Embed Size (px)
Citation preview
Clay Minerals (1986) 21, 811-826
SOME A P P L I C A T I O N S OF C L A Y M I N E R A L O G Y TO R E S E R V O I R D E S C R I P T I O N
A. H U R S T AND J. S. A R C H E R *
Department of Reservoir Evaluation, Statoil, Forus, Postboks 300, N-4001 Stavanger, Norway and *ERC Energy Resource Consultants Ltd., 15 Welbeck St., London W1M 7PF
(Received 10 May 1985; revised 25 July 1985)
A B S T R A C T: Study of sandstone diagenesis provides information about the origin, texture, distribution and composition of clay minerals, which in turn is used in reservoir description. Three examples of the use of clay mineralogy in reservoir description are given. (1) Kaolinite commonly forms pore-filling cements which are pervasive in specific sandstone intervals. It is shown that water-zone kaolinization homogenizes and lowers the porosity and permeability relative to the oil zone; in a reservoir model different O/K relationships are defined above and below the oil-water contact. (2) An occurrence of chlorite in dish-structured horizons is shown to increase horizontal permeability and decrease formation resistivity. The sensitivity of the neutron porosity log to the chlorite cement reduces the usefulness of the log for porosity evaluation. Uncritical application of wireline logs to define reservoir parameters can give pessimistic reservoir evaluation. (3) Sand production can be related to wettability, which in turn is strongly influenced by clay mineralogy. A perforation strategy to minimize sand production may then be based on knowledge of the clay mineralogy of a reservoir.
Reservoir description requires that geological and petrophysical data are integrated for input to a dynamic three-dimensional reservoir simulation model (Hurst & Archer, 1986) [previous paper]. Porosity (O), permeability (K), water saturation (Sw) and the petrophysical parameter volume shale (Vsaale) are routinely evaluated from wireline logs, sometimes without input of geological data. It is emphasized that all the characteristics, O, K, S w and Vshale, are derived indirectly from log measurements using mathematical or empirical formulae. Clay minerals influence all wireline logs; therefore all wireline logs have some potential for identifying clay minerals. Ideally, different clay minerals should be differentiated by their characteristics as measured by wireline logs (Fertl & Frost, 1980; Almon, 1979).
The claims by some petrophysicists that they are able to identify clay mineral types and proportions by using cross-plots of various wireline log data has traditionally been regarded with circumspection by geologists. Also, the problem of integrating clay mineralogy, measured on #m-scale fractions from gram-weight samples, with petrophysical data (which are average measurements from 0.25 m intervals), leads to some concern among petrophysicists as to the general validity of mineralogical data at reservoir scale. There is perhaps a tendency to fear that clay mineral data will only create problems in reservoir characterization, e.g. by finding fibrous illitic cement (Pallatt et al., 1984). It is not always clear how new data may readily be incorporated into a reservoir model, particularly when there are incompatibilities with existing interpretations.
1986 The Mineralogical Society
812 A. Hurs t andJ . S. Archer
Studies of sandstone diagenesis provide mineralogical data, often including clay mineralogy, which should be routinely applied to reservoir characterization. In this paper, examples are given where clay mineral data are used to describe reservoir zonation above and below an oil-water contact (example 1), in the evaluation of wireline logs (example 2), and to predict the occurrence of intervals particularly sensitive to collapse (sand- production) during hydrocarbon production (example 3).
S A N D S T O N E D I A G E N E S I S
To understand the effect clay minerals have on reservoir characteristics, one must identify not only clay mineral types, but describe their origin, distribution and surface textures. The geochemistry of sandstone diagenesis and clay mineral authigenesis is routinely applied to problems of reservoir stimulation and enhanced recovery (Almon & Davies, 1981; Hearn et al., 1984). Description of clay mineral distribution and texture on a microscopic scale is well-documented. However, macroscopic distribution of clays is usually less well- documented and restricted to examples where clay minerals are visible in hand-specimen, e.g. clay clasts, or kaolinization associated with coal beds. The application of two-dimensional textural data from microscopic examination, commonly representative of a rock area of less than 1 • 10 mm 2, to a reservoir description applicable to fluid movement in intervals tens of metres thick and kilometres in lateral extent clearly requires considerable care.
Quantification of the clay mineralogy alone does not provide sufficient information to evaluate fully the effect of clay minerals on reservoir characteristics. Distribution of small proportions (< 10 vol%) of authigenic clay minerals on a microscopic scale may have a profound effect on a reservoir independent of the specific proportion of each clay mineral (Sommer, 1978; Seeman, 1979; Pallatt et al., 1984).
