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Geological Society, London, Special Publications

New techniques in lithofacies determination and

permeability prediction in carbonates using well logs
M. H. Dorfman, J.-J. Newey and G. R. Coates

Geological Society, London, Special Publications 1990, v.48;

p113-120.
doi: 10.1144/GSL.SP.1990.048.01.10

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© The Geological Society of London 2012

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New techniques in lithofacies determination and permeability

prediction in carbonates using well logs
M. H. D O R F M A N , J.-J. N E W E Y & G. R. C O A T E S
Department of Petroleum Engineering, The University o f Texas at
Austin, Austin, T X 78712, USA

Abstract: Carbonate reservoirs pose many challenges to geologists and engineers. Litho-
facies variations are often the key to the determination of commercial value and efficient
reservoir exploitation. Thus, techniques which permit the identification of the involved
lithofacies would be useful. This paper illustrates a successful application of multi-
dimension techniques in two-dimensional space, by using cross plots of a variety of well
logs that have a principle component sensitivity to the lithofacies. This paper also
examines the appropriateness of techniques which relate log data to core-derived per-
meability. These approaches have previously been associated with the intergranular shaly
sand rocks and not carbonates. The technique shown approaches this from a Kozeny-core
correlation which is used to predict the surface area parameter. This is then followed by
development of a link to log-derived bulk water values. The log derived variables can be
made to work providing irreducible conditions are present or can be established.

Identification of carbonate rock type and texture mud-supported wackestones and mudstones.
from well-log response can serve as a valuable Porosity within reservoir systems may be inter-
aid in geological characterization of reservoirs granular, intraparticle, vuggy or moldic, and
and in development of depositional models for sometimes includes fractures or bimodal po-
both exploration and production. Such identi- rosity systems. Regardless of the classification
fication can also be used to trace lateral extent scheme employed, characteristic well-log re-
and continuity of individual reservoir zones sponse patterns are often discernable within
within complex reservoir systems, in many cases individual facies and can be used for both
optimizing development well locations for geological characterization and engineering
improved primary drainage patterns and for quantification of reservoir performance.
efficiency in subsequent enhanced recovery Using logs to identify sedimentary facies is
operations. also expected to help predict permeabilities.
Geologists have traditionally relied on core Such correlations are approachable by using
data for sedimentological interpretation, but permeability information from cores of the
complete coring in all field wells is rare because facies studied, and a model, like Kozeny's,
of high cost; total core recoveries are also rare which links such parameters to permeability.
because of mechanical problems. As a result,
the technique of matching limited core facies
data with well-log response, and subsequent Current studies in lithofacies determination
facies identification from well logs, can often
lead to complete facies discrimination and re- Well-log crossplots have long been in general
finement of depositional models. Since open- use for determination of mineralogy and po-
hole logging suites are routinely run in all wells, rosity (Raymer & Biggs 1963; Burke et al. 1969)
they provide complete data throughout both and also more specifically for discrimination
the reservoir and adjoining rock systems. of carbonate facies (Asquith 1979). Recently
The technique, which has been successfully in Basham & Dorfman (1983), Keith & Pittman
several fields, involves correlating facies from (1983), Dorfman & Dupree (1985) and Kamon
core description with log response and cross- & Dorfman (1985) successfully distinguished
plotting various log parameters of individual facies and associated reservoir characteristics
facies by a variety of methods. The key to using primarily well-log responses correlated
selection of crossplots which distinguish sedi- with limited core data. Dorfman & Dupree
mentary facies is for the facies to have textural (1985) gave an outline of a method that might
and mineralogical characteristics which affect be used for permeability prediction in carbon-
log measurements. Carbonate systems consist ates which is developed in this paper.
typically of a complex series of vertically Variation in sonic and neutron porosity was
sequenced rocks that may be classified as used to differentiate three major facies (grain-
clean grainstones and packstones, grading to stone, wackestone and lime mudstone) in the

From HURST, A., LOVELL,M. A. & MORTON,A. C. (eds), 1990, GeologicalApplications of 113
Wireline Logs Geological Society Special Publication No. 48, pp. 113-120
 Downloaded from http://sp.lyellcollection.org/ at Boston College on October 24, 2012

