Spwla96 Paper I

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

CAPILLARY PRESSURE: THE KEY TO PRODUCIBLE POROSITY
W. SCOTT DODGE SR
ESSO AUSTRALIA LTD., MELBOURNE, VICTORIA, AUSTRALIA

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

ABSTRACT containing microporous materials. The large
intergranular pores observed in Figure 1 range in size
Producible porosity, defined as the pore volume from 50 to 200 microns whereas the smallest pores
available to hydrocarbon emplacement, has been (intergranular and intragranular) visible in high
computed from log measurements by modelling magnification photomicrographs are 5 to 7 microns.
capillary pressure irreducible water saturation as a Smaller pores can be observed under the Scanning
function of permeability and maximum hydrocarbon Electron Microscope (SEM) in Figure 2. This
column height. Producible porosity has been also microporous chlorite clay contains pores less than 1
measured directly by NMR when the T2 relaxation micron in diameter. Hydrocarbons can invade these
time distribution cut-off is calibrated to the maximum pores only when the pressure in the hydrocarbon
capillary pressure in the reservoir. The producible column is greater than the capillary pressure in the
pore volume imposes a calibration constraint on the micropores.
maximum hydrocarbon pore volume that can be
computed from logs. Producible porosity contains no This paper focuses on porosity description in clastic
immobile or irreducible water. depositional rock facies where isolated porosity is
negligible and normally can be ignored. We
Total, effective, isolated, macro and micro pore acknowledge that in clastics isolated porosity can occur
volumes are all used to characterise porosity based on under certain conditions of sandstone diagenesis.
specific definitions, criteria and measurement Definitions and concepts of total and effective porosity
techniques. Total porosity computed from logs should are reviewed while we go on to define a new
match core porosity where core porosity represents the hydrodynamic pore volume, "producible porosity".
total interconnected pore volume, however, total
porosity in shaley sandstone reservoirs computed from PETROPHYSICAL POROSITY MODEL
the crossplot of bulk density and neutron porosity logs
has been shown to overestimate core porosity. By Porosity in a shaley sand can be viewed as a continuum
modelling formation mineralogy based on a calibration that changes with the measurement method and
set and solving the log response equations through definition of its components. Formations which
least squares inversion, total porosity from logs contain detrital clay grains have significant
accurately matches core porosity. microporosity as with the glauconitic sandstone in
Figure 1. This thin-section is from an oil reservoir
INTRODUCTION containing a high total water saturation and produces
oil, free of formation water due to the abundance of
The reservoir engineer, geologist, petrologist and clay and capillary bound water. A large component of
petrophysicist all use or determine porosity to the bound water is associated with micro porosity in
characterise reservoir quality and volumetrics. The the glauconite. Microporous detrital grains such as
use and understanding of porosity definitions glauconite have less of an adverse effect on formation
frequently vary between and within disciplines. The permeability compared to the pore lining chlorite
reservoir engineer defines effective porosity as the shown in Figure 2.
interconnected pore volume of the rock, whereas this is
the definition of total porosity for the petrophysicist in Three modes of porosity that have been defined and
clastic reservoirs where isolated porosity is negligible. related to drainage capillary pressure data are
illustrated in Figure 3. Clay bound water is depicted
The total visible pore volume point counted in thin by the water associated with pore lining and filling
section by a petrologist frequently underestimates core clay in addition to detrital clay grains. In fine grained
porosity. This is found to be true especially in rocks sandstones, additional irreducible pore water is

