drawdown andan associated surge of fluids. The drawdowncan drop the sample pressure below thebubblepoint, and change the phase charac-teristics and composition of the sample withthe precipitation of solids or the appearanceof gas. In addition, high flow rates canloosen matrix grains, causing formationprobe seal failures and plugging in probeand flow lines.

Water and air cushions with valve throt-tling have sometimes been used to counterthe initial shock, but in many cases thesetechniques have failed. Air-cushion cham-bers offer little control of the drawdown andwill frequently allow the flowing pressure ofthe sample to drop below the bubblepoint.Flashing in the formation will yield anapparent GOR that is higher than the actualreservoir GOR.12

The Low Shock Sampling technique wasdeveloped by Schlumberger to limit pressuredrawdown during fluid sampling operations.The shock is minimized by pumping for-mation fluids into the MDT tool againstpiston chambers held at borehole pressure,as opposed to drawing formation fluid intochambers at atmospheric pressure (above).

This technique is frequently used for samplingin unconsolidated sands, where a typicalproblem is breakdown and mobilization ofsand grains. An effective means to addressthis problem is to use a single large-diameterprobe and a gravel-packed filter screen witha large zone of the reservoir packed off.

For example, China Offshore Oil BohaiCorporation in Bohai Bay, China needed anew technique to sample fluids in a forma-tion complicated by heavy oil in thin beds.Sampling is vital, due to the low-resistivitycontrast between oil and fresh water, leadingto uncertainty in determining formation fluidtype. Conventional downhole testing in fiveearlier wells in the same fault block wasunsuccessful in measuring pressure accu-rately, and no samples were obtained.

Using the Low Shock Sampling technique,the operator successfully captured 26 pres-sure points and one low-contaminationwater sample in this difficult formation. Asecond-low contamination, high-density oilsample was obtained using a dual-packermodule (next page, left). The large area cov-ered by the dual packer reduces the load onthe sandface, allowing the invading filtrate tobe pumped out and heavy oil to be sampledwithout collapsing the formation. The LowShock Sampling technique helped to recorda formation pressure profile safely—withoutdamaging the sandface—for the first time inthis field. The samples provided valuableinformation for reservoir modeling and com-pletion design.

Modeling Fluid FlowSince excessive pumping and cleanup timemeans increased rig costs and additional riskof differential tool sticking, new methods toreduce cleanup time and minimize the levelof contamination are being investigated.These require understanding what actuallyhappens to fluids in the formation when thesample probe makes contact with the forma-tion through the mudcake and starts to pump.A good connection to the formation is essen-tial. The probe must penetrate mudcake andseal against the formation, and the mudcakemust be able to isolate borehole mud fluidand keep it from filtrating into the sandface.Without a good mudcake seal, formation fluidflow in front of the probe can quickly changeto a flow around the probe pad, drawing inmud fluids from the borehole. Given a goodmudcake and probe seal, and knowing thedepth of invasion from a resistivity profile, one

P

P

Open valve

Closed valve

Resistivity

CQG

Strain gauge

bubblescontamination

OFA

Pressuretest chamber

Formationfluid

Samplechamber

Pump up/downmodule

Sample fluid

Wellbore fluidat hydrostaticpressure

■■Low ShockSampling tech-nique. Internalpressure of thesample chamber is held at the for-mation pressure,thereby eliminatingany shock to thesandface when thechamber is opened.Before the samplechamber is opened,the pumpout mod-ule flushes filtratefrom the formationback to the well-bore. The flowlinefluid can be moni-tored using the OFAmodule to deter-mine when a low-contaminationsample can berecovered, and thefluid flow can bediverted into asample chamber.

Autumn 1998 39

can estimate—assuming spherical flow—howlong to pump in order to remove the filtratelayer in front of the probe.

