SPWLA 36th Annual Logging Symposium, June 26-29, 1995˝

-1-

CORE AND LOG NMR MEASUREMENTS OF AN IRON-RICH,GLAUCONITIC SANDSTONE RESERVOIR

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

JOHN L. SHAFER AND ANGEL G. GUZMAN-GARCIAEXXON PRODUCTION RESEARCH COMPANY, HOUSTON, TEXAS, U.S.A.

ABSTRACT

NMR porosity and relaxation time measurements froman iron-rich, glauconitic sandstone reservoir showquantifiable effects of mineral iron content on NMRT2 relaxation times. This result has significant impactupon measuring irreducible water pore volume wherethe surface relaxation mechanism is nonconstant.Centrifuge air/brine drainage capillary pressuremeasurements show that the standard 30 msec T2cutoff must be lowered to calibrate irreducible watersaturation computed from NMR. Although the effectsof iron are observable on T2 distributions, permeabilityestimation from NMR, using either the Coates orSchlumberger relationships, show excellent agreementto permeability on core plugs.

Quantitative mineral composition on core plugs usingboth XRD and XRF, show iron-rich glauconite to varyfrom 3 to 31 weight percent. The bulk rock total ironoxide content ranges from 1 to 17 weight percent.High iron content within this reservoir raised concernthat NMR surface relaxation would be affected,leading to errors in irreducible water saturation andproducible porosity derived from NMR measurements.

NMR measurements were acquired using a pulsed fieldgradient logging tool operating at 530 kHz and on coreplugs with a 1000 kHz laboratory spectrometer.Homogenous field NMR core plug measurements areused to show the accuracy of the logging tool tomeasure NMR porosity, and permeability.

INTRODUCTION

Conventional methods using logs to determine net pay,effective porosity, water saturation, and producibilityproved ineffective in an iron-rich glauconiticsandstone oil reservoir recently drilled in Australia.Production tests costing in the order of A$1.5m havebeen required to determine the producibility owing to

difficulty in determining a realistic porosity-permeability relationship. This mineralogicallycomplex reservoir, deposited in Eocene age offshoremarine channels, contains significant amounts of iron-bearing detrital glauconite, matrix clays, andauthigenic chlorite, dolomite cement and sideritereplacement. The dominant controls on reservoirporosity and permeability are grain size, clay matrix,and the amount of microporosity in dissolvingfeldspars, glauconite, and clay matrix.

The first well (Well 1) drilled into the reservoirpenetrated a 30 metre oil column. The petrophysicalevaluation (Figure 1) to determine porosity, watersaturation and permeability, integrated core analysis,mineralogy, drainage capillary pressure measurementsand conventional wireline logs. Above the oil-watertransition zone (i.e., above 2927 metres) the averagetotal water saturation was 55 percent. Owing to thepoor reservoir quality and high water saturation, thewell was production tested, and flowed oil at 1500 bpd(barrels per day) with no evidence of formation water.Drainage capillary pressure measurements confirmedthat the high water saturation was irreducible and, asindicated by the production test, would not beproduced.

A second well in the field (Well 2) penetrated an olderreservoir containing a similar glauconitic sandstone,underlain by a high reservoir-quality, partiallydolomitised sandstone with multidarcy permeability.This well (Figure 2) was production-tested sequentiallyover the two intervals, flowing water-free oil at 6640bpd from the lower sand, and 5660 bpd from the poor-quality upper reservoir. The entire reservoir sand wasconventionally cored and an extensive reservoircharacterisation programme was undertaken toaccurately determine the formation mineralogy andpetrophysical properties.

SPWLA 36th Annual Logging Symposium, June 26-29, 1995

-2-

As part of the reservoir characterisation programme,laboratory Nuclear Magnetic Resonance (NMR)measurements were conducted on 15 core plugs fromWell 2. These measurements were undertaken toassess the ability of NMR to measure porosity,irreducible water saturation, and permeability in thismineralogically complex reservoir. If successful, theNMR logging tool could be used to log future wells inthe development of the field to reduce the need forexpensive production tests and conventional core. Wewere concerned, however, by the high iron content ofthe reservoir rocks. The laboratory measurementssubsequently confirmed that NMR could be used tomeasure valid reservoir petrophysical parameters whencalibrated to air/brine capillary pressure saturation.