114 M.H. DORFMAN ETAL.

Sligo Formation (Lower Cretaceous) in South undisturbed portion of the reservoir, Rt, and
Texas (Basham & Dorfman 1983), where po- resistivity in the region flushed by mud filtrate,
rosity is above 5% (Fig. 1). The formation Rxo.
has intergranular porosity in the grainstone re- The work of Kamon & Dorfman (1985) in-
servoir facies with limited diagenesis in the volved a complex grainstone/mudstone se-
supratidal facies, and is comparatively uncom- quence in the San Andres Formation (Permian),
plicated. Distinction of facies depends upon the West Seminole Field, Texas. In this oil field,
difference between total porosity as recorded extreme diagenesis is found in the dolomitic
by the neutron log and porosity calculated from rocks, with both moldic and intraparticle
the sonic log. This difference, caused by low po- porosity present throughout the rock sequence,
rosity values from the sonic log due to poorly and interparticle porosity present in the grain-
connected porosity, is usually referred to as stone facies. The two facies were distinguished
'secondary porosity' by the log analyst. by use of an Rtl(Rxo/Rmf ) against Rt/(RslRz)
Keith & Pittman (1983) examined a more crossplot (Fig. 2). As in the case of Keith &
complex system involving both a unimodal and Pittman (1983), the crossplot works because of
bimodal pore system within a grainstone facies the differences in mud filtrate invasion.
in the Rodessa Formation (Lower Cretaceous), Dorfman & Dupree (1985) examined the San
Running Duke Field, Texas. In this gas field, Andres Dolomite (Permian), Hanford Field,
water saturation calculations indicated similar Texas, a series of shoaling upward sequences
saturation values in both pore systems, but with coarser grainstones deposited on the top of
water-free gas was produced from only the the shoals; mudstones and wackestones, rep-
bimodal pore system. The two systems were resenting lower depositional energy, were de-
differentiated by use of an Rt against Rxo/Rmf posited away from the shoal and along its flanks
crossplot. Differences in pore geometry often (Kumar & Foster 1982). The depositional cycle
create differences in the depth of mud filtrate comprises approximately 1000 feet of cyclic
invasion or the efficiency with which mud filtrate sediments, capped by supratidal deposits of
displaces hydrocarbons and formation water. anhydrite and terrigenous shales.
Depending upon saturations and the values of Only two of the 35 field wells were cored, but
Rmf and Rw, differences in filtrate invasion geological descriptions from the cores were suf-
characteristics here resulted in a unique con- ficient to provide facies information for log
trast between formation resistivity in the studies. Digitized logging parameters for each

LEGEND: + GRAIN 0 UPPER MUD

LOW lO.OOO
+
3.981 4.+ 4. :
++
I. 4.
~/, g ,~^,.~' 1.585 + 4. ~. S
70-
,1,' - - , : / y , , 0+
4.
4.'4.
4.

Of) . / /j/ <,z / ~ .631 4'

+
4.

r
<3 ,,.,,- .251 ~176
~" o o
///
i =. ooooo
0
.100 00 0
=,- 60- 0 0
0
1 .040 o0
p-
o
u ///

~
Anh.
50- /
i1 / Ix

/
/ lllg
i
I
/
.016

.olo '.o~5 '.0~3 '.1.~8 '.3~8 '1.000' ' 2.~,1~ e~310

R t / ( R s / R z ); Rs = shallow Isterolog reslsUvity

o ,b 2'0 3'0 Fig. 2. Resistivity crossplot from logs from the West
SNP NEUTRON POROSITY(e/e) Seminole Field where R t is the true resistivity, Rxo is
the resistivity in the flushed zone, Rmf is the mud
Fig. 1. Cumulative sonic-neutron crossplot showing filtrate resistivity, R~ is the shallow laterolog
combination of observed linear data trends. Note resistivity and Rz is the estimated resistivity of mud
transition from high energy to low energy facies filtrate and formation water in the partially flushed
deposition. zonc.
 Downloaded from http://sp.lyellcollection.org/ at Boston College on October 24, 2012