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present in small pores and pore throats due to capillary the log response equations in a process called least
forces. The sum of irreducible water due to capillary squares inversion. LASER porosity is determined
forces and clay bound water is the bulk volume from a log forward model based on the results of core
irreducible, BVI, water in the reservoir which is mineralogical analyses by Fourier Transform Infrared
measured by drainage capillary pressure Spectroscopy MINERALOG (Hamish, 1988), thin
measurements. Producible porosity is that macro pore section petrographic analysis, and quantitative X-ray
volume which contains the moveable fluids, water and diffraction and X-ray fluorescence chemical analyses.
potentially hydrocarbons. The LASER mineral model, based on core mineral
identification, contains quartz, potassium feldspar,
As grain size and composition change, so does the dolomite, glauconite and kaolinite for the reservoir in
mechanism for irreducible fluid entrapment in the this example.
form of clay and capillary bound water. The
corresponding petrophysical shaley sand model based The reservoir sequence from 2880 metres to 2895
on these pore fluid types in a water-wet reservoir is metres has an elevated gamma ray which is caused by
shown in Figure 4. New techniques will be shown the presence of radioactive potassium feldspar shown
how to determine the producible porosity which in track 4. Clay volume in track 5 is negligible over
contains no irreducible water. this interval. LASER computed mineral bulk volume
of potassium feldspar and clay compare well to core.
TOTAL POROSITY Clay volume from LASER is the sum of the glauconite
and kaolinite volumes. Modelling formation
The engineering definition of total porosity in a mineralogy with LASER, grain density is accurately
sandstone is "The ratio of void space in a rock to the computed from the volume fraction of each mineral
bulk volume of that rock". Pore volume of a rock multiplied by its grain density. This in turn results in
sample is most commonly measured using Boyle's law more accurate porosity determination from logs.
or helium expansion. In separate measurements, pore Crossplot porosity fails to determine grain density
volume and grain volume are computed from a known accurately in sandstone reservoirs containing clays or
volume of gas at a known pressure and expanded into feldspars. The low grain density of feldspar and the
a chamber containing the rock sample. The pressure different clay types found associated with sandstones
in the chamber is measured after equilibration from are not taken into account in the solution of crossplot
which the unknown volume is computed. Total porosity.
interconnected porosity from core is computed as,
PHIX crossplot porosity overestimates core and
Pore Volume
φt = Pore Volume + Grain Volume
(1) LASER porosity by 3.4 porosity units in this shaley
feldspathic sandstone reservoir interval at 2870 metres
An important point to be made is that even when the shown in track 3. Total porosity is overestimated by
sample is dried using humidity controlled drying it has 17 percent using PHIX.
been shown the water saturation in the rock is
negligible and is equivalent to that observed at EFFECTIVE POROSITY
extremely high air/brine capillary pressure in excess of
13000 psi (Pallatt, 1990). Effective porosity is commonly used as a measurement
of rock quality to identify net reservoir from non-net
Commonly, total porosity from logs is computed using reservoir. Effective porosity as defined by the
the bulk density and neutron porosity crossplot petrophysicist is "The total porosity less any water
(Schlumberger, 1995). Crossplot porosity is accurate associated with clay minerals in the rock".
when the reservoir mineralogy contains quartz, calcite
φe = φt − Vclbw (2)
or dolomite and low clay content. This technique,
however, overestimates porosity in shaley sand
reservoirs. Figure 5 shows core porosity compared to Different methods have evolved in the determination
total porosity computed using two different porosity of clay bound water. The shale volume relationship
models over the cored interval down to 2875 metres. determined from logs in Equation 3 is commonly used
Track 3 contains the crossplot porosity, PHIX, while to estimate the clay bound water term in Equation 2.
the curve labelled LASER PHIT results from solving
Vshbw = Vsh × φsh (3)