The successful laboratory results in Well 2 supportedthe running of an NMR logging tool in the third welldrilled in this field. The well was conventionallycored and comparisons of the log measurements withNMR core plug measurements were performed inorder to assess the quality of the log data.

CHARACTERISATION OF RESERVOIRMINERALOGY

Quantifying formation mineralogy was the first step tobuilding a petrophysical model for this complexreservoir rock. A programme was developedincorporating measurements such as Petrographicanalysis, intragranualar microporosity(MICROQUANT), Scanning Electron Microscopy(SEM), and quantitative mineralogy (MINQUANT).MINQUANT and MICROQUANT are programmesdeveloped at Exxon Production Research Company.MINQUANT uses X-ray diffraction (XRD) and X-rayfluorescence (XRF) elemental chemical analysis toquantify mineralogy. MICROQUANT usesbackscattered electron images to quantify intragranularmicroporosity.

The large difference between total and effectiveporosity on the computed well log responses in Well 1(Figure 1), indicated that the reservoir rocks containsignificant quantities of microporous clay as well asthin beds of dense siderite minerals. A thin-sectionphotomicrograph (Figure 3) shows the presence ofgreen glauconite grains which are the same size asquartz grains in this sample. Additionally, clay richsedimentary rock fragments and diagenetic chlorite arepresent, and both contain intragranular microporosity.The size of the intergranular pores (blue) is as large as80 microns.

An SEM image (Figure 4) at x5000 magnificationshows highly crystalline microporous chlorite. Themicropores range from 8 microns to sub-micron size.The maximum capillary pressure in this reservoir is 50psi air/brine equivalent corresponding to a 0.5 micronpore-throat size, and thus much of this microporosityis accessible to hydrocarbons. Figure 5 shows a high-magnification thin-section photomicrograph of a greenglauconite grain. In the backscatter SEM image x1000magnification of this same glauconite grain (Figure 6),intragranular porosity is visible as black in the image.The micropores within this grain range in size from 10microns down to sub-micron. The glauconitemicroporosity averages 21 percent grain volume asmeasured by MICROQUANT.

Fifteen core plugs from Well 2 in Figure 2 wereanalysed using MINQUANT. The results (Table 1)showed quartz content ranging from 77 to 44 on agrain weight percent basis, and total clay mineralcontent to be as high as 34 percent. Dense iron-bearing minerals identified in these samples areglauconite and pyrite. The bulk iron content from XRFin these samples ranges from 1.3 to 9.5 weight percent.The diagenetic iron-bearing chlorite identified in SEMis included in the glauconite fraction determined fromMINQUANT.

CHARACTERISATION OF RESERVOIRPETROPHYSICS

Prediction of formation productivity is difficult wherethere is a weak correlation between porosity andpermeability as is the case in these mineralogicallycomplex sandstone reservoirs. The ability to predictproductivity is important in order to determinewhether a reservoir sequence is able to deliverhydrocarbons at economic rates. Figure 7a shows theporosity to permeability relationship for Well 2. Thetwo reservoirs in this well are represented by twodifferent relationships.

In Well 2 (Figure 2), the dolomitic sandstone from2840 to 2862 metres has porosity that varies from 4 to27 percent, whereas permeability remain uniformlyabove 2000 md. Thin-sections show this reservoir tobe a quartzose sandstone with clay content less than 10percent. The multidarcy sandstone contains varyingamounts of diagenetic dolomite cement filling theintergranular pore volume. The dolomitisation doesnot ensure that occluded porosity also reducespermeability.