LITHOFACIES DETERMINATION: NEW TECHNIQUES 115

facies were then crossplotted following the

method of Fertl (1981), and it was found that a
plot of R t against q~p (Fig. 3) as well as a plot of
R t against q~N, could be used to distinguish the
~o_
MOOSONE.::''',
."
N~ Ill
various facies. Since all R t values were obtained ~11 111
WACKESTONE ~ ~ 9
within the oil column at irreducible Sw, the
principal variant that differentiates facies is pre- G
I ~ ~t i l IIII ~%,~_ i II ]llj~ /

sumed to be the cementation exponent, m, in ~:

0-)r
the Archie equation. The value of m depends ,-
upon the tortuosity of the electrically conduc-
tive paths provided by interstitial water. In gen-
eral, higher values of m are associated with
more tortuous pore geometries. In this case,
successively finer grained sediments (e.g.,
lime mudstones) exhibit more tortuous pore ~,72_
geometries than the grainstones.
We conclude that, generally, crossplots in-
volving functions of porosity against resistivity
differentiate facies due to variations in the + ,~RINSTONE
cementation exponent, rn while crossplots of NQCKESTONE
resistivity values, e.g. Rt against Rxo/Rmf,rep- HU0~TOHE

resent changes in the characteristics of mud %'2.~0 2: so 2:60 2: "7o s 80 2. so

filtrate invasion when plotted in zones at or DENSITY (GH/CCJ
near irreducible water saturation conditions pro- Fig. 3. Crossplot of Rt against bulk density, Hanford
viding the grain size characteristic is uniform. A Field.
more detailed study of m value relationships in
carbonates is found in Lucia (1983).
PERMEABILITY VS. POROSITY

Prediction of permeability in carbonates 1oo.o o /

c /
[] /
[] /
Background []
o
/ o ~o
10.0 [] oo/~ [] []
Estimation of permeability from core data or P
[3 o O o/

from well logs is not new. In fact, the process

o Do o
most commonly used is to estimate permeability o oo ~o n 0
[] oo~oloo o n o~ o
from core data using a semilog plot of K against
q~. While this technique is often useful in fairly 1.00 OO0 on 0'[] O O]OoO Oo O0 0

homogeneous sandstones, it is often impossible o ~ o/ore o ~

to apply in heterogeneous carbonates. Figure 4 0 o/ n0000
o rmn'm 0 rn ~:~ rn
shows a K against qb crossplot in the San Andres o ~nn []o o DO o
Dolomite, Hanford Field, Texas, from cores of 1
z
0.10 ', ~ - - - . ~ ' ~ ~ ~ ~ j:~ ~r, , , , , , ~ ~ ,
one well. As a result, other methods must be 901 .03 .05 .07 .09 .11 .13 .15 .17 1.9
applied to attempt to estimate permeability.
CORE POROSITY
The concept used in this work was first presented
by Wyllie & Rose (1950). Their work proposed Fig. 4. Plot of core permeability versus core porosity
use of the Kozeny equation in estimating the for the Boecker 215-1 well, illustrating the poor
permeability of consolidated porous media linear trend. Note the variation in permeabilities for
having regular pore geometry. A later paper by the 10-11% porosity range.
Wyllie & Spangler (1952) first implied that per-
meability could be estimated using electrical
resistivity measurements and a modified form face area, obtained using different techniques
of the Kozeny equation. of measurement on the same porous medium,
The problem in applying the Kozeny equation varied greatly. However, specific surface area
to complex porous media has been obtaining a of the pore surface is a controlling factor in the
direct measure of specific surface area and a permeability of carbonates. A l o g - l o g plot
parameter called the Kozeny constant. Wyllie (Fig. 5) shows the effect of particle size on the
& Spangler showed that values of specific sur- permeability of uniformly cemented, non-vuggy
 Downloaded from http://sp.lyellcollection.org/ at Boston College on October 24, 2012