Integrated analysis of wireline logs may provide independent measurements of clay mineralogy (Quirein et aL, 1981; Ruhovets & Fertl, 1981). If a specific clay mineral can be correlated with log responses, it is possible to assess the distribution of that clay mineral using wireline logs. The problem of relating the scale of observation of clay minerals to thier effect on reservoir characteristics may then be solved by the successful integration of geological and petrophysical methods.
Study of sandstone diagenesis provides models for the genesis of the different authigenic minerals. Authigenic kaolinite forms in porewaters with low ionic concentration and low pH; such porewaters may either be meteoric (Bjorlykke et al., 1979; Hurst & Irwin, 1982), or produced by burial diagenetic reactions in shales (Curtis, 1978; Boles & Franks, 1979). Kaolinite forms pore-filling cements which commonly vary in grain size and surface area:mass ratios, but are generally distributed throughout the pores of a specific sandstone interval. Exceptions to this pervasive distribution are found; e.g. authigenic kaolinite is commonly concentrated in sandstones underlying coal beds and below disconformities.
Chlorite and mixed-layer illite-smectite commonly form grain-coating cements con- centrated within particular intervals. Grain-coating cementation is often associated with primary depositional, or immediately post-depositional, processes. Illite-smectite grain coatings have been interpreted to form by early diagenetic filtration of meteoric water (Walker et al., 1978; Davies et al., 1979). Chlorite grain-coatings have been identified as the clay mineral component of some dish structures (Hurst & Buller, 1984).
Clay mineralogy and reservoir description 813
Illitic cements (fibrous, hairy varieties) occur as pore-filling and pore-lining cements-- textures presumably dependent on their abundance. The structure and texture of fibrous illites are well documented (e.g. McHardy et al., 1982; Gfiven et al., 1980; Nadeau et al., 1984). However, few studies present data on the distribution of illitic cements relative to sedimentary facies (e.g. Sommer, 1978; Almon & Davies, 1979).
R E S E R V O I R D E S C R I P T I O N
Example 1
The reservoir interval is a transitional deltaic/marine sandstone of fine to very coarse (averaging medium) grain size (Fig. 1). An 'average' modal mineralogy (by volume) is: quartz 50-70%, biotite <5%, muscovite 5-10%, K-feldspar 8-12%, plagioclase 2-8%, with minor authigenic kaolinite 2-10%, siderite <5%, pyrite <5% and heavy minerals <2%. Calcite and ferroan calcite occur as isolated nodules commonly comprising >30% of the bulk mineralogy. Micas and heavy minerals are sporadically concentrated in thin (< 10 cm), commonly repetitive, laminae.
Pore-filling kaolinite cement occurs in both the oil zone and the water zone, and despite problems in quantifying, the kaolinite is thought to be most abundant in the water zone. It is postulated that additional kaolinization occurred after hydrocarbon emplacement, hence kaolinite is more abundant in the water zone. The fault block configuration of the reservoir provides data from intervals with very similar sedimentary facies, at similar depth, within both the oil zone and the water zone. There is no evidence to suggest that the intervals studied from the water zone and oil zone have any significant sedimentological differences other than the abundance of kaolinite.
A cross-plot of porosity-permeability (Fig. 2A) shows that there is a different relationship between 13 and K in the oil and water zones. Data in Fig. 2A are derived from similar sedimentological units to those shown in Fig. 1, from a field under evaluation where both oil- and water-saturated intervals have been cored. The preferred reservoir model is one in which different O/K relationships are defined above and below the oil-water contact (Fig. 2A).
In the oil zone, primary sorting exerts a strong control over the relationship between O and K. Kaolinite authigenesis in the water zone is interpreted to have homogenized the effects of primary sorting. Therefore, the reservoir zonation, identified by sedimentary facies in the oil zone, is not continuous into the water zone (Fig. 2B). Reservoir characteristics (O and K) for a sedimentologicaUy-defined reservoir interval (Fig. 3) show that the average O and K of the same interval is lower for the water zone than for the oil zone. Lowering of K does not appear to he uniform throughout the defined interval, a distinctly bimodal log-normal permeability distribution present in the water zone (Fig. 3B) being generated from the presumed less diagenetically-modified, slightly skewed log-normal distribution in the oil zone (Fig. 3A). Generation of a bimodal distribution may be indicative of the occurrence of more intense kaolinite authigenesis in particular horizons.
Thin-section and SEM studies reveal that kaolinite in the water zone is slightly more abundant than in the oil zone, and occurs in an additional textural style. In the oil zone and the water zone kaolinite occurs as 10-30 gm diameter, vermicular crystals (Fig. 4A). In the water zone an additional blocky kaolinite (Fig. 4B) occurs. The coarse kaolinite
814 A. Hurst and J. S, Archer
0
.m
l : o
,o, ,~ :,:..m ;.rex QL 3 b , U .