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Non-clay minerals in a shale also contain associated
porosity. Therefore even a dense shale will contain Vhy = φt (1 − Swt ) = φe (1 − Swe ) (6)
porosity that is not associated with clays. Equation 3
frequently overestimates clay microporosity where Hydrocarbon pore volume must be the same whether
shale volume is usually one in a pure shale. This is computed using porosity and water saturation on a
because clay volume is commonly less than 50 percent total or effective pore volume basis. It is common to
of the rock volume in shales, therefore observe Swe approach or be limited to zero in shaley
hydrocarbon bearing sands. Hydrocarbon pore volume
Vclbw ≠ Vshbw and Vclay ≠ Vsh will be in error in this situation and underestimated.
This error is due to incorrectly determining clay bound
An accurate method which measures clay water which results in underestimating effective
intragranular microporosity developed at Exxon porosity and overestimating bound water saturation.
Production Research Company is called The current recommendation for computing
MICROQUANT. Figure 6 shows a backscattered hydrocarbon pore volume is to use porosity and water
electron SEM image of a glauconite grain where the saturation on a total pore volume basis as in the first
black is pure porosity and the intermediate grey levels part of Equation 6.
varying amounts of clay microporosity. Grey scale
image analysis has determined the clay grain to PRODUCIBLE POROSITY
contain 23.4 percent intragranular porosity. Once a
database of porosity associated with different clay and Producible porosity is discussed by Timur as early as
grain types has been built, it is incorporated into a 1969 (Timur, 1969) relating pore volume available to
LASER petrophysical model which computes the hydrocarbon storage.
various clay and other mineral fractions and the
associated microporosity from MICROQUANT. It is φp = φt (1 − Sw ) (7)
essential to calibrate the LASER model on a large
enough number of well characterised samples. Timur's producible porosity in Equation 7 is computed
using water saturation determined from air/brine
It is of primary importance to recognise that incorrect drainage capillary pressure at 50 psi. This capillary
determination of the volume of clay bound water will pressure was selected based on field observations of
affect the contribution of the clay water conductivity in water free oil production at 50 psi capillary pressure.
shaley sand water saturation equations like Dual Water Timur's method fails to account for reservoirs having
and Simandoux. Over estimation of clay bound water different hydrocarbon column heights and fluid types.
in Equation 3 introduces error in total water saturation We have taken Timur's producible porosity definition
computed from logs. one step further to account for these factors.
Incorporating irreducible water saturation into Timur's
WATER SATURATION Equation 7, we can determine the producible pore
space accessible to hydrocarbons for any oil or gas
Effective porosity and effective water saturation are reservoir.
commonly used to characterise rock quality and
producible fluids in shaley sands. Effective water φp = φt (1 − Swi ) (8)
saturation and clay bound water saturation are defined
in Equations 4 and 5. "Irreducible water saturation is defined by primary
drainage capillary pressure behaviour and
Swt - Swb
Swe = (4) corresponds to the water saturation at the maximum
1- Swb capillary pressure existing in the reservoir". This
leads to the definition of producible porosity as "The
where: pore volume available to hydrocarbon emplacement".
The petrophysical shaley sand formation model in
Vclbw
Swb = (5) Figure 4 shows the relationships of total, effective and
φt producible porosity.

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

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Determining producible porosity has great advantages of total porosity representing irreducible water
over effective porosity. Effective porosity contains the saturation). We can also consider the irreducible fluid
irreducible pore fluids related to capillary bound water filled pore volume to represent the microporosity in the
in addition to the moveable fluids, connate water rock composed of clay intragranular microporosity and
and/or hydrocarbons. Capillary bound water cannot be small pores and pore throats associated with fine grain
measured using conventional logging tools. We will non-clay minerals as shown in Figure 3. Additionally,
show that modelling capillary pressure measurements capillary water can be trapped in pore throats of coarse
or Nuclear Magnetic Resonance (NMR) logging grain sands. The large macro pores contain only
provides the additional information to measure this moveable fluids, the volume of which is equivalent to
capillary bound water. producible porosity. The subdivision between the two
pore types is determined by the maximum capillary
Irreducible water saturation has been modeled using pressure in the reservoir. This can be expressed as,
drainage capillary pressure saturation as a function of
permeability and maximum hydrocarbon column φt = φp + Vwi = φmacro + φmicro (11)
height. Drainage capillary pressure by mercury
injection of two sandstones of different permeability By differentiating the drainage capillary pressure
are shown in Figures 7a and 7b. Petrophysical measurement, accessible pore volume was computed in
properties of these two samples are shown in Table 1. Figures 8a and 8b. Inspection of SEM
TABLE 1 photomicrographs as in Figure 2 reveals pore types
Core Petrophysical Measurements which may be available to hydrocarbon emplacement
Sample Liquid Helium Thin Swi at the micron scale. The accessible pore volume
Number Permeability Porosity Section @
Visible 265psi diagrams in Figures 8a and 8b show the subdivision
Porosity Hg between macro and microporosity. The minimum pore
(md) (p.u.) (p.u.) (s.u.) throat diameter that permits hydrocarbon emplacement
3 2540 25 11 8
is 1.0 micron for this reservoir from,

