Spwla95 paper o

SPWLA 36th Annual Logging Symposium, June 26-29, 1995
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CORE AND LOG NMR MEASUREMENTS OF AN IRON-RICH,
GLAUCONITIC SANDSTONE RESERVOIR
WM. SCOTT DODGE SR
ESSO AUSTRALIA LTD., MELBOURNE, VICTORIA, AUSTRALIA

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

ABSTRACT difficulty in determining a realistic porosity-
permeability relationship. This mineralogically
NMR porosity and relaxation time measurements from complex reservoir, deposited in Eocene age offshore
an iron-rich, glauconitic sandstone reservoir show marine channels, contains significant amounts of iron-
quantifiable effects of mineral iron content on NMR bearing detrital glauconite, matrix clays, and
T2 relaxation times. This result has significant impact authigenic chlorite, dolomite cement and siderite
upon measuring irreducible water pore volume where replacement. The dominant controls on reservoir
the surface relaxation mechanism is nonconstant. porosity and permeability are grain size, clay matrix,
Centrifuge air/brine drainage capillary pressure and the amount of microporosity in dissolving
measurements show that the standard 30 msec T2 feldspars, glauconite, and clay matrix.
cutoff must be lowered to calibrate irreducible water
saturation computed from NMR. Although the effects The first well (Well 1) drilled into the reservoir
of iron are observable on T2 distributions, permeability penetrated a 30 metre oil column. The petrophysical
estimation from NMR, using either the Coates or evaluation (Figure 1) to determine porosity, water
Schlumberger relationships, show excellent agreement saturation and permeability, integrated core analysis,
to permeability on core plugs. mineralogy, drainage capillary pressure measurements
and conventional wireline logs. Above the oil-water
Quantitative mineral composition on core plugs using transition zone (i.e., above 2927 metres) the average
both XRD and XRF, show iron-rich glauconite to vary total water saturation was 55 percent. Owing to the
from 3 to 31 weight percent. The bulk rock total iron poor reservoir quality and high water saturation, the
oxide content ranges from 1 to 17 weight percent. well was production tested, and flowed oil at 1500 bpd
High iron content within this reservoir raised concern (barrels per day) with no evidence of formation water.
that NMR surface relaxation would be affected, Drainage capillary pressure measurements confirmed
leading to errors in irreducible water saturation and that the high water saturation was irreducible and, as
producible porosity derived from NMR measurements. indicated by the production test, would not be
produced.
NMR measurements were acquired using a pulsed field
gradient logging tool operating at 530 kHz and on core A second well in the field (Well 2) penetrated an older
plugs with a 1000 kHz laboratory spectrometer. reservoir containing a similar glauconitic sandstone,
Homogenous field NMR core plug measurements are underlain by a high reservoir-quality, partially
used to show the accuracy of the logging tool to dolomitised sandstone with multidarcy permeability.
measure NMR porosity, and permeability. This well (Figure 2) was production-tested sequentially
over the two intervals, flowing water-free oil at 6640
INTRODUCTION bpd from the lower sand, and 5660 bpd from the poor-
quality upper reservoir. The entire reservoir sand was
Conventional methods using logs to determine net pay, conventionally cored and an extensive reservoir
effective porosity, water saturation, and producibility characterisation programme was undertaken to
proved ineffective in an iron-rich glauconitic accurately determine the formation mineralogy and
sandstone oil reservoir recently drilled in Australia. petrophysical properties.
Production tests costing in the order of A$1.5m have
been required to determine the producibility owing to

