Spwla96 Paper I

SPWLA 37th Annual Logging Symposium, June 16-19, 1996

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CAPILLARY PRESSURE: THE KEY TO PRODUCIBLE POROSITY

W. SCOTT DODGE SRESSO AUSTRALIA LTD., MELBOURNE, VICTORIA, AUSTRALIA

JOHN L. SHAFER AND ROBERT E. KLIMENTIDISEXXON PRODUCTION RESEARCH COMPANY, HOUSTON, TEXAS, U.S.A.

ABSTRACT

Producible porosity, defined as the pore volumeavailable to hydrocarbon emplacement, has beencomputed from log measurements by modellingcapillary pressure irreducible water saturation as afunction of permeability and maximum hydrocarboncolumn height. Producible porosity has been alsomeasured directly by NMR when the T2 relaxationtime distribution cut-off is calibrated to the maximumcapillary pressure in the reservoir. The produciblepore volume imposes a calibration constraint on themaximum hydrocarbon pore volume that can becomputed from logs. Producible porosity contains noimmobile or irreducible water.

Total, effective, isolated, macro and micro porevolumes are all used to characterise porosity based onspecific definitions, criteria and measurementtechniques. Total porosity computed from logs shouldmatch core porosity where core porosity represents thetotal interconnected pore volume, however, totalporosity in shaley sandstone reservoirs computed fromthe crossplot of bulk density and neutron porosity logshas been shown to overestimate core porosity. Bymodelling formation mineralogy based on a calibrationset and solving the log response equations throughleast squares inversion, total porosity from logsaccurately matches core porosity.

INTRODUCTION

The reservoir engineer, geologist, petrologist andpetrophysicist all use or determine porosity tocharacterise reservoir quality and volumetrics. Theuse and understanding of porosity definitionsfrequently vary between and within disciplines. Thereservoir engineer defines effective porosity as theinterconnected pore volume of the rock, whereas this isthe definition of total porosity for the petrophysicist inclastic reservoirs where isolated porosity is negligible.

The total visible pore volume point counted in thinsection by a petrologist frequently underestimates coreporosity. This is found to be true especially in rocks

containing microporous materials. The largeintergranular pores observed in Figure 1 range in sizefrom 50 to 200 microns whereas the smallest pores(intergranular and intragranular) visible in highmagnification photomicrographs are 5 to 7 microns.Smaller pores can be observed under the ScanningElectron Microscope (SEM) in Figure 2. Thismicroporous chlorite clay contains pores less than 1micron in diameter. Hydrocarbons can invade thesepores only when the pressure in the hydrocarboncolumn is greater than the capillary pressure in themicropores.

This paper focuses on porosity description in clasticdepositional rock facies where isolated porosity isnegligible and normally can be ignored. Weacknowledge that in clastics isolated porosity can occurunder certain conditions of sandstone diagenesis.Definitions and concepts of total and effective porosityare reviewed while we go on to define a newhydrodynamic pore volume, "producible porosity".

PETROPHYSICAL POROSITY MODEL

Porosity in a shaley sand can be viewed as a continuumthat changes with the measurement method anddefinition of its components. Formations whichcontain detrital clay grains have significantmicroporosity as with the glauconitic sandstone inFigure 1. This thin-section is from an oil reservoircontaining a high total water saturation and producesoil, free of formation water due to the abundance ofclay and capillary bound water. A large component ofthe bound water is associated with micro porosity inthe glauconite. Microporous detrital grains such asglauconite have less of an adverse effect on formationpermeability compared to the pore lining chloriteshown in Figure 2.

Three modes of porosity that have been defined andrelated to drainage capillary pressure data areillustrated in Figure 3. Clay bound water is depictedby the water associated with pore lining and fillingclay in addition to detrital clay grains. In fine grainedsandstones, additional irreducible pore water is


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present in small pores and pore throats due to capillaryforces. The sum of irreducible water due to capillaryforces and clay bound water is the bulk volumeirreducible, BVI, water in the reservoir which ismeasured by drainage capillary pressuremeasurements. Producible porosity is that macro porevolume which contains the moveable fluids, water andpotentially hydrocarbons.

As grain size and composition change, so does themechanism for irreducible fluid entrapment in theform of clay and capillary bound water. Thecorresponding petrophysical shaley sand model basedon these pore fluid types in a water-wet reservoir isshown in Figure 4. New techniques will be shownhow to determine the producible porosity whichcontains no irreducible water.