.t-' ~ 0
U , ,
i l |.+ _-~~ 1r w ca . "
0
A,+o' ,o .~ , - , ~ ~ . - , + , , - ,,,, ,+ P, "~
"D @ . _ 0 . m �9 - - u,, O . - -
o ~ ,- . ,. ~
J+ ++
Clay mineralogy and reservoir description 815
A
K (mD)
1 0 0 0 0 0
1 0 0 0 0
1 0 0 0
100
1 0
o o o o
" "/ ~ o
x x
o o
0.05 0.10 0.15 0 .20 0 .25 0 .30 0.35 0 . 4 0 0 .45
O
t . 5 0
B �9 Fault
a "~_ ~ ' ~ ~.._"~ " ~ ~ ~ ~ ~ _ ~ ~ "~_~ ~ ~.
OWC
FIG. 2. (A) Porosity (O)--permeability (K) cross-plot of similar sedimentary facies buried to similar depths, oil zone (x and stipple), water zone (o and hatching). (B) Schematic cross- section of reservoir described in Fig. 1 and (A). Reservoir zones a, b and c are not continuous
into water zone OWC = oil-water contact.
crystals lower 0 without significantly causing deterioration of K. Smaller blocky kaolinite
crystals are interpreted as causing a slight reduction of porosity, and because of their fine crystal size cause a deterioration of K. Similar clay diagenesis in the water zone is well-documented in the North Sea area (Hancock, 1978; Pallatt et al., 1984).
816
A
50
4 0
30
20
10
A. Hurst andJ. S. Archer
5 0
40
30
20
10
0 ! . I I 0.1 0 .2 0 .3 0 .4 0 .5 0 0.1 0 .2 0 .3 0 .4
�9 log (K) (roD) av. 0 - 2 4 . 4 % av. K=3 .51D
!
0.5
B
50
40
30
20
10
0 n
0 011
50
40
30
20
| la I I I I 0 1 I I ! I a
0.2 0 .3 0 .4 0 ,5 0 0.1 0 .2 0 ,3 0 .4 0 .5
(~ l og (K) (mD) av . 0=23% a v . K = 2 . 8 7 D
FIG. 3. Histogram plots. (A) Oil-zone porosity (13") and permeability (K). (B) Water-zone porosity and permeability. O and K (roD) are measured from core plugs.
Example 2
The reservoir interval (gas-saturated) (Fig. 5) comprises a largely massive marine sandstone with an average grain size of medium sand. All sandstones are highly quartzose and contain (by volume): quartz 55-65%, mica <2%, K-feldspar 2-12%, plagioclase
(a)
Clay mineralogy and reservoir description 817
(b)
FIG. 4. (A) Vermicular kaolinite, scale bar = 10/~m. (B) Blocky kaolinite, restricted to water zone, scale bar = 10/~m.
2-8%, with minor authigenic chlorite 2-5%. Pyrite, calcite and siderite occur as localized concretions. Authigenic kaolinite is rarely detected in thin-section or by SEM. Kaolinite is present in very small amounts.
Chlorite occurs throughout the reservoir interval; however, its mode of occurrence and proportion vary. Chlorite is most abundant in dish-structured horizons as a grain-coating
818 A. Hurst andJ. S. Archer
. , , , -
. . . . . ; I i . f .
f . u *
i .
ooo.o~ ~ ~ - :- " � 9 - : " I �9 ' "
. . . . . . I ! " I
, ~ l ,
I " N ) )1)
) ) ) ) )
o
T i [
i
8
g
Z i -
I
i
A O O I O H L I 1
" 0
o,o 0
-5
E
s::: 0
X
",5
.> ~J
0 :>
, A
Clay mineralogy and reservoir description 819
FIG. 6. Grain-coating chlorite cement typical of dish-structured horizons shown in Fig. 5. Scale bar = 10/tm.
cement (Fig. 6). Where chlorite is less abundant it occurs as partial grain coatings and small pore-fillings. Corresponding to the increase of chlorite cementation, the formation resistivity (RXO) decreases from 2 to 1.1 ohm m -1 and the neutron porosity (PHIN) response increases from 25 to 38 porosity units (Fig. 5).