SPWLA 36th Annual Logging Symposium, June 26-29, 1995˝

-3-

The glauconitic sandstone from 2825 to 2840 metresin the same well shows a more linear trend of porositywith permeability. The opposite phenomena to thedeeper sand occurs in this reservoir in that minorchanges in porosity can correspond to two orders ofmagnitude change in permeability. The two reservoirsexhibit dramatically different porosity-permeabilityrelationships, and it is this uncertainty that can lead tosignificant errors in estimating permeability.

Fifteen core plugs were selected to represent bothreservoir facies for NMR measurements (Figure 7b).Core analysis for each of these plugs (Table 2) showthe variability of porosity and permeability in these oil-bearing sandstones. The majority of the samples havean average grain density greater than that of quartz(2.65 g/cc) because of the presence of denser minerals:e.g. glauconite (2.85 g/cc), dolomite (2.85 g/cc), andpyrite (4.99 g/cc).

Centrifuge air/brine drainage capillary pressure wasmeasured using 222 x 254 millimetre core plugs. Thesamples were spun at a centrifuge speed equivalent tothe 50 psi air/brine capillary pressure in the 30 metreoil column. The water saturation obtained at thispressure is defined to be equivalent to the irreduciblewater saturation in the reservoir. Coincidentally this50 psi air/brine capillary pressure is the same as thatused by Timur (1969) to define producible porosity.Timur's relationship was used (Equation 1), withsubstitution of the irreducible water saturation asdetermined at the maximum capillary pressure in thereservoir, to define the pore volume containing mobilefluids (hydrocarbons and connate water).

φp = φt (1-Swi) (1)

Table 2 shows that the centrifuge irreducible watersaturation ranges from 0.12 to 0.78. Figure 8 showsthat irreducible water saturation is closely related topermeability (r2=0.96) and can be used as an estimateof reservoir permeability.

Increasing iron content is associated with lowerpermeability samples illustrated in Figure 9. Wheniron content exceeds 4 percent, the mineralscontributing the most to high iron content are siderite,glauconite and chlorite. Chlorite is a diagenetic pore-filling clay which directly impacts fluid flow throughthe pore system. The glauconite is a detrital frameworkgrain which does not impact permeability as severelyas chlorite. The glauconite, however, is ductile and can

reduce the intergranular pore space upon compactionwith burial.

EFFECT OF IRON ON NMR T2 RELAXATIONAND IRREDUCIBLE WATER SATURATION

NMR T2 relaxation measurements were taken on thefifteen core plugs whose porosity and permeabilitycharacteristics are shown in Figure 7b. A laboratoryNUMALOG CORESPEC spectrometer operating at1000 kHz recorded the CPMG pulse train echoes(Farrar, 1971) of hydrogen protons in the field oftransverse magnetisation, T2. These amplitude versustime measurements were acquired in an appliedhomogeneous magnetic field with an inter echospacing of 0.5 milliseconds and a range of repetitiontimes from 1 to 20 seconds. A sandstone with variablepore size yields a T2 relaxation decay curve that is thesum of single exponentials with each termcorresponding to a particular pore size (Equation 2).

A(t) = Aie (-t/T2i) (2)

Where Ai is proportional to the proton population ofpores having a relaxation time of T2i. The T2amplitude spectra for five of the fifteen core plugs,shown in Figure 10, represent a range of permeabilityfrom 3.4 md to 4235 md. As permeability increases,T2g also increases from a low of 4.3 msec for the lowpermeability sample, up to 90 msec for the highpermeability sample. Integration of the amplitudespectra yields NMR porosity (Equation 3).

φNMR = K Σ Ai (3)

The impact of mineral iron content is reflected in thesurface relaxivity term (ρ) which relates T2 relaxationtime to pore surface area and pore volume (Equation4).