116 M.H. DORFMAN ETAL.

10000 Rose. They found that for clean, brine-saturated

sandstones, tortuosity is related to the formation
INTERPARTICLE POROSITY resistivity factor and the porosity of the rock.
1000 Both of these parameters can be directly
x ,lOO~ /~_~:.~,_r
o 2O-lOO. / . / ;Z'.
measured using well logs in water-bearing for-
9 =o~ / / / "'0. mations, and estimated in oil-bearing forma-
>: 100 tions from secondary correlations.
5 In theory then, tortuosity could also be esti-
mated in clean formations using well-log
~ lo measurements. Furthermore, if a correlation
could be obtained between log-measured para-
, ' "~" : ' A ' . ":~'" metres and specific surface area, permeability
1.o / ../;/.'.,1",.
/ ," . ~ ~176 ~ could be estimated in wells without core, using
//./.;-;;... 9 the Kozeny equation and well logs. However,
0.1 , . . Z /*,"r . . . . . . in dealing with logs through oil-saturated zones,
4 lO 20 40 do it is important to recognize that a correlation
POROSITY, %
should exist between specific surface area and
Fig. 5. Relationship between porosity and irreducible water saturation (Archie 1952); this
permeability for various particle size groups in correlation is elaborated on in this work.
uniformly cemented, non-vuggy carbonate rocks
(after Lucia 1983).
Application of the Kozeny Model
carbonates from which Lucia (1983) concluded The Kozeny equation is an analytical solution
that the size and amount of intra-particle for fluid flow through porous media and is ob-
porosity were major factors controlling per- tained by combining the Hagen-Poiseuille law
meability in carbonates. Brooks & Purcell with Darcy's law. The general Kozeny formula
(1952) presented a laboratory method for is
measuring specific surface area using gas ad-
sorption. Their results, presented for a variety dp3 x 108
of sandstones and limestones, showed good K = 21:2Sv2(l_dp)2 (1)
repeatability of measurement. Unfortunately,
measurement of specific surface area by gas where K is the absolute permeability of the
adsorption requires elaborate apparatus which porous media(in darcies), tp is the porosity as a
is not standard equipment in a typical core fraction of bulk volume, Sv is the specific sur-
laboratory. face area of mineral constituents in cm -~ and 9 is
The difficulty in direct measurement of the tortuosity factor (dimensionless) which has
specific surface area in the laboratory has been been shown (Winsauer 1952) to be related to
circumvented in this study. Incorporating a formation factor and porosity in the following
modified form of the Kozeny equation, values manner:
for core permeability and porosity are plugged "t2 = Fq~-2. (2)
into the equation, and specific surface area
values are then back-calculated. The method The formation factor commonly used for
avoids the errors in measuring specific surface carbonates is
area using a visual method (Wyllie & Spangler F = ~ ) -2. (3)
1952). Furthermore, values obtained with the
proposed method compare well in range and Combining (2) and (3) into (1), gives
magnitude, to values obtained for other q~4 x 108
carbonate rocks using the gas adsorption K = 2Sv2(l_qb)2. (4)
techniques.
The other problem in applying the Kozeny The Kozeny equation assumes laminar in-
equation to complex porous media had been compressible flow with end effects ignored. This
measurement of the tortuosity parameter. application assumed no end effects in laboratory
Wyllie & Rose (1950) suggested that tortuousity measurements of permeability, which are nor-
could be estimated by measurement of the for- mally minimized. Another assumption is lack
mation resistivity factor. Winsauer (1952) pre- of channeling in the porous media, a factor
sented theory and laboratory measurements that which might be violated if fractures or large
substantiated the earlier premise of Wyllie and vugs are present. Since the predominant po-
 Downloaded from http://sp.lyellcollection.org/ at Boston College on October 24, 2012

LITHOFACIES DETERMINATION: NEW TECHNIQUES 117

rosity in this San Andres Dolomite is intergranu- PERMEABILITY VS. POROSITY

lar, this assumption is probably not violated.
100 .,,
The final assumption is a cementation exponent [] ,'

of 2, which cannot be validated in our case,

u silo o :060
t,. o .,..'

although similar formations in nearby fields **' ~ O

have an average cementation exponent closely . ." . s . ~ 13 oB"

./ o
approximating 2. 9 .., oo o 9 ~

In order to proceed with estimation of 10. .."' ' ~ o ..""