TOTAL POROSITY

The engineering definition of total porosity in asandstone is "The ratio of void space in a rock to thebulk volume of that rock". Pore volume of a rocksample is most commonly measured using Boyle's lawor helium expansion. In separate measurements, porevolume and grain volume are computed from a knownvolume of gas at a known pressure and expanded intoa chamber containing the rock sample. The pressurein the chamber is measured after equilibration fromwhich the unknown volume is computed. Totalinterconnected porosity from core is computed as,

φtGrain Volume

Pore VolumePore Volume

=+

(1)

An important point to be made is that even when thesample is dried using humidity controlled drying it hasbeen shown the water saturation in the rock isnegligible and is equivalent to that observed atextremely high air/brine capillary pressure in excess of13000 psi (Pallatt, 1990).

Commonly, total porosity from logs is computed usingthe bulk density and neutron porosity crossplot(Schlumberger, 1995). Crossplot porosity is accuratewhen the reservoir mineralogy contains quartz, calciteor dolomite and low clay content. This technique,however, overestimates porosity in shaley sandreservoirs. Figure 5 shows core porosity compared tototal porosity computed using two different porositymodels over the cored interval down to 2875 metres.Track 3 contains the crossplot porosity, PHIX, whilethe curve labelled LASER PHIT results from solving

the log response equations in a process called leastsquares inversion. LASER porosity is determinedfrom a log forward model based on the results of coremineralogical analyses by Fourier Transform InfraredSpectroscopy MINERALOG (Hamish, 1988), thinsection petrographic analysis, and quantitative X-raydiffraction and X-ray fluorescence chemical analyses.The LASER mineral model, based on core mineralidentification, contains quartz, potassium feldspar,dolomite, glauconite and kaolinite for the reservoir inthis example.

The reservoir sequence from 2880 metres to 2895metres has an elevated gamma ray which is caused bythe presence of radioactive potassium feldspar shownin track 4. Clay volume in track 5 is negligible overthis interval. LASER computed mineral bulk volumeof potassium feldspar and clay compare well to core.Clay volume from LASER is the sum of the glauconiteand kaolinite volumes. Modelling formationmineralogy with LASER, grain density is accuratelycomputed from the volume fraction of each mineralmultiplied by its grain density. This in turn results inmore accurate porosity determination from logs.Crossplot porosity fails to determine grain densityaccurately in sandstone reservoirs containing clays orfeldspars. The low grain density of feldspar and thedifferent clay types found associated with sandstonesare not taken into account in the solution of crossplotporosity.

PHIX crossplot porosity overestimates core andLASER porosity by 3.4 porosity units in this shaleyfeldspathic sandstone reservoir interval at 2870 metresshown in track 3. Total porosity is overestimated by17 percent using PHIX.

EFFECTIVE POROSITY

Effective porosity is commonly used as a measurementof rock quality to identify net reservoir from non-netreservoir. Effective porosity as defined by thepetrophysicist is "The total porosity less any waterassociated with clay minerals in the rock".

φ φe t clbwV = − (2)

Different methods have evolved in the determinationof clay bound water. The shale volume relationshipdetermined from logs in Equation 3 is commonly usedto estimate the clay bound water term in Equation 2.

V Vshbw sh sh = × φ (3)


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Non-clay minerals in a shale also contain associatedporosity. Therefore even a dense shale will containporosity that is not associated with clays. Equation 3frequently overestimates clay microporosity whereshale volume is usually one in a pure shale. This isbecause clay volume is commonly less than 50 percentof the rock volume in shales, therefore

V Vclbw shbw ≠ and V Vclay sh ≠

An accurate method which measures clayintragranular microporosity developed at ExxonProduction Research Company is calledMICROQUANT. Figure 6 shows a backscatteredelectron SEM image of a glauconite grain where theblack is pure porosity and the intermediate grey levelsvarying amounts of clay microporosity. Grey scaleimage analysis has determined the clay grain tocontain 23.4 percent intragranular porosity. Once adatabase of porosity associated with different clay andgrain types has been built, it is incorporated into aLASER petrophysical model which computes thevarious clay and other mineral fractions and theassociated microporosity from MICROQUANT. It isessential to calibrate the LASER model on a largeenough number of well characterised samples.

It is of primary importance to recognise that incorrectdetermination of the volume of clay bound water willaffect the contribution of the clay water conductivity inshaley sand water saturation equations like Dual Waterand Simandoux. Over estimation of clay bound waterin Equation 3 introduces error in total water saturationcomputed from logs.