T2-1 = ρ (S/V) (4)

If the surface relaxivity is nonconstant, then the abilityof T2g to purely reflect surface to volumecharacteristics (i.e. mobile vs non-mobile fluids) is notvalid. An increase of surface relaxation will directlyimpact T2g by shifting the relaxation distribution toshorter times. Integration of the T2 amplitudedistribution may still reflect porosity, although theselection of a T2 cutoff for partitioning Bulk VolumeIrreducible (BVI) fluid from producible fluid maychange. It has been shown in several studies of

SPWLA 36th Annual Logging Symposium, June 26-29, 1995

-4-

sandstones (Morriss, 1993, Kleinberg, 1993) that a T2cutoff time of approximately 30 msec, when applied toT2 distributions, reflects the irreducible watersaturation as measured by drainage capillary pressure.

NMR irreducible water saturation was computed fromthe T2 distribution curve by selecting a T2 cutoff timeat 10, 20, 30 and 40 msec (Table 2). The ratio of thearea under the curve below the T2 cutoff, to the totalarea under the curve, is the irreducible watersaturation from NMR. Figure 11 shows NMRirreducible water saturation, and 50 psi air/brinecapillary pressure water saturation for each T2 cutoff.It is apparent that the low permeability samples withhigh irreducible water saturation (above 0.40) have asignificant proportion of their pore volume in therange of 10 to 40 msec. As the T2 cutoff changes, alarge change is observed in Swi. The highpermeability samples have very few small pores in therange of 10 to 40 msec, with the majority of the poresat higher T2 times.

IRON CONTENT, T2 CUTOFF AND THEERROR ON NMR IRREDUCIBLE WATERSATURATION

Figures 12 through 14 show the difference betweenNMR Swi and Air/Brine Swi as a function of ironcontent for a T2 cutoff of 30, 20, and 10 msec. Figure12 shows for a T2 cutoff of 30 msec, the error is 0.01in NMR Swi for samples with less than 4 percent iron.For samples with higher iron content, the error inNMR Swi is as much as 0.19. These data places anupper bound on the error in NMR Swi in theseglauconitic sandstones when using the standard T2cutoff of 30 msec.

The iron content increases NMR surface relaxation,which in turn shifts the T2 distribution to lower times.Therefore the T2 cutoff would have to shift to lowertimes to maintain calibration of NMR Swi to Air/BrineSwi. Figure 13 shows that with a 20 msec T2 cutoffthe error in NMR Swi is -0.03 for samples with ironcontent less than 4 percent. The majority of thesamples with higher iron content contain an error ofless than 0.05.

By reducing the T2 cutoff to 10 msec (Figure 14), mostsamples underestimate Air/Brine Swi, with errorsranging from -0.03 to -0.10. It would be reasonable touse a T2 cutoff of 10 msec for reservoir rocks withmore than 6 percent iron.

After a review of these data we can suggest thefollowing general guidelines for appropriate T2 cutofftimes in iron-bearing glauconitic-rich sandstones.

Fe (wt%) T2 cutoff (msec)0 < 4 304 - 6 20 > 6 10

NMR CORE PLUG IRREDUCIBLESATURATION COMPARED TO LOGSATURATION

Following the evaluation of iron content and effect onthe NMR T2 cutoff in Well 2 we decided to proceedwith using the standard 30 msec T2 cutoff for analysisof irreducible water saturation and permeability whileacknowledging that in iron-rich rocks, the irreduciblewater saturation could be high by 0.19. Figure 2shows in track 2 a comparison of the total watersaturation derived from logs, capillary pressureAir/Brine Swi and NMR Swi. It can be seen that inthe low clay content dolomitic sandstone below 2840metres, NMR Swi agrees well with core and logsaturations. Above 2840 metres, in the glauconiticsandstone reservoir, NMR Swi overestimates Air/BrineSwi as expected.

Permeability estimation from NMR was derived fromthe relationship between irreducible water saturationand permeability shown in Figure 8. This relationshiptakes the form shown in Equation 5 (Timur, 1969).

kNMR = B βt (5)

where B and t are empirical constants 0.15 and 2.5.The NMR parameter, β is defined by

β = Swi-2 (6)

Core plug permeability compares well to NMRestimated permeability (Figure 2, track 4). It isimportant to note that the relationship of irreduciblewater saturation to permeability is independent of thedepositional facies, which was not the case observedfor the porosity-permeability relationships (Figure 7a).