Sometimes, even with good seals, manygallons of fluid are pumped, and the sampleis still highly contaminated with filtrate.Under apparently optimum conditions, suchfactors as permeability anisotropy can affectthe results.13 Modeling fluid flow has been a useful approach to understand the com-plexity of fluid dynamics under samplingconditions. Three-dimensional models havebeen developed by Halliburton, Baker Atlasand Schlumberger to simulate the flow offluids into wireline formation tester sampleprobes.14 Results of these simulations helpvisualize the flow and lead to bettersampling strategies designed to minimizefiltrate contamination.

Schlumberger applied the results of 3Dmodeling to build a simulator to study con-tamination levels and cleanup behavior inmore than 150 combinations of variousrocks with different fluid properties.15 Thesimulator computed fluid flow and deter-mined time evolution of the contaminationlevels. The effect of various parameters suchas viscosity, anisotropy, relative fluid perme-ability, end-point mobilities, fluid density,porosity and proximity to barriers oncleanup time were analyzed. For model ver-ification, field data from sampling werematched with simulated cleanup times.

The simulator results show that the radialflow profile of formation oil is essentiallyspherical or elliptical (depending on perme-ability anisotropy), and filtrate flow is nearlycylindrical within the invaded zone (above).The outer wall of the invasion cylinder or the

■■Dual-packer module. The dual-packermodule has two packers inflated by thepumpout module to isolate a zone of theborehole from the column of mud. Thisallows a greater area of the formation to be pumped than is possible with thesingle probe.

Formation fluid (oil)

Mud filtrate (water)

Filtrate dumped into borehole

Wat

er fl

owW

ater

flow

Oil zoneFiltrate

Oil flow

■■Simulated fluidflow around a sin-gle probe. Aradial sectionmap (top) showsformation satura-tion adjacent tothe probe (right)and formation oil(red) coningtowards the probeduring samplepumping. Waterfiltrate (blue) canbe seen feedingin from aboveand below. Theinvasion satura-tion in the forma-tion opposite theprobe (left) alsoshows a charac-teristic hourglassfiltrate distributionroughly centeredon the probe.Simulator results(bottom) indicatethat cleanup timeusing multipleprobes (one probesampling and theother probe usedas a pumpingguard probe) canreduce both thecleanup time andthe ultimate levelof sample con-tamination by afactor of three.

Wat

er c

ut, %

Elapsed time, hr

Sampling probe, 2 probes flowing

Sampling probe only flowing

0 2.5 5.0

0

20

40

60

80

100

12. Flashing is a process in which the composition of a system remains constant, but the proportions of gas and liquid phases that make up the systemchange as pressure or other independent variablesare changed.

13. Ayan C, Colley N, Cowan G, Ezekwe E, Wannell M,Goode P, Halford F, Joseph J, Mongini A, ObondokoG and Pop J: “Measuring Permeability Anisotropy:The Latest Approach,” Oilfield Review 6, no. 4(October 1994): 24-35.

14. A comprehensive discussion of modeling fluid flow at the Wireline Fluid Sampling Meeting,Aberdeen, Scotland, April 22, 1997, can be found at the Welltest Network website:http://www.welltesting.net.com/index.html.

15. Akram AH, Fitzpatrick AJ and Halford FR: “A Modelto Predict Formation Tester Sample Contamination,”paper SPE 48959, accepted for presentation at theAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 27-30, 1998.

40 Oilfield Review

filtrate-oil interface, is drawn inward towardthe probe, leading to a filtrate saturation dis-tribution around the wellbore in the shape ofan hourglass. Reduction in vertical perme-ability will inhibit vertical flow of filtrate andresult in shorter cleanup times. Not surpris-ingly, proximity to a flow boundary wasfound to reduce cleanup time. Differences in

oil and filtrate density can cause the filtrate toslump vertically; if sampling takes placewhen there is significant slumping, cleanuptime increases.

Modeling suggests several practical ways toreduce cleanup time and contaminationlevel. First, formation geometry can be usedto help obtain good samples. In many wells,the zone of interest is located between twoclosely spaced shale beds, and these bedswill provide a barrier that prevents filtratefrom flowing vertically and recontaminatingthe sample zone. Another approach deploysmultiple sampling probes (left). With a mul-tiple-probe tool, one probe can act as guardprobe to isolate the other sample-taking probe from the natural vertical flow ofthe invaded filtrate. The third probe is used tohelp in setting the tool and provides a moni-toring function.