WATER SATURATION

Effective porosity and effective water saturation arecommonly used to characterise rock quality andproducible fluids in shaley sands. Effective watersaturation and clay bound water saturation are definedin Equations 4 and 5.

Swe S - S1- Swt wb

wb= (4)

where:

Swb Vclbw

t=

φ(5)

Effective water saturation and effective porosity arethen used to compute hydrocarbon pore volume,

V S Shy t wt e we = − = −φ φ( ) ( )1 1 (6)

Hydrocarbon pore volume must be the same whethercomputed using porosity and water saturation on atotal or effective pore volume basis. It is common toobserve Swe approach or be limited to zero in shaleyhydrocarbon bearing sands. Hydrocarbon pore volumewill be in error in this situation and underestimated.This error is due to incorrectly determining clay boundwater which results in underestimating effectiveporosity and overestimating bound water saturation.The current recommendation for computinghydrocarbon pore volume is to use porosity and watersaturation on a total pore volume basis as in the firstpart of Equation 6.

PRODUCIBLE POROSITY

Producible porosity is discussed by Timur as early as1969 (Timur, 1969) relating pore volume available tohydrocarbon storage.

φ φp t wS = −( )1 (7)

Timur's producible porosity in Equation 7 is computedusing water saturation determined from air/brinedrainage capillary pressure at 50 psi. This capillarypressure was selected based on field observations ofwater free oil production at 50 psi capillary pressure.Timur's method fails to account for reservoirs havingdifferent hydrocarbon column heights and fluid types.We have taken Timur's producible porosity definitionone step further to account for these factors.Incorporating irreducible water saturation into Timur'sEquation 7, we can determine the producible porespace accessible to hydrocarbons for any oil or gasreservoir.

φ φp t wiS = −( )1 (8)

"Irreducible water saturation is defined by primarydrainage capillary pressure behaviour andcorresponds to the water saturation at the maximumcapillary pressure existing in the reservoir". Thisleads to the definition of producible porosity as "Thepore volume available to hydrocarbon emplacement".The petrophysical shaley sand formation model inFigure 4 shows the relationships of total, effective andproducible porosity.


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Determining producible porosity has great advantagesover effective porosity. Effective porosity contains theirreducible pore fluids related to capillary bound waterin addition to the moveable fluids, connate waterand/or hydrocarbons. Capillary bound water cannot bemeasured using conventional logging tools. We willshow that modelling capillary pressure measurementsor Nuclear Magnetic Resonance (NMR) loggingprovides the additional information to measure thiscapillary bound water.

Irreducible water saturation has been modeled usingdrainage capillary pressure saturation as a function ofpermeability and maximum hydrocarbon columnheight. Drainage capillary pressure by mercuryinjection of two sandstones of different permeabilityare shown in Figures 7a and 7b. Petrophysicalproperties of these two samples are shown in Table 1.

TABLE 1Core Petrophysical Measurements

SampleNumber

LiquidPermeability

HeliumPorosity

ThinSectionVisiblePorosity

Swi@

265psiHg

(md) (p.u.) (p.u.) (s.u.)

3 2540 25 11 8

6 0.12 15 4 62

The reservoir has a 30 metre oil column height with amaximum oil/water capillary pressure of 19 psi. The19 psi oil/water capillary pressure is equivalent to alaboratory air/brine capillary pressure of 52 psi. Thispressure, coincidentally, is similar to Timur's capillarypressure conditions. The reservoir capillary pressuretransforms to an equivalent laboratory mercurycapillary pressure of 265 psi. Equations 9 and 10 showhow to compute reservoir and laboratory capillarypressure for the maximum hydrocarbon column height.

Pc res( ) . ) h ( max w o= −0 0228 ρ ρ (9)

Pc Pclab reslab

res( ) ( )

( cos )( cos )

=σ θσ θ

(10)

The 265 psi mercury equivalent reservoir capillarypressure corresponds to the minimum water saturationin the reservoir, 8 percent in sample 3 and 62 percentin sample 6. This minimum water saturationpartitions the total pore volume into two pore volumecomponents: producible porosity (fraction of totalporosity representing accessible pore volume at 265psi) and irreducible fluid filled pore volume (fraction

of total porosity representing irreducible watersaturation). We can also consider the irreducible fluidfilled pore volume to represent the microporosity in therock composed of clay intragranular microporosity andsmall pores and pore throats associated with fine grainnon-clay minerals as shown in Figure 3. Additionally,capillary water can be trapped in pore throats of coarsegrain sands. The large macro pores contain onlymoveable fluids, the volume of which is equivalent toproducible porosity. The subdivision between the twopore types is determined by the maximum capillarypressure in the reservoir. This can be expressed as,