NMR LOG MEASUREMENTS COMPARED TOCORE

Following successful validation of NMR T2 relaxationto measure irreducible water saturation and estimatepermeability in mineralogically complex sandstones,

SPWLA 36th Annual Logging Symposium, June 26-29, 1995˝

-5-

Well 3 was drilled and logged with an NMR tool. Thiswas the first new-generation, pulsed NMR tool to berun in Australia. The entire reservoir wasconventionally cored, and additional NMR core plugmeasurements were taken to validate the accuracy ofthe log measurements. The NMR log along with coreplug measurements from Well 3 are shown in Figure15.

The reservoir interval encountered at first appeared tobe of similar quality to that in Well 1 (Figure 1). Oilshows in the core indicated that this sandstone was oilbearing and it was known that a common field oil-water contact should be present at 2859 metres.Computed porosities were similar to Well 1, but thecalculated water saturation was 0.80 as compared to0.55. A production test was originally planned to testthe productivity of the glauconitic sand because of theuncertainty in reservoir quality. Thus, significant costsavings could be realised if NMR log measurementscould be confidently used to quantify producibleporosity and permeability.

In the case under discussion, operational problemscontributed to marginal NMR log quality with poorrepeatability. Although the NMR log quality was poor,the log data could still be used on a zone-average basisfor comparison to core NMR. Even though the NMRtool was logged in a 12.25 inch wellbore, the lowoperating frequency (530 kHz) placed the sensitivemeasurement volume at an 18 inch diameter. Only in asevere washout below 2860 metres (Figure 15) did thelog record mud readings, with corresponding invalidhigh NMR porosity and permeability measurements.

Ten core plugs were measured using the same NMRspectrometer as was used for the Well 2 plugs. The T2experiments were repeated 3 times using the followinginter echo spacings and magnetic field: 0.5 msecHomogeneous, 0.5 msec Gradient, and 2.0 msecGradient. The purpose of the three experiments was tomeasure the maximum porosity in the core plug usingthe shortest inter echo spacing available at 0.5 msec,while replicating the logging tool which operates at a2.0 msec inter echo spacing in a gradient field. The0.5 msec NMR porosity should replicate core porosityby measuring the fast T2 relaxing components in theclay microporosity (Borgia, 1994) while the 2.0 msecporosity data should be less than total porosity (minusclay microporosity). Only the 0.5 msec homogeneousfield NMR core plug measurements are reviewed inthis paper (Table 2).

The NMR well log and core data are shown in Figure15. Both total porosity from forward modeling andNMR plug porosity compare well to core porosity(track 2). The NMR log porosity varies betweenforward modeled log total and effective porosity. In asmuch as the NMR log inter echo spacing is 2.0 msec,some fraction of the clay microporosity will not bemeasured, and the log should be similar to effectiveporosity as is the case between 2856 to 2862 metres.Above 2862 metres, however, the log measures closerto forward modeled log total porosity. Permeabilitywas estimated using both the Coates and SchlumbergerT2 relationship in Equations 7 and 8.

kce = (φNMR/10)4 (FFI/BVI)2 (7)

kse = 4.6 (φNMR/100)4 (T2g)2 (8)

Track 3 shows the excellent match between computedpermeabilities from the NMR log and NMR core plugsand measured core permeability. The permeability,which is below 1 md in this reservoir, is an order ofmagnitude lower than that measured in Well 1 whichproduction tested 1500 bpd oil. This information, inaddition to wellsite core plug permeability andformation tester pressures, supported the decision toabandon the planned production test on this well.

Reservoir average values of forward modeled log totaland effective porosity, core porosity, NMR logporosity, and NMR core porosity are shown in Figure16. Both the core porosity and NMR core porosity aremeasured at ambient surface pressure. We wouldexpect these values to be around 5 percent lower atoverburden confining pressure and would give betteragreement to log total porosity.