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As part of the reservoir characterisation programme,
laboratory Nuclear Magnetic Resonance (NMR) An SEM image (Figure 4) at x5000 magnification
measurements were conducted on 15 core plugs from shows highly crystalline microporous chlorite. The
Well 2. These measurements were undertaken to micropores range from 8 microns to sub-micron size.
assess the ability of NMR to measure porosity, The maximum capillary pressure in this reservoir is 50
irreducible water saturation, and permeability in this psi air/brine equivalent corresponding to a 0.5 micron
mineralogically complex reservoir. If successful, the pore-throat size, and thus much of this microporosity
NMR logging tool could be used to log future wells in is accessible to hydrocarbons. Figure 5 shows a high-
the development of the field to reduce the need for magnification thin-section photomicrograph of a green
expensive production tests and conventional core. We glauconite grain. In the backscatter SEM image x1000
were concerned, however, by the high iron content of magnification of this same glauconite grain (Figure 6),
the reservoir rocks. The laboratory measurements intragranular porosity is visible as black in the image.
subsequently confirmed that NMR could be used to The micropores within this grain range in size from 10
measure valid reservoir petrophysical parameters when microns down to sub-micron. The glauconite
calibrated to air/brine capillary pressure saturation. microporosity averages 21 percent grain volume as
measured by MICROQUANT.
The successful laboratory results in Well 2 supported
the running of an NMR logging tool in the third well Fifteen core plugs from Well 2 in Figure 2 were
drilled in this field. The well was conventionally analysed using MINQUANT. The results (Table 1)
cored and comparisons of the log measurements with showed quartz content ranging from 77 to 44 on a
NMR core plug measurements were performed in grain weight percent basis, and total clay mineral
order to assess the quality of the log data. content to be as high as 34 percent. Dense iron-
bearing minerals identified in these samples are
CHARACTERISATION OF RESERVOIR glauconite and pyrite. The bulk iron content from XRF
MINERALOGY in these samples ranges from 1.3 to 9.5 weight percent.
The diagenetic iron-bearing chlorite identified in SEM
Quantifying formation mineralogy was the first step to is included in the glauconite fraction determined from
building a petrophysical model for this complex MINQUANT.
reservoir rock. A programme was developed
incorporating measurements such as Petrographic CHARACTERISATION OF RESERVOIR
analysis, intragranualar microporosity PETROPHYSICS
(MICROQUANT), Scanning Electron Microscopy
(SEM), and quantitative mineralogy (MINQUANT). Prediction of formation productivity is difficult where
MINQUANT and MICROQUANT are programmes there is a weak correlation between porosity and
developed at Exxon Production Research Company. permeability as is the case in these mineralogically
MINQUANT uses X-ray diffraction (XRD) and X-ray complex sandstone reservoirs. The ability to predict
fluorescence (XRF) elemental chemical analysis to productivity is important in order to determine
quantify mineralogy. MICROQUANT uses whether a reservoir sequence is able to deliver
backscattered electron images to quantify intragranular hydrocarbons at economic rates. Figure 7a shows the
microporosity. porosity to permeability relationship for Well 2. The
two reservoirs in this well are represented by two
The large difference between total and effective different relationships.
porosity on the computed well log responses in Well 1
(Figure 1), indicated that the reservoir rocks contain In Well 2 (Figure 2), the dolomitic sandstone from
significant quantities of microporous clay as well as 2840 to 2862 metres has porosity that varies from 4 to
thin beds of dense siderite minerals. A thin-section 27 percent, whereas permeability remain uniformly
photomicrograph (Figure 3) shows the presence of above 2000 md. Thin-sections show this reservoir to
green glauconite grains which are the same size as be a quartzose sandstone with clay content less than 10
quartz grains in this sample. Additionally, clay rich percent. The multidarcy sandstone contains varying
sedimentary rock fragments and diagenetic chlorite are amounts of diagenetic dolomite cement filling the
present, and both contain intragranular microporosity. intergranular pore volume. The dolomitisation does
The size of the intergranular pores (blue) is as large as not ensure that occluded porosity also reduces
80 microns. permeability.

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reduce the intergranular pore space upon compaction
The glauconitic sandstone from 2825 to 2840 metres with burial.
in the same well shows a more linear trend of porosity
with permeability. The opposite phenomena to the EFFECT OF IRON ON NMR T2 RELAXATION
deeper sand occurs in this reservoir in that minor AND IRREDUCIBLE WATER SATURATION
changes in porosity can correspond to two orders of
magnitude change in permeability. The two reservoirs NMR T2 relaxation measurements were taken on the
exhibit dramatically different porosity-permeability fifteen core plugs whose porosity and permeability
relationships, and it is this uncertainty that can lead to characteristics are shown in Figure 7b. A laboratory
significant errors in estimating permeability. NUMALOG CORESPEC spectrometer operating at
1000 kHz recorded the CPMG pulse train echoes
Fifteen core plugs were selected to represent both (Farrar, 1971) of hydrogen protons in the field of
reservoir facies for NMR measurements (Figure 7b). transverse magnetisation, T2. These amplitude versus
Core analysis for each of these plugs (Table 2) show time measurements were acquired in an applied
the variability of porosity and permeability in these oil- homogeneous magnetic field with an inter echo
bearing sandstones. The majority of the samples have spacing of 0.5 milliseconds and a range of repetition
an average grain density greater than that of quartz times from 1 to 20 seconds. A sandstone with variable
(2.65 g/cc) because of the presence of denser minerals: pore size yields a T2 relaxation decay curve that is the
e.g. glauconite (2.85 g/cc), dolomite (2.85 g/cc), and sum of single exponentials with each term
pyrite (4.99 g/cc). corresponding to a particular pore size (Equation 2).