φ φ φ φt p wi macro microV = + = + (11)

By differentiating the drainage capillary pressuremeasurement, accessible pore volume was computed inFigures 8a and 8b. Inspection of SEMphotomicrographs as in Figure 2 reveals pore typeswhich may be available to hydrocarbon emplacementat the micron scale. The accessible pore volumediagrams in Figures 8a and 8b show the subdivisionbetween macro and microporosity. The minimum porethroat diameter that permits hydrocarbon emplacementis 1.0 micron for this reservoir from,

r

= =26 895

26 895

( cos ).

( cos ).( ) ( )

σ θ σ θres

res

lab

labPc Pc(12)

Effective porosity overestimates producible porosity asreservoir quality declines. This is shown in Table 2where the clay rich sample 6 has a total porosity of 15p.u., effective porosity of 8.8 p.u. and producibleporosity of 5.7 p.u.. Producible porosity determinedfrom drainage capillary pressure in this poor qualityshaley sand sample confirms that 5.7 p.u. can containhydrocarbons.

TABLE 2Comparison of Total, Effective, Producible PorositySample Vclay PHIT PHIE PHIP

(%) (p.u.) (p.u.) (p.u.)

3 8 25.0 23.7 23.0

6 29 15.0 8.8 5.7

Capillary pressure irreducible water saturation hasbeen modelled as a function of permeability shown inFigure 9 and Equation 13. The irreducible watersaturation was determined at a maximum reservoircapillary pressure of 52 psi from air/brine drainagecentrifuge measurements. It is preferable to use


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air/brine drainage capillary pressure when available,where brine is the wetting phase, as opposed tomercury injection which is performed on an evacuatedsample.

Swi k = − +0 223 0 892. log( ) . (13)

Producible porosity can be determined using Equation8 once having established the irreducible watersaturation relationship based on formationpermeability and maximum hydrocarbon columnheight. In the following example, permeability wasdetermined using core and log NMR. Techniques tomeasure permeability outside of reservoir coredintervals include NMR (Coates, 1993), Hydraulic FlowUnits (Amaefule, 1994), Regression techniques(Herron, 1987), Acoustic Stoneley waves (Winkler,1989) or Discriminant Analysis.

RESERVOIR CHARACTERISATION USINGPRODUCIBLE POROSITY

A glauconite rich shaley sand reservoir whichcomputes high water saturations from logs productiontested oil rates as high as 1500 bpd in an offset well.Figure 10 shows the producible porosity and watersaturation resulting from modelling drainage capillarypressure. The reservoir's field oil-water contact occursat 2859 metres; residual oil saturations are presentbelow this depth caused by late structuring of thereservoir post oil migration. The reservoir wasconventionally cored from 2837 metres to 2875 metresand oil fluorescence was visible in the core to a depthof 2849 metres confirming the presence of oil.

Overburden core permeability is shown in track 4 ofFigure 10. A 10 millidarcy permeability net reservoircut-off is also displayed showing reservoir quality isbelow the cut-off within the oil column. Producing oilreservoirs in the Gippsland Basin flow oil at economicrates when formation permeability is greater than 10millidarcy. The entire reservoir section was loggedwith NUMAR's "B" series Nuclear MagneticResonance Image Log (MRIL). Below the coredinterval permeability was determined using the MRILCoates permeability relationship. We have shownpreviously (Dodge, 1995) the good comparison ofNMR permeability to overburden core permeability onlaboratory core plug samples from this reservoir inanother well.

In the glauconitic sandstone reservoir from 2837metres to 2882 metres the producible porosity is

significantly less than effective or total porosity whichleaves less pore volume available for hydrocarbonemplacement. Within the high permeabilitysandstones below 2882 metres all three pore typesconverge indicating a low irreducible water saturationin the high permeability facies.

Measurement of producible porosity provides acalibration for log computed hydrocarbon pore volumeshown in track 3 of Figure 10. Knowledge ofproducible porosity imposes the constraint thathydrocarbon pore volume must be less than theproducible pore volume. When the reservoir is abovethe oil-water transition zone, the hydrocarbon porevolume approaches the producible pore volume.