I-- , .
o o~ . '
." n rl .
permeability, core porosities from one well "i , o.. a n ,"o ~ 1 7 6 t~.
0o' :~ ~ ~' o uoo 4 0 0 0 o
(Boecker No. 2 1 5 - 1 ) were compared with log o o:" ~o "~' o o ....'
porosity obtained by density/neutron crossplot 9 ' I"I .. u

0.. o .0~o0 .'~ o o/ o

porosity (Fig. 6). Some deviations occur in
1.0 t o.o o, o. o o , '"o [] .o o -~," ---: o 8000
extremely low porosity ranges, but in general a. " " D tV9 '
eft =g"
9 n ..
..
rr ' ,' o ~ ~ ." ..
there is good agreement between core-and log-
D . 9 I] ,'0 g ~." ,."
derived porosity. The modified Kozeny equa- o moo o m o m m y"
tion (4) was then rearranged as follows: I o ' i o o .. ...0~
o ~ n orV" ." 5 .. [
9 . ~' o ,"

( ~4 • 108 ~1/2
0.1 I .9 . ~ ..v , p .~ . l ~.. , ~., ~ - ~ * ~ " - - - "~ . 4 . , ~ - ~ ,-. . p- "-'
I,~ I I I I I I I I I

Sv = \2K(l_qb)2 / (5) 0 .02 .04 .06 .08 .1 .12 .14 .16 .18 .2
CORE POROSITY
and core porosity and permeability for 336 core
samples from this well were used to obtain S v = 1000 S v = 2000 S v = 4000
values for Sv (Fig. 7). A distribution of Sv Fig. 7o Core permeability plotted against core
values is shown in Fig. 8, with values ranging porosity for Boecker 215-1. Curved lines represent
from 100 cm2/cm 3 to just under 7000 cm2/cm 3. solutions to the Kozeny equation for constant values
Modal values of 1000 to 2000 cm2/cm 3 (Fig. 7) of specific surface area.
are similar to gas adsorption measurements
made on some Ordovician limestones (Brooks
DISTRIBUTION OF SPECIFIC SURFACE AREA
& Purcell 1952). We also note that Sv increases
9
with a decrease in grain size, a finding that is in
8
agreement with Lucia (1983). However, since
pore size, pore geometry, and roughness of 7
pore walls are controlling factors in formation >- 6
permeability, it is beneficial to think of specific ~s
surface area in terms of pore size and geometry 0 4
rather than grain size.
" 3
2
COMPARISON OF X-PLOT AND CORE POROSITY
1
0.2-
0
0.18 ~ 0 1000 2000 3000 4000 5000 6000 7000
0.16 SPECIFIC SURFACE ( c m 2 / c m 3)
>-
F- 0.14
Fig. 8. Frequency distribution of calculated specific
surface areas, from the San Andres producing
mO 0.1
0"12~ i ~ i horizon in Boecker 215-1, Hanford Field (Gaines
O 0.08 County, Texas).
0.06
0.04
0.02 Petrophysical studies have shown that, in a
water-wet reservoir, the irreducible or connate
5.38 5.'42 ' 5.~16 ' 5J5 ' 5.'54 ' 5 : 5 8 ' 5.62
water saturation is a function of pore size. In
DEPTH (feet x 10 3 ) general, a rock with smaller pores will have a
higher irreducible water saturation than a rock
CORE POROSITY X-PLOT POROSITY with larger pores. This p h e n o m e n o n is caused
Fig. 6. Comparison of the (CNL/FDC) crossplot by the interracial forces that exist between the
porosity curve with the core porosity curve for the oil-and water-wet phases in the reservoir and
Boecker 215-1 well. Note the division of the two the specific surface area. These forces are in-
curves at low porosity ranges. versely proportional to the radii of the pores in
 Downloaded from http://sp.lyellcollection.org/ at Boston College on October 24, 2012