6 0.12 15 4 62 2 (σ cos θ)res 2 ( σ cos θ)lab
r = = (12)
6. 895 Pc ( res ) 6. 895 Pc ( lab )
The reservoir has a 30 metre oil column height with a
Effective porosity overestimates producible porosity as
maximum oil/water capillary pressure of 19 psi. The
reservoir quality declines. This is shown in Table 2
19 psi oil/water capillary pressure is equivalent to a
where the clay rich sample 6 has a total porosity of 15
laboratory air/brine capillary pressure of 52 psi. This
p.u., effective porosity of 8.8 p.u. and producible
pressure, coincidentally, is similar to Timur's capillary
porosity of 5.7 p.u.. Producible porosity determined
pressure conditions. The reservoir capillary pressure
from drainage capillary pressure in this poor quality
transforms to an equivalent laboratory mercury
shaley sand sample confirms that 5.7 p.u. can contain
capillary pressure of 265 psi. Equations 9 and 10 show
hydrocarbons.
how to compute reservoir and laboratory capillary
pressure for the maximum hydrocarbon column height.
TABLE 2
Comparison of Total, Effective, Producible Porosity
Pc( res ) = 0. 0228 hmax (ρw − ρo ) (9) Sample Vclay PHIT PHIE PHIP
(%) (p.u.) (p.u.) (p.u.)
(σ cos θ)lab
Pc( lab ) = Pc( res ) (10) 3 8 25.0 23.7 23.0
( σ cos θ)res
6 29 15.0 8.8 5.7
The 265 psi mercury equivalent reservoir capillary
pressure corresponds to the minimum water saturation
in the reservoir, 8 percent in sample 3 and 62 percent Capillary pressure irreducible water saturation has
in sample 6. This minimum water saturation been modelled as a function of permeability shown in
partitions the total pore volume into two pore volume Figure 9 and Equation 13. The irreducible water
components: producible porosity (fraction of total saturation was determined at a maximum reservoir
porosity representing accessible pore volume at 265 capillary pressure of 52 psi from air/brine drainage
psi) and irreducible fluid filled pore volume (fraction centrifuge measurements. It is preferable to use

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air/brine drainage capillary pressure when available, significantly less than effective or total porosity which
where brine is the wetting phase, as opposed to leaves less pore volume available for hydrocarbon
mercury injection which is performed on an evacuated emplacement. Within the high permeability
sample. sandstones below 2882 metres all three pore types
converge indicating a low irreducible water saturation
Swi = − 0. 223 log( k ) + 0. 892 (13) in the high permeability facies.

Producible porosity can be determined using Equation Measurement of producible porosity provides a
8 once having established the irreducible water calibration for log computed hydrocarbon pore volume
saturation relationship based on formation shown in track 3 of Figure 10. Knowledge of
permeability and maximum hydrocarbon column producible porosity imposes the constraint that
height. In the following example, permeability was hydrocarbon pore volume must be less than the
determined using core and log NMR. Techniques to producible pore volume. When the reservoir is above
measure permeability outside of reservoir cored the oil-water transition zone, the hydrocarbon pore
intervals include NMR (Coates, 1993), Hydraulic Flow volume approaches the producible pore volume.
Units (Amaefule, 1994), Regression techniques
(Herron, 1987), Acoustic Stoneley waves (Winkler, Vhy = φt (1 − Swt ) ≤ φp (14)
1989) or Discriminant Analysis.
This constraint can also be viewed in terms of water
RESERVOIR CHARACTERISATION USING saturation,
PRODUCIBLE POROSITY
Swt ≥ Swi (15)
A glauconite rich shaley sand reservoir which
computes high water saturations from logs production APPLICATIONS OF NMR TO FORMATION
tested oil rates as high as 1500 bpd in an offset well. EVALUATION
Figure 10 shows the producible porosity and water
saturation resulting from modelling drainage capillary NMR can provide additional information to the
pressure. The reservoir's field oil-water contact occurs petrophysical logging suite available only from core
at 2859 metres; residual oil saturations are present capillary pressure measurements. Specific to this
below this depth caused by late structuring of the paper NMR provides, based on a predetermined T2 cut-
reservoir post oil migration. The reservoir was off, quantitative estimates of:
conventionally cored from 2837 metres to 2875 metres
and oil fluorescence was visible in the core to a depth • Free Fluid Index (FFI)
of 2849 metres confirming the presence of oil. • Irreducible Fluid Filled Porosity (BVI)