V Shy wt t p= − ≤φ φ( )1 (14)

This constraint can also be viewed in terms of watersaturation,

S Swt wi ≥ (15)

APPLICATIONS OF NMR TO FORMATIONEVALUATION

NMR can provide additional information to thepetrophysical logging suite available only from corecapillary pressure measurements. Specific to thispaper NMR provides, based on a predetermined T2 cut-off, quantitative estimates of:

• Free Fluid Index (FFI)• Irreducible Fluid Filled Porosity (BVI)

NMR measures the relaxation rate of hydrogen protonsin porous media when excited by an applied magneticfield. T2 relaxation time of transverse magnetisationcan be related to the surface-to-volume ratio of watersaturated rocks. The BVI from log NMR does notmeasure clay bound water because of the very fastrelaxation time of clays (<1 msec) but is a measure ofthe capillary bound irreducible fluid. To computeaccurate irreducible water saturation from log NMRwhich can be calibrated to core, the clay bound porewater must be taken into account as,

Swi BVI V

FFINMR clbw

t

t

t= =

+ −

φφ

φ(16)

The great advantage of NMR to formation evaluationis that the logging measurement can be simulated inthe laboratory on core using NMR spectrometry.


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When performing NMR measurements on core it isimportant to design the experiments to have the sameacquisition parameters as the logging tool if the goal iscore to log calibration. Specifically magnetic fieldstrength (homogeneous or gradient), echo spacing, andrecovery time should be equivalent.

A laboratory T2 relaxation distribution is shown for thelow clay content sandstone in Figure 11. The bi-modalT2 distribution indicates that a high percentage of theporosity contains large pores and a small component ofpore space is microporous. T2 relaxation wasmeasured with the plug fully saturated and alsodesaturated to 50 psi air/brine capillary pressure. Thecapillary bound irreducible water is represented by thesignal amplitude less than 33 msec. Integration of theT2 distribution amplitudes over all T2 for the fullysaturated sample yields the rock pore volume,

∫= 22)( dTTANMR

φ (17)

NMR FFI is calibrated to producible porosity measuredfrom drainage capillary pressure by determining therelaxation T2 cut-off which equates these twomeasurements,

∫∞

==off-2cut

T

22)dTA(T FFI pressurecap

pφ (18)

The primary drainage mercury injection capillarypressure for this sample is shown in Figure 12. Porevolume which contains producible fluids occurs forcapillary pressures below 265 psi. Calibration of theNMR T2 cut-off time to this pore volume bringsequivalence into the NMR derived producible porevolume measurements.

Literature is filled with comparison of NMR T2relaxation distributions to capillary pressure (Chang,1994, Dunn, 1994, Kenyon, 1992). The newest logNMR signal processing is based on computation ofproducible porosity from T2 relaxation distributions. Ithas been shown that the T2 relaxation cut-off for mostclastic reservoirs is approximately 33 msec (Straley,1991).

SUMMARY

Definitions of porosity are quite varied between thevarious disciplines which use this petrophysicalparameter. Producible porosity reviewed in this paperis a new porosity type, having distinct advantages for

reservoir description and hydrocarbon volumequantification.

Producible porosity is determined from drainagecapillary pressure measurements and represents "Thepore volume available to hydrocarbon emplacement".Producible pore volume from core imposes a maximumconstraint on the hydrocarbon pore volume computedfrom petrophysical logs. It is now possible to computeproducible porosity from log measurements bymodelling capillary pressure irreducible watersaturation as a function of permeability and maximumhydrocarbon column height. Permeability data arerequired to transfer the modelling process to thepetrophysical logs.

NMR log measurements quantify producible porosityand capillary bound irreducible pore volume whencalibrated to core. These log measurements canprovide significant cost savings in special core analysisby replacing the need to measure drainage capillarypressure water saturation to verify petrophysical logderived water saturation as well as increase reservoircoverage in non-cored intervals.

NOMENCLATURE

A NMR signal amplitude, p.u.hmax maximum height of hydc. column, metresk single phase absolute permeability, mdPc(lab) laboratory capillary pressure, psiPc(res) reservoir capillary pressure, psiSw drainage capillary water saturation, fracSwb clay bound water saturation, fracSwe effective water saturation, fracSwi irreducible water saturation, fracSwt total water saturation, fracT2 transverse spin-spin relaxation time, msecVclay bulk volume dry clay minerals, fracVclbw bulk volume clay bound water, fracVhy bulk volume hydrocarbons, fracVsh bulk volume shale, fracVshbw bulk volume shale bound water, fracVwi bulk volume irreducible water, fracφe effective pore volume, fracφmacro macro pore volume, fracφmicro micro pore volume, fracφp producible pore volume, fracφsh porosity in shale, fracφt total pore volume, fracρo reservoir condition oil density, lb/cfρw connate water density, lb/cfσ fluid surface tension, dynes/cm2