Centrifuge air/brine drainage capillary pressure was A(t) = Aie (-t/T2i) (2)
measured using 222 x 254 millimetre core plugs. The
samples were spun at a centrifuge speed equivalent to Where Ai is proportional to the proton population of
the 50 psi air/brine capillary pressure in the 30 metre pores having a relaxation time of T2i. The T2
oil column. The water saturation obtained at this amplitude spectra for five of the fifteen core plugs,
pressure is defined to be equivalent to the irreducible shown in Figure 10, represent a range of permeability
water saturation in the reservoir. Coincidentally this from 3.4 md to 4235 md. As permeability increases,
50 psi air/brine capillary pressure is the same as that T2g also increases from a low of 4.3 msec for the low
used by Timur (1969) to define producible porosity. permeability sample, up to 90 msec for the high
Timur's relationship was used (Equation 1), with permeability sample. Integration of the amplitude
substitution of the irreducible water saturation as spectra yields NMR porosity (Equation 3).
determined at the maximum capillary pressure in the
reservoir, to define the pore volume containing mobile
fluids (hydrocarbons and connate water).
φNMR = K Σ Ai (3)

The impact of mineral iron content is reflected in the
φp = φt (1-Swi) (1)
surface relaxivity term (ρ) which relates T2 relaxation
Table 2 shows that the centrifuge irreducible water time to pore surface area and pore volume (Equation
saturation ranges from 0.12 to 0.78. Figure 8 shows 4).
that irreducible water saturation is closely related to
permeability (r2=0.96) and can be used as an estimate T2-1 = ρ (S/V) (4)
of reservoir permeability.
If the surface relaxivity is nonconstant, then the ability
Increasing iron content is associated with lower of T2g to purely reflect surface to volume
permeability samples illustrated in Figure 9. When characteristics (i.e. mobile vs non-mobile fluids) is not
iron content exceeds 4 percent, the minerals valid. An increase of surface relaxation will directly
contributing the most to high iron content are siderite, impact T2g by shifting the relaxation distribution to
glauconite and chlorite. Chlorite is a diagenetic pore- shorter times. Integration of the T2 amplitude
filling clay which directly impacts fluid flow through distribution may still reflect porosity, although the
the pore system. The glauconite is a detrital framework selection of a T2 cutoff for partitioning Bulk Volume
grain which does not impact permeability as severely Irreducible (BVI) fluid from producible fluid may
as chlorite. The glauconite, however, is ductile and can change. It has been shown in several studies of