118 M.H. DORFMAN E T A L .

which the fluids interact. In the smaller pores, OSxo VS r

higher capillary forces are exhibited. As a result, 0.08

water tends to reside preferentially in the

0.07 ", 2
smaller pores. In the oil column of a carbonate
reservoir, the irreducible water saturation will 9 " 3 2
0.06. " ~ 1
tend to vary according to the predominant pore
9 8 4
size. In addition, if water is exposed to highly 0"05 i . / = 1 "2
oil-saturated rock in the oil column, it will tend "/ 'o ,2 " .~
preferentially to invade the portion of the res- ~ 0.04 9
/
/. " ~
'.~.~ t 27
1,5
229 $
4t6 t
f' .
,
g
/ '2. ~ -z --- .
ervoir having smaller pores.
0.03 ~ "/. ~ I~ *',. 12 2 ( " --'--"
Since specific surface area is directly related I., ?~ "t ' ,..e:~e."
to pore size, we focused on correlating specific 0.02- / / ' ' ;~,..~.....~.~'~""
~ : ~ ~ ~'- ..
surface area to log-derived values of water satu-
ration. In addition, since the wells at Hanford 0.01 o6 ~ 800 ?,1 9 ..........
Field were drilled with a saltwater-based mud,
the possibility of an imbibition effect was also
00 ' 0)02
iiiiii '
.

0.'04
. . . . . :
' 0.06
examined. Theoretically, if invasion of mud fil- CSw
trate did occur in the oil column, it would
invade preferentially at levels with predomi- Fig. 9. Well-log derived values of qbSxoagainst dpSw
nantly smaller pores. Reservoir sections having for core data in the oil column of Boecker 215-1.
Points are labelled with specific surface areas/1000.
larger pores would have little or no invasion.
Specific surface area was plotted against vari-
ous log-derived saturation values. A correlation
was observed between specific surface area and corner of the plot, correspond to low values of
(1) ~Sw, the bulk volume fraction of water in both q~Sxo and q~Sw, and high values of specific
the virgin zone, and (2) q~Sxo, the bulk volume surface area correspond to higher OpSxoand qSw
fraction of mud filtrate in the invaded zone. amounts in the upper right-hand corner of the
The bulk volume fraction of water in the plot. This is further illustrated by adding the
virgin zone is calculated using the following qbSxo • r = constant hyperbolae for 0.0001,
formula: 0.0002, 0.0008 and 0.0016. These observations
are reasonable since high specific surface areas
dpSw = (Rw/Rt) 1/2 (6)
mean smaller pores. Smaller pores result in
where Sw is the water saturation in the virgin higher irreducible water saturations in the virgin
zone, Rw is the resistivity of the formation zone, explaining the increased r Further-
water (in ohm m) and R t is the true resistivity of more, mud filtrate tends to invade zones pre-
the virgin zone (in ohm m). The bulk volume ferentially where the predominant pore size is
fraction of filtrate in the invaded zone is smaller. This phenomenon explains the high
calculated in a similar manner: q~Sxo estimates for higher specific surface areas.
A more obvious correlation is observed when
qbSxo = (Rmf/Rxo) ]/2 (7)
specific surface area is plotted against the prod-
where Sxo is the mud filtrate saturation in the uct of r and q~Sw (Fig. 10). The plot shows
invaded zone, Rmf is the resistivity of the mud that an increase in specific surface area cor-
filtrate (in ohm m) and Rxo is the true resistivity responds to an increase in both q~Sxo and r
of the invaded zone (in ohm m). Both (6) and By performing a linear regression fit through
(7) assume a cementation exponent of 2 and the data we now have a model for predicting
a saturation exponent of 2. As discussed earlier, specific surface area. By calculating r and
the assumption of 2 as a cementation exponent r using resistivity logs, we can obtain a pre-
is justified. The saturation exponent is dicted value of specific surface area in wells that
arbitrarily taken as 2 also. have no core. Then, an estimate of permeability
The relationship between the quantities ex- is obtained by plugging the predicted specific
pressed in (6) and (7) and specific surface area surface area value and a log-derived estimate of
can be seen in a plot of qbSxo against r (Fig. porosity into (4).
9). Note that r < q~Swoccurs; this is probably It is important to stress that this correlation,
caused by incomplete flushing by the invasion based on an irreducible water saturation, applies
process. The plot has specific surface area, div- only to the oil column of the reservoir. Some
ided by 1000, labelled as the Z axis. The general other method must be used in zones below the
trend observed is that low values of specific oil/water contact or if hydrocarbon changes from
surface area, located in the lower left hand oil to gas. Since the zone of interest is normally
 Downloaded from http://sp.lyellcollection.org/ at Boston College on October 24, 2012