In some wells, the sampling probe can beplaced below a shale cap and the guardprobe positioned 2.3 ft [0.7 m] lower. Theguard probe will clean out the filtrate in theregion beneath the sample probe, and theshale cap keeps new filtrate from enteringfrom above. Simulations indicate that thismultiple-probe technique can reducecleanup time by a factor of three andreduce final contamination level by thesame amount. This reduction in contamina-tion level with two probes is especially use-ful because reaching a low level ofcontamination in some formations with asingle-probe configuration can be exceed-ingly difficult (see “Using the Guard-ProbeTechnique,” below).

Single-Phase SamplingAccurate compositional and PVT analysis offormation samples requires the recoveredsample to remain in downhole formationconditions. In many cases, this means main-taining a monophase sample. Many samplingchambers work on the principle of trapping afixed volume of single-phase fluid at reservoirconditions. However, as the sample returns tosurface, the temperature in the chamberdecreases (next page, top left). This coolingresults in a pressure drop within the sealedchamber, which in most cases causes thesample to pass through the bubblepoint lineto a gas and liquid mixture. As the pressureapproaches the bubblepoint, asphalteneprecipitation can occur. Asphaltene deposi-tion in the reservoir, wellbore and processlines is a well-documented problem duringcrude oil recovery. Additionally, coolingcauses the precipitation of paraffin, whichmay be left behind if not completely heatedand recombined prior to sample transfer.Recombination of precipitated asphaltenes inthe sample chamber requires a lengthy repres-suring process, which may never be fullyreversible. Compositional changes will resultin changes to other critical production param-eters such as GOR, viscosity and API gravity.

One solution to this problem has beendeveloped by Oilphase (a division ofSchlumberger Wireline & Testing in Aberdeen,Scotland). The technique involves overpres-suring the samples after they are taken atreservoir conditions. Sample chambers arepressurized across two pistons with a nitrogengas chamber, thereby allowing compensationfor the temperature-induced pressure drop asthe samples are returned to surface.16 TheSingle-Phase Multisample-Chamber (SPMC)is designed for use with the MDT multisample

■■The MDT Modular Formation DynamicsTester tool in multiprobe mode. By pump-ing through two of the three probes (thetwo on the same side of the tool) simultane-ously, samples can be obtained in less timeand with lower levels of contamination.

Using the Guard-Probe Technique

An operator working in Angola, West Africa,

needed PVT-quality, low-contamination formation

samples to characterize reserves in a deepwater

environment. The high cost associated with

obtaining fluid samples led the operator to con-

sider every option available—including new

methods of sampling—to minimize factors that

could degrade sample quality.

Guided by the results of flow-modeling analy-

sis, the MDT dual-probe configuration was used

to create a guard-probe geometry. The tool was

positioned adjacent to a permeability boundary to

help direct the flow pattern of the filtrate during the

pumpout cleanup phase. The expectation

was that by reducing the vertical filtrate flow, the

filtrate-to-reservoir fluid ratio would be lower.

After the flow pattern was optimized using

guard-probe geometry, the Low Shock Sampling

technique was used to capture fluid samples. The

OFA module was used to monitor the contamina-

tion level in real time, and the log showed when

the sample could be taken.

Two oil samples with filtrate contamination levels

of 3.3% and 4.2% by weight were recovered—

well below the job design objective of 10%.

Previous attempts using older sampling tech-

niques yielded samples with contamination levels

as high as 18.6%. The operator applied the guard-

probe and the Low Shock Sampling technique

successfully on other wells in this region.

16. Birkett GP: “Single-Phase Downhole Sampling forAsphaltenes,” presented at the International BusinessCommunications Conference on ControllingHydrates, Paraffins and Asphaltenes, New Orleans,Louisiana, USA, November 6-7, 1997.