EFFECT OF IRON ON SURFACE RELAXATION

Measurements of high-pressure (60,000 psi) MercuryInjection Capillary Pressure (MICP) provides thesurface to volume data necessary in computing NMRsurface relaxation. Equation 4 shows the relationshipof surface relaxation in microns/second derived fromNMR T2 relaxation and the surface to volume ratiofrom core samples. Table 3 show these measurementsperformed on core plugs from Well 2 and Well 3.

NMR surface relaxivity is seen to be a function ofsandstone iron content (Figure 17). The surfacerelaxivity varies from 1.0 micron/sec for a low ironcontent sandstone to 3.9 microns/sec for a glauconiticsandstone with 14 percent iron. The scatter in surfacerelaxivity is consistent with the fact that it is not bulk

SPWLA 36th Annual Logging Symposium, June 26-29, 1995

-6-

iron concentration but surface iron concentration thatis the control on relaxation. As rock iron contentincreases, a well defined trend in increasing surfacerelaxivity is observed. A four fold increase in surfacerelaxivity will reduce T2g to one quarter its originalvalue. This change in T2g will reduce thepermeability that is computed using the Schlumbergeror Coates relationships which are dependent on T2gand BVI respectively. However, the NMRpermeability estimates in Figure 15 show good matchto core permeability.

CONCLUSIONS

Measured NMR surface relaxivity ranges from 1micron/sec in low iron content sandstones to 3.9microns/sec in glauconitic sandstones with as much as14 percent iron. Nonconstant surface relaxivity hasthe effect of reducing NMR T2g relaxation times by asmuch as one quarter the value of a low iron contentsample. Lowering of the T2 cutoff is required forcorrect partitioning of irreducible fluid fromproducible fluid. If this factor is not taken intoaccount, reduction of T2 relaxation times increases thecomputed irreducible water saturation relative tomeasured drainage capillary pressure water saturation.The T2 cutoff required adjustment from 30 msec to 20msec to match capillary pressure water saturationwhen iron content was greater than 4 percent. Anotheradverse effect of high iron content is that permeabilitywill be under-estimated when using the Schlumberger(dependent on T2g) or Coates relationship (dependenton T2 cutoff).

The significant iron-bearing minerals in thesesandstones were glauconite, chlorite, pyrite, andsiderite. Using a 30 msec T2 cutoff, the NMRsaturation error was 0.19 saturation high compared toAir/Brine Swi in the highest iron content glauconiticsandstones, with the error approaching zero as ironcontent decreases. In general, however, coremeasurements of NMR porosity, irreducible watersaturation, and permeability agree well with coreanalysis porosity, air/brine drainage capillary pressure,and permeability.

The ability of NMR to measure the surface to volumeratio of reservoir rocks leads to good estimation ofpermeability when a core calibration set is available.We have shown that both Coates and Schlumbergerpermeability relationships perform well for estimatingpermeability from core NMR. This information isnecessary to estimate well productivity and can result

in significant savings by reducing the need forexpensive production well tests and/or coring.

SPWLA 36th Annual Logging Symposium, June 26-29, 1995˝

-7-

NOMENCLATURE

A total NMR T2 echo signal amplitude, (mv)Ai relative amplitude of relaxation time T2iBVI NMR bulk volume irreducible fluid, (p.u.)FFI NMR log free fluid index, (p.u.)i i th poreK NMR porosity calibration constantkce NMR Coates permeability, (md)kNMR NMR permeability estimate, (md)kse Schlumberger permeability estimate, (md)microns 10-6 metresφNMR NMR porosity, (p.u.)φp producible porosity, (p.u.)φt total interconnected porosity, (p.u.)ρ NMR surface relaxivity, (microns/sec)p.u. porosity units, percent bulk volumeS pore surface area, (micron2)Swi irreducible water saturation, (fraction)T2 transverse relaxation time, (msec)T2co T2 cutoff, (msec)T2g geometric mean T2, (msec)V pore volume, (micron3)

ACKNOWLEDGEMENTS

The authors are grateful to the following persons fortheir contributions to this paper. Hans Thomann andMarco Duran, Exxon Research and Engineering. BobKlimentidis, Dave Pevear, and John Longo, ExxonProduction Research. Dale Fitz, Esso ProductionMalaysia. Duncan Mardon, NUMAR Corporation.Chris Straley, Schlumberger Doll Research. AdemDjakic, Andy Mills, and John Phillips of EssoAustralia. Special thanks to Esso Australia Ltd.,Exxon Production Research Company, ExxonExploration Company, and BHPP Pty. Ltd. forpermission to publish this paper.