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sandstones (Morriss, 1993, Kleinberg, 1993) that a T2 After a review of these data we can suggest the
cutoff time of approximately 30 msec, when applied to following general guidelines for appropriate T2 cutoff
T2 distributions, reflects the irreducible water times in iron-bearing glauconitic-rich sandstones.
saturation as measured by drainage capillary pressure.
Fe (wt%) T2 cutoff (msec)
NMR irreducible water saturation was computed from 0 < 4 30
the T2 distribution curve by selecting a T2 cutoff time 4 - 6 20
at 10, 20, 30 and 40 msec (Table 2). The ratio of the > 6 10
area under the curve below the T2 cutoff, to the total
area under the curve, is the irreducible water NMR CORE PLUG IRREDUCIBLE
saturation from NMR. Figure 11 shows NMR SATURATION COMPARED TO LOG
irreducible water saturation, and 50 psi air/brine SATURATION
capillary pressure water saturation for each T2 cutoff.
It is apparent that the low permeability samples with Following the evaluation of iron content and effect on
high irreducible water saturation (above 0.40) have a the NMR T2 cutoff in Well 2 we decided to proceed
significant proportion of their pore volume in the with using the standard 30 msec T2 cutoff for analysis
range of 10 to 40 msec. As the T2 cutoff changes, a of irreducible water saturation and permeability while
large change is observed in Swi. The high acknowledging that in iron-rich rocks, the irreducible
permeability samples have very few small pores in the water saturation could be high by 0.19. Figure 2
range of 10 to 40 msec, with the majority of the pores shows in track 2 a comparison of the total water
at higher T2 times. saturation derived from logs, capillary pressure
Air/Brine Swi and NMR Swi. It can be seen that in
IRON CONTENT, T2 CUTOFF AND THE the low clay content dolomitic sandstone below 2840
ERROR ON NMR IRREDUCIBLE WATER metres, NMR Swi agrees well with core and log
SATURATION saturations. Above 2840 metres, in the glauconitic
sandstone reservoir, NMR Swi overestimates Air/Brine
Figures 12 through 14 show the difference between Swi as expected.
NMR Swi and Air/Brine Swi as a function of iron
content for a T2 cutoff of 30, 20, and 10 msec. Figure Permeability estimation from NMR was derived from
12 shows for a T2 cutoff of 30 msec, the error is 0.01 the relationship between irreducible water saturation
in NMR Swi for samples with less than 4 percent iron. and permeability shown in Figure 8. This relationship
For samples with higher iron content, the error in takes the form shown in Equation 5 (Timur, 1969).
NMR Swi is as much as 0.19. These data places an
upper bound on the error in NMR Swi in these kNMR = B βt (5)
glauconitic sandstones when using the standard T2
cutoff of 30 msec. where B and t are empirical constants 0.15 and 2.5.
The NMR parameter, β is defined by
The iron content increases NMR surface relaxation,
which in turn shifts the T2 distribution to lower times. β = Swi-2 (6)
Therefore the T2 cutoff would have to shift to lower
times to maintain calibration of NMR Swi to Air/Brine Core plug permeability compares well to NMR
Swi. Figure 13 shows that with a 20 msec T2 cutoff estimated permeability (Figure 2, track 4). It is
the error in NMR Swi is -0.03 for samples with iron important to note that the relationship of irreducible
content less than 4 percent. The majority of the water saturation to permeability is independent of the
samples with higher iron content contain an error of depositional facies, which was not the case observed
less than 0.05. for the porosity-permeability relationships (Figure 7a).

By reducing the T2 cutoff to 10 msec (Figure 14), most NMR LOG MEASUREMENTS COMPARED TO
samples underestimate Air/Brine Swi, with errors CORE
ranging from -0.03 to -0.10. It would be reasonable to
use a T2 cutoff of 10 msec for reservoir rocks with Following successful validation of NMR T2 relaxation
more than 6 percent iron. to measure irreducible water saturation and estimate
permeability in mineralogically complex sandstones,