Autumn 1998 41

module (right). The nitrogen is isolated fromthe sample chamber and acts on the samplethrough a piston floating on a synthetic oilbuffer. This avoids any nitrogen contaminationof the sample fluid. The pressurized gascharge maintains pressure in the sample chamber, ensuring that the sample remainsabove the bubblepoint line. Once brought tothe surface, sample chambers are transportedto the PVT laboratory for analysis.

How well does single-phase samplingwork? Recently, Texaco was trying to estab-lish the presence of producible hydrocar-bons in a North Sea reservoir. PVT-quality,single-phase fluid samples were required—a task well suited to single-phase samplingwith the MDT tool. Estimating recoverablereserves required accurate reservoir parame-ters derived from a representative, mono-phase formation fluid sample.

The challenge was to distinguish formationoil from the oil-base mud filtrate. Water sat-urations from 40 to 50% compounded toheighten the difficulty of testing and sam-pling. SPMC chambers were run in this wellusing the MDT multisample module. Sixlow-contamination samples were recovered,including two monophase samples. Surfacepressure checks on the SPMC chambers con-firmed monophase recovery with readingsgreater than 1600 psi [11 MPa] above forma-tion pressure. Subsequent PVT lab analysisrecorded contamination levels of 4% and2%. The samples allowed Texaco to reducethe risks associated with their recoverablereserves estimate.

Future of SamplingWireline fluid sampling technology and tech-niques continue to evolve. Despite progress,some aspects need further research.

The reservoir engineers, productionchemists and process engineers who useformation fluid data are concerned with the range and quality of the PVT andcompositional analyses they get from sam-pling. Contamination levels and their impacton the fluid analysis are crucial. As far aswater-base mud and miscible oil-base mudfiltrate contamination are concerned, expertsin the field believe they understand what arethe acceptable levels and how to obtain rep-resentative samples in formations with blackand volatile hydrocarbons. The situation inreservoirs with gas condensates is not asclear. Only a small level of oil-base mudfiltrate contamination is necessary to altersample behavior from a gas condensate to a volatile oil. This is an important area ofcontinuing research.

The data gatherers—those concerned withplanning the jobs, designing and preparingsampling tools and ultimately gatheringhigh-quality samples—must continue to lis-ten to the needs of the data users. Askingquestions about how samples will be used,and understanding how sample acquisitionand deployment affect the results, will set thecourse for new, improved solutions. —RCH

250-cm3

monophasicsample

'Floating' piston

Pressure-chargednitrogen

Nitrogen pressuretransmitted tothe samplethrough thebuffer fluid

'Floating' piston

Reservoir fluid

Buffer fluid

Nitrogen

■■Single-phase sample chamber. The Oilphase Single-Phase Multisample Chamber(SPMC) is a 250-cm3 [15 in.3], 20,000-psi [138-MPa] sample chamber that is used with theMDT multisample module to provide pressure-compensated fluid samples. Its samplebottles are filled at or near formation pressure by the MDT pumpout module. After cap-ture of the fluid sample, the sample is overpressured during retrieval by the release of apreset nitrogen charge (blue). The nitrogen acts on the sample through a piston floatingon a synthetic oil buffer. The recovery pressure is generally set several thousand psiabove the sample bubblepoint pressure.

Liquid

fract

ion

, %

Ambient temperatureReservoir temperature

A. Initial reservoir conditions

B. Nitrogen charged

D. Multiphase sample

C. Single-phase sample

Liquid

Multiphase zone

Gas

75%50%

25%

0%

Critical point100%

Temperature

Pre

ssur

e

Liquid, %

■■Phase diagram ofa typical crude oil.Liquid hydrocarbonsamples taken atreservoir tempera-ture and pressure (A)can change phaseat lower tempera-tures and pressuresas they are broughtto the surface (D). By overpressurizingthe sample down-hole (B), the samplewill maintain its initial phase as it is brought to the surface (C) at lowertemperature.