REFERENCES

Borgia G.C., 1994, "A new Un-free fluid index insandstones through NMR studies", SPE 69th AnnualConference, September, SPE 28366.

Farrar, T.C., Becker, E.D., 1971, "Pulse and FourierTransform NMR introduction to theory and methods",Academic Press, New York, pp 22-28.

Kleinberg, R.L., etal, 1993, "Nuclear MagneticResonance of Rocks", SPE 68th Annual Conference,October, SPE 26470.

Morriss, C.E., etal, 1993, "Field Test of anexperimental pulsed nuclear magnetism tool", SPWLA34th Annual Logging Symposium, June 13-16, paperGGG.

Timur, A., 1969, "Pulsed Nuclear Magnetic ResonanceStudies of Porosity, Moveable Fluid and Permeabilityof Sandstones", SPE Journal of Petroleum Technology,June, pp 775-786.

ABOUT THE AUTHORS

Scott Dodge, presently a Senior Petrophysicist withEsso Australia Ltd. in Melbourne, Australia received aBSc. degree in Mechanical Engineering from KansasState University in 1979 and a MSc. degree inPetroleum Engineering from the University ofSouthern California in 1982. He has been with Exxonfor the past 13 years as a Formation EvaluationSpecialist.

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 16years.

Angel G. Guzman-Garcia received his Ph.D. degree inChemical Engineering from Tulane University. Hejoined Exxon Production Research in 1990 and hasmodeled SP and resistivity tools in shaly sands. Hiscurrent assignment is in the acquisition andinterpretation of NMR for estimation of petrophysicalparameters.

SPWLA 36th Annual Logging Symposium, June 26-29, 1995

-8-

Table I MINQUANT MINERAL XRD/XRF ANALYSES (wt%)

PLUG # QUARTZ CARBONATE PYRITE GLAUCONITE KAOLINITE ILLITE SMECTITE TOTAL CLAY

Well 2 *Note Carbonate in Well 2 is primarily Dolomite.

1 71 4 0 13 1 2 2 18

2 56 1 1 15 1 8 4 28

3 74 0 1 6 1 1 1 8

4 48 1 0 16 3 11 4 34

5 54 0 2 12 3 9 4 28

6 49 1 7 11 5 10 3 29

7 60 1 1 8 2 8 3 21

8 66 0 2 12 1 3 2 18

9 44 1 8 15 3 11 2 32

10 55 0 3 12 0 9 5 26

11 58 0 3 14 0 7 2 23

12 77 0 0 6 1 0 1 8

13 71 1 0 6 0 2 2 10

14 70 14 0 3 0 0 2 6

15 61 22 0 5 0 1 1 7

Well 3 *Note Carbonate in Well 3 is primarily Siderite (Iron carbonate).

2 53 1 0 22 3 6 4 35

6 36 26 0 18 3 6 6 33

12 49 3 5 21 2 8 4 35

13 50 2 0 30 3 1 4 38

14 47 4 0 26 6 2 4 38

17 49 7 1 20 0 9 5 34

22 50 1 0 20 1 5 7 33

25 53 4 0 31 2 4 4 41

28 52 5 1 31 1 3 4 39

34 52 12 0 29 0 2 3 34

Table 2 Petrophysical Properties of NMR Care Plugs

PLUG # AMS BUOYANT AMB NMR 0.5ms AIR/BRINE T2oo 10ms T2oo 20ms T2oo 30ms T2oo 40ms