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Well 3 was drilled and logged with an NMR tool. This The NMR well log and core data are shown in Figure
was the first new-generation, pulsed NMR tool to be 15. Both total porosity from forward modeling and
run in Australia. The entire reservoir was NMR plug porosity compare well to core porosity
conventionally cored, and additional NMR core plug (track 2). The NMR log porosity varies between
measurements were taken to validate the accuracy of forward modeled log total and effective porosity. In as
the log measurements. The NMR log along with core much as the NMR log inter echo spacing is 2.0 msec,
plug measurements from Well 3 are shown in Figure some fraction of the clay microporosity will not be
15. measured, and the log should be similar to effective
porosity as is the case between 2856 to 2862 metres.
The reservoir interval encountered at first appeared to Above 2862 metres, however, the log measures closer
be of similar quality to that in Well 1 (Figure 1). Oil to forward modeled log total porosity. Permeability
shows in the core indicated that this sandstone was oil was estimated using both the Coates and Schlumberger
bearing and it was known that a common field oil- T2 relationship in Equations 7 and 8.
water contact should be present at 2859 metres.
Computed porosities were similar to Well 1, but the kce = (φNMR/10)4 (FFI/BVI)2 (7)
calculated water saturation was 0.80 as compared to kse = 4.6 (φNMR/100)4 (T2g)2 (8)
0.55. A production test was originally planned to test
the productivity of the glauconitic sand because of the Track 3 shows the excellent match between computed
uncertainty in reservoir quality. Thus, significant cost permeabilities from the NMR log and NMR core plugs
savings could be realised if NMR log measurements and measured core permeability. The permeability,
could be confidently used to quantify producible which is below 1 md in this reservoir, is an order of
porosity and permeability. magnitude lower than that measured in Well 1 which
production tested 1500 bpd oil. This information, in
In the case under discussion, operational problems addition to wellsite core plug permeability and
contributed to marginal NMR log quality with poor formation tester pressures, supported the decision to
repeatability. Although the NMR log quality was poor, abandon the planned production test on this well.
the log data could still be used on a zone-average basis
for comparison to core NMR. Even though the NMR Reservoir average values of forward modeled log total
tool was logged in a 12.25 inch wellbore, the low and effective porosity, core porosity, NMR log
operating frequency (530 kHz) placed the sensitive porosity, and NMR core porosity are shown in Figure
measurement volume at an 18 inch diameter. Only in a 16. Both the core porosity and NMR core porosity are
severe washout below 2860 metres (Figure 15) did the measured at ambient surface pressure. We would
log record mud readings, with corresponding invalid expect these values to be around 5 percent lower at
high NMR porosity and permeability measurements. overburden confining pressure and would give better
agreement to log total porosity.
Ten core plugs were measured using the same NMR
spectrometer as was used for the Well 2 plugs. The T2 EFFECT OF IRON ON SURFACE RELAXATION
experiments were repeated 3 times using the following
inter echo spacings and magnetic field: 0.5 msec Measurements of high-pressure (60,000 psi) Mercury
Homogeneous, 0.5 msec Gradient, and 2.0 msec Injection Capillary Pressure (MICP) provides the
Gradient. The purpose of the three experiments was to surface to volume data necessary in computing NMR
measure the maximum porosity in the core plug using surface relaxation. Equation 4 shows the relationship
the shortest inter echo spacing available at 0.5 msec, of surface relaxation in microns/second derived from
while replicating the logging tool which operates at a NMR T2 relaxation and the surface to volume ratio
2.0 msec inter echo spacing in a gradient field. The from core samples. Table 3 show these measurements
0.5 msec NMR porosity should replicate core porosity performed on core plugs from Well 2 and Well 3.
by measuring the fast T2 relaxing components in the
clay microporosity (Borgia, 1994) while the 2.0 msec NMR surface relaxivity is seen to be a function of
porosity data should be less than total porosity (minus sandstone iron content (Figure 17). The surface
clay microporosity). Only the 0.5 msec homogeneous relaxivity varies from 1.0 micron/sec for a low iron
field NMR core plug measurements are reviewed in content sandstone to 3.9 microns/sec for a glauconitic
this paper (Table 2). sandstone with 14 percent iron. The scatter in surface
relaxivity is consistent with the fact that it is not bulk

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iron concentration but surface iron concentration that in significant savings by reducing the need for
is the control on relaxation. As rock iron content expensive production well tests and/or coring.
increases, a well defined trend in increasing surface
relaxivity is observed. A four fold increase in surface
relaxivity will reduce T2g to one quarter its original
value. This change in T2g will reduce the
permeability that is computed using the Schlumberger
or Coates relationships which are dependent on T2g
and BVI respectively. However, the NMR
permeability estimates in Figure 15 show good match
to core permeability.

CONCLUSIONS

Measured NMR surface relaxivity ranges from 1
micron/sec in low iron content sandstones to 3.9
microns/sec in glauconitic sandstones with as much as
14 percent iron. Nonconstant surface relaxivity has
the effect of reducing NMR T2g relaxation times by as
much as one quarter the value of a low iron content
sample. Lowering of the T2 cutoff is required for
correct partitioning of irreducible fluid from
producible fluid. If this factor is not taken into
account, reduction of T2 relaxation times increases the
computed irreducible water saturation relative to
measured drainage capillary pressure water saturation.
The T2 cutoff required adjustment from 30 msec to 20
msec to match capillary pressure water saturation
when iron content was greater than 4 percent. Another
adverse effect of high iron content is that permeability
will be under-estimated when using the Schlumberger
(dependent on T2g) or Coates relationship (dependent
on T2 cutoff).