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θ fluid contact angle, degrees

ACKNOWLEDGEMENTS

The authors would like to acknowledge Kumar Kuttan,Steve Twartz and Andy Mills for their work insaturation modelling of capillary pressuremeasurements. Angel Guzman-Garcia providedvaluable comments in the editing of this paper.Special thanks to Esso Australia Ltd., ExxonProduction Research Company, Exxon ExplorationCompany, and BHP Petroleum for permission topublish this paper.

REFERENCES CITED

Amaefule, J.O., 1994, "Applications of Core Data inHydraulic (Flow) Unit Zonation for ImprovedReservoir Description", Workshop on Core Analysisfor Reservoir Management, Society of Core Analysts,Vienna, Austria.

Chang, D., 1994, Vinegar, H.J., Morriss, C.E., Straley,C., "Effective Porosity, Producible Fluid andPermeability in Carbonates from NMR Logging",SPWLA 35th Annual Logging Symposium, Paper A.

Dodge, W.S., Shafer, J.L., Guzman-Garcia, A.G.,1995, "Core and Log NMR Measurements of an Iron-Rich Glauconitic Sandstone Reservoir", SPWLA 36thAnnual Logging Symposium, Paper O.

Dunn, K.J., LaTorraca, G.A., Warner, J.L., Bergman,D.J., 1994, "On the Calculations and Interpretation ofNMR Relaxation Time Distributions", SPE 69thAnnual Technical Conference, New Orleans, La., SPE28367.

Hamish, A., Harville, D.G., Meer, D., Freeman, D.,1988, "Rapid mineral analysis by Fourier transforminfrared spectroscopy", Society of Core AnalystsConference, SCA 8809.

Herron, M.M., 1987, "Estimating the IntrinsicPermeability of Clastic Sediments from GeochemicalData", SPWLA 28th Annual Logging Symposium,Paper HH.

Kenyon, W.E., 1992, "Nuclear Magnetic Resonance asa Petrophysical Measurement", Nuclear Geophysics,Vol. 6, No. 2, pp 153-171.

Pallatt, N., Thornley, D., 1990, "The Role of BoundWater and Capillary Water in the Evaluation ofPorosity in Reservoirs", Society of European CoreAnalysis Symposium.

Schlumberger, 1995, "Log Interpretation Charts",Schlumberger Educational Services.

Straley, C., Morriss, C.E., Kenyon, W.E., Howard, J.J.,1991, "NMR in Partially Saturated Rocks: LaboratoryInsights on Free Fluid Index and Comparison withBorehole Logs", SPWLA 32nd Annual LoggingSymposium, Paper CC.

Timur, A., 1969, "Pulsed Nuclear Magnetic ResonanceStudies of Porosity, Moveable Fluid, and Permeabilityof Sandstones", JPT.

Winkler, K.W., Liu, H.L., Johnson, D.L., 1989,"Permeability and borehole Stoneley waves:Comparison between experiment and theory",Geophysics, Vol. 54, No. 1.

ABOUT THE AUTHORS

Scott Dodge is a Senior Petrophysicist with EssoAustralia Ltd. in Melbourne, Australia. He holds aBSc. degree in Mechanical Engineering from KansasState University and MSc. degree in PetroleumEngineering from University of Southern California.He has served as President of the FormationEvaluation Society of Victoria. Scott joined Exxon in1982 and has worked in the U.S.A., Canada andAustralia as a Formation Evaluation Specialist.

John Shafer presently is a Senior Research Specialistin the Reservoir Division of Exxon ProductionResearch in Houston, Texas. He received a BSc.degree in Chemistry from Allegheny College in 1963,a Ph.D. degree in Chemistry from University ofCalifornia at Berkeley in 1971, and a MSc. degree inPetroleum Engineering from the University of Houstonin 1992. John has been with Exxon for the past 17years.

Bob Klimentidis is presently a GeochemicalTechnologist in the Petrophysics and Reservoir Qualitysection of Exxon Production Research in Houston,Texas. He received a BSc. and MSc. degrees inGeology in 1975 and 1979 respectively from QueensCollege, University of New York. Bob has been withExxon for the past 15 years.


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Spwla96 Paper I