Overburden core permeability is shown in track 4 of NMR measures the relaxation rate of hydrogen protons
Figure 10. A 10 millidarcy permeability net reservoir in porous media when excited by an applied magnetic
cut-off is also displayed showing reservoir quality is field. T2 relaxation time of transverse magnetisation
below the cut-off within the oil column. Producing oil can be related to the surface-to-volume ratio of water
reservoirs in the Gippsland Basin flow oil at economic saturated rocks. The BVI from log NMR does not
rates when formation permeability is greater than 10 measure clay bound water because of the very fast
millidarcy. The entire reservoir section was logged relaxation time of clays (<1 msec) but is a measure of
with NUMAR's "B" series Nuclear Magnetic the capillary bound irreducible fluid. To compute
Resonance Image Log (MRIL). Below the cored accurate irreducible water saturation from log NMR
interval permeability was determined using the MRIL which can be calibrated to core, the clay bound pore
Coates permeability relationship. We have shown water must be taken into account as,
previously (Dodge, 1995) the good comparison of
NMR permeability to overburden core permeability on BVINMR + Vclbw φt − FFI
Swi = = (16)
laboratory core plug samples from this reservoir in φt φt
another well.
The great advantage of NMR to formation evaluation
In the glauconitic sandstone reservoir from 2837 is that the logging measurement can be simulated in
metres to 2882 metres the producible porosity is the laboratory on core using NMR spectrometry.

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When performing NMR measurements on core it is reservoir description and hydrocarbon volume
important to design the experiments to have the same quantification.
acquisition parameters as the logging tool if the goal is
core to log calibration. Specifically magnetic field Producible porosity is determined from drainage
strength (homogeneous or gradient), echo spacing, and capillary pressure measurements and represents "The
recovery time should be equivalent. pore volume available to hydrocarbon emplacement".
Producible pore volume from core imposes a maximum
A laboratory T2 relaxation distribution is shown for the constraint on the hydrocarbon pore volume computed
low clay content sandstone in Figure 11. The bi-modal from petrophysical logs. It is now possible to compute
T2 distribution indicates that a high percentage of the producible porosity from log measurements by
porosity contains large pores and a small component of modelling capillary pressure irreducible water
pore space is microporous. T2 relaxation was saturation as a function of permeability and maximum
measured with the plug fully saturated and also hydrocarbon column height. Permeability data are
desaturated to 50 psi air/brine capillary pressure. The required to transfer the modelling process to the
capillary bound irreducible water is represented by the petrophysical logs.
signal amplitude less than 33 msec. Integration of the
T2 distribution amplitudes over all T2 for the fully NMR log measurements quantify producible porosity
saturated sample yields the rock pore volume, and capillary bound irreducible pore volume when
calibrated to core. These log measurements can
φ NMR = ∫ A(T 2)dT 2 (17) provide significant cost savings in special core analysis
by replacing the need to measure drainage capillary
pressure water saturation to verify petrophysical log
NMR FFI is calibrated to producible porosity measured derived water saturation as well as increase reservoir
from drainage capillary pressure by determining the coverage in non-cored intervals.
relaxation T2 cut-off which equates these two
measurements, NOMENCLATURE

∞ A NMR signal amplitude, p.u.
φp cap pressure = FFI = ∫ A(T2)dT2 (18) hmax maximum height of hydc. column, metres
T2cut - off k single phase absolute permeability, md
The primary drainage mercury injection capillary Pc(lab) laboratory capillary pressure, psi
pressure for this sample is shown in Figure 12. Pore Pc(res) reservoir capillary pressure, psi
volume which contains producible fluids occurs for Sw drainage capillary water saturation, frac
capillary pressures below 265 psi. Calibration of the Swb clay bound water saturation, frac
NMR T2 cut-off time to this pore volume brings Swe effective water saturation, frac
equivalence into the NMR derived producible pore Swi irreducible water saturation, frac
volume measurements. Swt total water saturation, frac
T2 transverse spin-spin relaxation time, msec
Literature is filled with comparison of NMR T2 Vclay bulk volume dry clay minerals, frac
relaxation distributions to capillary pressure (Chang, Vclbw bulk volume clay bound water, frac
1994, Dunn, 1994, Kenyon, 1992). The newest log Vhy bulk volume hydrocarbons, frac
NMR signal processing is based on computation of Vsh bulk volume shale, frac
producible porosity from T2 relaxation distributions. It Vshbw bulk volume shale bound water, frac
has been shown that the T2 relaxation cut-off for most Vwi bulk volume irreducible water, frac
clastic reservoirs is approximately 33 msec (Straley, φe effective pore volume, frac
1991). φmacro macro pore volume, frac
φmicro micro pore volume, frac
SUMMARY φp producible pore volume, frac
φsh porosity in shale, frac
Definitions of porosity are quite varied between the φt total pore volume, frac
various disciplines which use this petrophysical ρo reservoir condition oil density, lb/cf
parameter. Producible porosity reviewed in this paper ρw connate water density, lb/cf
is a new porosity type, having distinct advantages for σ fluid surface tension, dynes/cm2