The relationship between O and K is a function of grain size, sorting and cementation. Core description shows that grain size is fairly constant (350-500/tm mean diameter) and that sorting is poor. Uniform porosity distribution is confirmed by the even sonic (DT) and formation density (RHOB) curves and the core-measured porosity data (Fig. 5). Horizontal permeability (DKLH, Fig. 5) decreases from 0.8-1 to 0.4-0.8 D, corresponding to decreased chlorite content and less dish structures. It appears that the distribution and cementation of authigenic chlorite (and consequently the occurrence of dish structures) is the main factor controlling reservoir character.
An uncritical evaluation of log data, without clay mineral data, may lead to an erroneous petrophysical evaluation of porosity (Fig. 7). For example, if the neutron porosity (PHIN) curve is used in a porosity evaluation, the response caused by chlorite concentration will generate an interval histogram much broader (Fig. 7B) than that for core data (Fig. 7A). Clearly, the PHIN curve should not in this example be used to evaluate porosity without applying a correction factor. DT and RHOB curves are suitable for evaluation of porosity distribution from the available wireline logs.
If chlorite had remained undetected (i.e. no integration of geological and petrophysical data) and the depth-matched log-derived porosity (PHIF, Fig. 5) correlated directly with core permeability, a significantly different porosity/permeability relationship would have been obtained (Figs. 7C,D and Fig. 8). In this example, PHIF is derived from a com- bination of formation density (RHOB) and neutron porosity (PHIN) (cf. Schlumberger,
A
5 0
4 0
3 0
2 0
t 0
( D P O R )
R n r l �9 I I I I I
0 0.1 0 .2 0 .3 0 .4 0 .5 l l l l i
0 O.1 0 .2 O,3 0 .4 0 .5
B
5O
4 0
3 0
20
10
820 A. Hurst and J. S. Archer
(PHIF)
C
5 0
D
5 0
4 0
3 0
2 0
10
4 0
3 0
I I I I I 0 O.1 0 .2 0 .3 0 .4 O.5
K (KLH) (roD)
2 0
10
I | I I I
0 0.1' 0 . 2 0 .3 0 4 0 . 5
K (KLOGH) (roD)
FIG. 7. Porosity 0 and permeability (K) histograms of intervals showia in Fig. 5. (A) He porosity (DPOR), (B) log-evaluated porosity (PHIF), (C) core-measured horizontal
permeability (KLH), (D) log-evaluated permeability (KLOGH).
Clay mineralogy and reservoir description 821
A 10000
1000
KH 100
( r nD )
10
/
/ I I I I I I I I I
0,05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50
0
B
10000
1000
KH 100
( m D )
10
X x X X / /x
f I I I I I I I I I
0.05 0.10 0.15 0.20 0.25 0.30 0.3.5 0.40 0.45 0.50
O
FIG. 8. Cross-plots of porosity and permeability for interval shown in Fig. 5. (A) core data, (B) log-derived 0 and KCORE.
1972) where RHOB is given 2.25 times greater weighting than PHIN. The values of permeability transferred into a simulator, control pressure gradients for a given rate of flow. Use of the porosity/permeability relationship defined in Fig. 8B generates a reservoir model in which K . deteriorates within the dish-structured chlorite-cemented interval, whereas core data (DKLH) show that this is not so, Without applying clay mineralogy to
822 A. Hurst and J. S. Archer
the reservoir evaluation, uncritical interpretation of log data will generate a pessimistic characterization of the reservoir.
Example 3
Production of sand grains is a commonly-occurring feature of hydrocarbon production. Sand may be produced by caving, or collapse around the perforated interval of the borehole due to poor consolidation of the formation. Such sand production normally occurs throughout the hydrocarbon production. A second type of sand production commonly coincides with the onset of water production, and has been shown to be related to the migration of fine particles in the formation, caused by water influx, and is strongly influenced by the formation wettability (Muecke, 1979).
Rock wettability is recognized as of great importance in the displacement of oil by water in reservoirs (Bobeck et al., 1958). The wettability of a rock-fluid system describes the ability of a fluid to spread on a rock surface. In an oil-water-rock system, the wettability refers to the preference of one of the fluids to wet the rock surface. Definition of wetting preference in a porous system may be made in terms of the contact angle (8) of the preferential wetting fluid with a surface (Fig. 9). Contact angles measured through the water phase which are near 0 ~ and 180 ~ are strongly water-wet and strongly oil-wet respectively (Craig, 1971). In a pore capillary system, the capillary pressure, Pc, is described by
20 cos 0 Pc = Pnw -- Pw = - - g
where Pnw - Pw is the pressure difference between the non-wetting (nw) and the wetting (w) fluid, r is the capillary radius, and o the interfacial tension. In a static capillary gravity
0 o w
~ o s ~ OIL ~ / / / / / / / 1 / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / H / / / / / / / / / / / / /
ROCK SURFACE
/7///~////////////I///I/I/////// WATER-WET OIL-WET
FI6. 9. Wettability of oil-water-solid surface.