PERMEABILITY POROSITY POROSITY (1) Swi @ 50 PSI NMP Swi NMR Swi NMR Swi NMR Swi

Well 2 (md) (p.u.) (p.u.) (frac) (frac) (frac) (frac) (frac)

1 134.00 23.6 23.3 0.46 0.39 0.45 0.50 0.55

2 3.40 23.1 22.9 0.56 0.53 0.62 0.71 0.78

3 2540.00 28.0 27.7 0.12 0.07 0.09 0.12 0.14

4 0.90 25.9 25.6 0.70 0.66 0.74 0.81 0.85

5 0.56 22.4 22.1 0.65 0.56 0.66 0.74 0.80

6 0.12 18.9 18.7 0.78 0.73 0.83 0.91 0.97

7 905.00 30.8 30.5 0.25 0.16 0.20 0.24 0.27

8 1024.00 31.1 30.7 0.23 0.18 0.22 0.26 0.28

9 0.17 23.1 22.8 0.77 0.78 0.89 0.96 0.99

10 4.54 26.8 26.6 0.46 0.36 0.45 0.54 0.62

11 14.80 23.6 23.4 0.42 0.42 0.60 0.74 0.82

12 4235.00 26.4 26.1 0.12 0.07 0.10 0.13 0.14

13 2413.00 30.0 29.6 0.13 0.08 0.10 0.12 0.14

14 2231.00 20.5 20.3 0.12 0.09 0.10 0.12 0.13

15 262.00 9.2 9.1 0.27 0.21 0.25 0.27 0.28

SPWLA 36th Annual Logging Symposium, June 26-29, 1995˝

-9-

Well 3

13 1.97 22.1 23.1 n.m. 0.64 0.75 0.80 0.93

14 0.04 18.5 19.4 n.m. 0.82 0.91 0.95 0.97

17 0.41 20.7 21.9 n.m. 0.73 0.83 0.86 0.89

22 0.02 21.5 21.1 n.m. 0.84 0.89 0.91 0.94

25 0.04 21.2 20.9 n.m. 0.84 0.92 0.93 0.94

28 0.02 20.3 21.4 n.m. 0.88 0.93 0.94 0.95

34 0.01 17.6 18.7 n.m. 0.87 0.94 0.95 0.96

NOTE (1): NMR rescaled for sample calibration.

Table 3 Surface Relaxivity and Iron Content

PLUG # Fe203 Surf / Vol T2 Surface

XRF MICP Geom Relaxivity

Well 2 (wt %) (1 / microns) (msec) (microns/sec)

1 4.8 64.6 7.2 2.1

2 5.3 83.8 4.3 2.8

3 2.0 9.4 115.0 0.9

4 4.5 110.0 5.8 1.6

5 4.3 75.1 6.1 2.2

6 7. 8 96.5 2.7 3.8

7 3.0 26.1 46.5 0.8

8 4.0 29.9 40.4 0.8

9 9.5 109.4 2.4 3.8

10 5.1 65.9 9.7 1.6

11 5.6 61.9 8.9 1.8

12 1.7 10.7 90.5 1.0

13 1.9 10.4 96.0 1.0

14 1.3 15.0 111.0 0.6

15 1.4 26.4 38.4 1.0

Well 3

2 5.8 108.60 6.3 1.5

6 17.3 174.24 3.4 1.7

12 9.7 132.64 5.0 1.5

25 9.8 157.31 3.3 1.9

34 13.8 149.94 1.7 3.9

SPWLA 36th Annual Logging Symposium, June 26-29, 1995

-10-

SPWLA 36th Annual Logging Symposium, June 26-29, 1995˝

-11-

SPWLA 36th Annual Logging Symposium, June 26-29, 1995

-12-

SPWLA 36th Annual Logging Symposium, June 26-29, 1995˝

-13-

SPWLA 36th Annual Logging Symposium, June 26-29, 1995

-14-

SPWLA 36th Annual Logging Symposium, June 26-29, 1995˝

-15-

SPWLA 36th Annual Logging Symposium, June 26-29, 1995

-16-