LITHOFACIES DETERMINATION: NEW TECHNIQUES ] 19

SPECIFIC SURFACE VS. ((~Sxo)(~Sw) CORE AND C A L C U L A T E D PERMEABILITIES

•E'105- 1000-

~ 104_ % ~ ~ ,~ 1 0 0 !

10 3-

<
~: 10 2 ;~ 1.0 i
h-

01 e 0.1

10 0 . . . . . . . . . . . . . . . . . . . 0.01
-4.5 -4.3 -4.1 -3.9 -3.7 -3.5 -3.3 -3.1 -2.9 -2.7 -2.5 5 . 3 8 ' 5.:42 ' 5 ) 4 6 ' 5:5 ' 5.'54' 5.'58 ' 5)82
LOG[ (~Sxo) (r w )]
DEPTH (feet x 10 3 )
Fig. 10. Correlation between specific surface area
and Sxoq~Swin the oil column of Boecker 215-1. CORE (AIR PERM) CALCULATED

Fig. 11. C o m p a r i s o n o f c a l c u l a t e d a n d c o r e - d e r i v e d
p e r m e a b i l i t i e s in B o e c k e r 2 2 5 - 1 .
above the oil/water contact, this should not be a
major problem.
changes in permeabilities over small intervals, it
Results is common for physical sampling to include the
best portion of the core for analysis. This may
The ultimate test of this Kozeny model is com- not, in some cases, be representative of the
parison of permeability estimates with core- entire interval. In general, the technique ap-
derived permeabilities (Fig. 11). Differences pears to give permeabilities based on well-log
occur primarily in the very low permeability response that compare favourably to those ob-
ranges and occasionally in the very high per- tained by laboratory measurement of cores.
meability ranges. The latter may result from the In the Hanford Field, all wells have been
few large vugs that occur in the San Andres and subjected to permeability estimation by the
are mentioned in the core description. A n o t h e r technique described herein. A cross section of
probable cause of error is in sampling of cores. wells across the field shows that the various
Since carbonate cores often have extreme zones have characteristic permeability profiles

PERMEABILITY(MD)
. .: o o
NORTH ~a SOUTH

01
ZON!I
9 ~
~,. ~,"
ZONE2
01 01

!.
i~" 01
.

~ ZONE3
9 "~01

. . . . . . . ___

ul .(,n

ARCO 214-3
01
BOECKER 215-1
BOECKER 215-2

Fig. 12. North-south cross section through the Hanford Field, Gaines County, Texas9 Curves represent
estimated permeabilities using the Kozeny equation9 Depths in thousands of feet.
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120 M . H . DORFMAN ET AL.

that can be c o r r e l a t e d field-wide (Fig. 12). W e a p p e a r to offer an alternative m e t h o d for cor-

can also see that not all wells are c o m p l e t e d in relating individual p e r m e a b l e zones a n d of
the same p e r m e a b l e intervals, and that in some estimating the p e r m e a b i l i t y ii'. each; t h e y
cases, o t h e r zones in individual wells contain also p r o v i d e a m e t h o d for consistent well
permeabilities as g o o d as, or b e t t e r t h a n , the c o m p l e t i o n s in c o m p a r a b l e zones for effec-
c o m p l e t i o n interval. Since only two wells in this tive d r a i n a g e and for m o r e efficient E O R
field w e r e c o r e d , the log-derived permeabilities operations.

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