The significant iron-bearing minerals in these
sandstones were glauconite, chlorite, pyrite, and
siderite. Using a 30 msec T2 cutoff, the NMR
saturation error was 0.19 saturation high compared to
Air/Brine Swi in the highest iron content glauconitic
sandstones, with the error approaching zero as iron
content decreases. In general, however, core
measurements of NMR porosity, irreducible water
saturation, and permeability agree well with core
analysis porosity, air/brine drainage capillary pressure,
and permeability.

The ability of NMR to measure the surface to volume
ratio of reservoir rocks leads to good estimation of
permeability when a core calibration set is available.
We have shown that both Coates and Schlumberger
permeability relationships perform well for estimating
permeability from core NMR. This information is
necessary to estimate well productivity and can result

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NOMENCLATURE Morriss, C.E., etal, 1993, "Field Test of an
experimental pulsed nuclear magnetism tool", SPWLA
A total NMR T2 echo signal amplitude, (mv) 34th Annual Logging Symposium, June 13-16, paper
Ai relative amplitude of relaxation time T2i GGG.
BVI NMR bulk volume irreducible fluid, (p.u.)
FFI NMR log free fluid index, (p.u.) Timur, A., 1969, "Pulsed Nuclear Magnetic Resonance
i ith pore Studies of Porosity, Moveable Fluid and Permeability
K NMR porosity calibration constant of Sandstones", SPE Journal of Petroleum Technology,
kce NMR Coates permeability, (md) June, pp 775-786.
kNMR NMR permeability estimate, (md)
kse Schlumberger permeability estimate, (md) ABOUT THE AUTHORS
microns 10-6 metres
φNMR NMR porosity, (p.u.) Scott Dodge, presently a Senior Petrophysicist with
φp producible porosity, (p.u.) Esso Australia Ltd. in Melbourne, Australia received a
φt total interconnected porosity, (p.u.) BSc. degree in Mechanical Engineering from Kansas
ρ NMR surface relaxivity, (microns/sec) State University in 1979 and a MSc. degree in
p.u. porosity units, percent bulk volume Petroleum Engineering from the University of
S pore surface area, (micron2) Southern California in 1982. He has been with Exxon
Swi irreducible water saturation, (fraction) for the past 13 years as a Formation Evaluation
T2 transverse relaxation time, (msec) Specialist.
T2co T2 cutoff, (msec)
T2g geometric mean T2, (msec) John Shafer presently is a Senior Research Specialist
V pore volume, (micron3) in the Reservoir Division of Exxon Production
Research in Houston, Texas. He received a BSc.
ACKNOWLEDGEMENTS degree in Chemistry from Allegheny College in 1963,
a Ph.D. degree in Chemistry from University of
The authors are grateful to the following persons for California at Berkeley in 1971, and a MSc. degree in
their contributions to this paper. Hans Thomann and Petroleum Engineering from the University of Houston
Marco Duran, Exxon Research and Engineering. Bob in 1992. John has been with Exxon for the past 16
Klimentidis, Dave Pevear, and John Longo, Exxon years.
Production Research. Dale Fitz, Esso Production
Malaysia. Duncan Mardon, NUMAR Corporation. Angel G. Guzman-Garcia received his Ph.D. degree in
Chris Straley, Schlumberger Doll Research. Adem Chemical Engineering from Tulane University. He
Djakic, Andy Mills, and John Phillips of Esso joined Exxon Production Research in 1990 and has
Australia. Special thanks to Esso Australia Ltd., modeled SP and resistivity tools in shaly sands. His
Exxon Production Research Company, Exxon current assignment is in the acquisition and
Exploration Company, and BHPP Pty. Ltd. for interpretation of NMR for estimation of petrophysical
permission to publish this paper. parameters.

REFERENCES

Borgia G.C., 1994, "A new Un-free fluid index in
sandstones through NMR studies", SPE 69th Annual
Conference, September, SPE 28366.

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

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

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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

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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

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