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θ fluid contact angle, degrees Pallatt, N., Thornley, D., 1990, "The Role of Bound
Water and Capillary Water in the Evaluation of
ACKNOWLEDGEMENTS Porosity in Reservoirs", Society of European Core
Analysis Symposium.
The authors would like to acknowledge Kumar Kuttan,
Steve Twartz and Andy Mills for their work in Schlumberger, 1995, "Log Interpretation Charts",
saturation modelling of capillary pressure Schlumberger Educational Services.
measurements. Angel Guzman-Garcia provided
valuable comments in the editing of this paper. Straley, C., Morriss, C.E., Kenyon, W.E., Howard, J.J.,
Special thanks to Esso Australia Ltd., Exxon 1991, "NMR in Partially Saturated Rocks: Laboratory
Production Research Company, Exxon Exploration Insights on Free Fluid Index and Comparison with
Company, and BHP Petroleum for permission to Borehole Logs", SPWLA 32nd Annual Logging
publish this paper. Symposium, Paper CC.

REFERENCES CITED Timur, A., 1969, "Pulsed Nuclear Magnetic Resonance
Studies of Porosity, Moveable Fluid, and Permeability
Amaefule, J.O., 1994, "Applications of Core Data in of Sandstones", JPT.
Hydraulic (Flow) Unit Zonation for Improved
Reservoir Description", Workshop on Core Analysis Winkler, K.W., Liu, H.L., Johnson, D.L., 1989,
for Reservoir Management, Society of Core Analysts, "Permeability and borehole Stoneley waves:
Vienna, Austria. Comparison between experiment and theory",
Geophysics, Vol. 54, No. 1.
Chang, D., 1994, Vinegar, H.J., Morriss, C.E., Straley,
C., "Effective Porosity, Producible Fluid and ABOUT THE AUTHORS
Permeability in Carbonates from NMR Logging",
SPWLA 35th Annual Logging Symposium, Paper A. Scott Dodge is a Senior Petrophysicist with Esso
Australia Ltd. in Melbourne, Australia. He holds a
Dodge, W.S., Shafer, J.L., Guzman-Garcia, A.G., BSc. degree in Mechanical Engineering from Kansas
1995, "Core and Log NMR Measurements of an Iron- State University and MSc. degree in Petroleum
Rich Glauconitic Sandstone Reservoir", SPWLA 36th Engineering from University of Southern California.
Annual Logging Symposium, Paper O. He has served as President of the Formation
Evaluation Society of Victoria. Scott joined Exxon in
Dunn, K.J., LaTorraca, G.A., Warner, J.L., Bergman, 1982 and has worked in the U.S.A., Canada and
D.J., 1994, "On the Calculations and Interpretation of Australia as a Formation Evaluation Specialist.
NMR Relaxation Time Distributions", SPE 69th
Annual Technical Conference, New Orleans, La., SPE John Shafer presently is a Senior Research Specialist
28367. in the Reservoir Division of Exxon Production
Research in Houston, Texas. He received a BSc.
Hamish, A., Harville, D.G., Meer, D., Freeman, D., degree in Chemistry from Allegheny College in 1963,
1988, "Rapid mineral analysis by Fourier transform a Ph.D. degree in Chemistry from University of
infrared spectroscopy", Society of Core Analysts California at Berkeley in 1971, and a MSc. degree in
Conference, SCA 8809. Petroleum Engineering from the University of Houston
in 1992. John has been with Exxon for the past 17
Herron, M.M., 1987, "Estimating the Intrinsic years.
Permeability of Clastic Sediments from Geochemical
Data", SPWLA 28th Annual Logging Symposium, Bob Klimentidis is presently a Geochemical
Paper HH. Technologist in the Petrophysics and Reservoir Quality
section of Exxon Production Research in Houston,
Kenyon, W.E., 1992, "Nuclear Magnetic Resonance as Texas. He received a BSc. and MSc. degrees in
a Petrophysical Measurement", Nuclear Geophysics, Geology in 1975 and 1979 respectively from Queens
Vol. 6, No. 2, pp 153-171. College, University of New York. Bob has been with
Exxon for the past 15 years.

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