Clay mineralogy and reservoir description 823
equilibrium, the Pc controls the saturation occurring at a height (H), which is measured as elevation above the free water level, in the transition zone between fluids, i.e.
Pc = gn(pw -- P,w)
where Pw and Pnw are fluid densities and g is the gravity constant. During displacement of oil from a reservoir the wetting character of the rock-fluid system controls both the upstream and downstream contact angles. Retention of oil (residual oil) in pores will depend on the relative magnitudes of capillary, viscous and gravity forces. Relative permeability (Kr) may be strongly influenced by the wettability of clay minerals (Hurst & Archer, 1986). It is therefore vital that lithological samples with wettability characteristics typical of the reservoir are selected for fluid displacement analysis. Fig. 10 illustrates the effect of wettability on K r and residual oil saturation. It is generally believed that most reservoir rocks display mixed wettability with their reservoir fluids (Owens & Archer, 1971).
An application of the effects of wettability to migration of fines (Muecke, 1979) allows clay mineralogy to be applied to a mechanism of sand production from reservoirs. Injection of solvents or surfactants to enhance oil recovery may introduce mutual solvents for oil and water which cause mobilization of formerly stable water-wet particles ('fines'). Typical fines may be clay mineral cements, the mobilization of which would decrease the structural strength of the reservoir and induce collapse of the sandstone fabric (Fig. 11). Knowledge of the clay mineralogy and distribution of clay cements can be applied to the design of a fluid injection programme for minimum formation damage.
Sand production problems are sometimes encountered in reservoir intervals containing concentrations of authigenic clay cements (e.g. Figs 5 and 11). If such zones are
Relative permeability
(Kr)
IMBIBITION DIRECTION DISPLACEMENT
n u ~ B ~ s t r o n g l y w a t e r w e t
,, s t rong ly oil we t
0 Sw 1
FIG. 10. Effect of wettabil i ty on relative permeabil i ty . S w = wett ing phase saturat ion,
K r = relative permeabil i ty, kro = relat ive permeabi l i ty to oil, kr, v = relat ive permeabi l i ty to water.
824 A. Hurst and J. S. Archer
S A N D S T O N E F O R M A T I O N
o 1oo G r a i n s i z e R X O I I F C o h m m - 1
P H I N - I ; : : : ,
.45 -.lj5 ~ 1 2 5 t ' * : : ' ' ' ' '
A
FIG. 11. Idealized reservoir interval containing a zone of grain-coating clay cement 'A' which if left unperforated will minimize sand production caused by fines migration. GR = gamma log (gamma log response is dependent on natural radioactivity of clay cement, i.e. chlorite = no
gamme response), PHIN = neutron porosity, RXO = microresistivity.
recognized prior to commencement potential zones of sand production breakthrough might be avoided.
of production, a policy of perforation avoiding caused by fines migration coincident with water
C O N C L U S I O N S
There is little doubt that clay mineralogy has already contributed significantly to the improvement of reservoir characterization. In the preceding examples, it is shown that small variations of authigenic clay content can have a marked effect on permeability and wireline log responses. It is shown that distribution and texture of authigenic clay cements can determine the extent to which clay mineralogy influences reservoir characteristics. Kaolinite authigenesis is demonstrated to 'homogenize ' pr imary porosity and permeability relationships. Sand production from a water-wet reservoir caused by mobilization of fines coincident with water breakthrough can be anticipated, and possibly controlled, if zones of clay cementation are identified, and subsequently, not perforated.
Clay mineralogy and reservoir description 825
Acquis i t ion of c lay minera l da t a is considered as a vital e lement of reservoir descript ion,
par t icular ly in s i tuat ions where a considerable inves tment is made in the tak ing of
convent iona l cores. Clay minera logy provides impor t an t input to pet rophysica l evaluat ion of wireline logs and analysis of permeabi l i ty data.
A C K N O W L E D G M E N T S
Colleagues in Statoil's Department for Reservoir Geology are acknowledged for their valuable discussions. A. T. Buller is thanked for his encouragement and perceptive criticisms. Frode Hadler-Jacobsen kindly supplied the micrographs of authigenic kaolinite. Tone Lien patiently typed the manuscript. Den Norske Stats Oljeselskap (Statoil) are acknowledged for supporting publication of this paper.
Terminology and headings used in text:
121 porosity K permeability K~ relative permeability S w water saturation Vshal e volume shale Pc capillary pressure CAL caliper (diameter of borehole) log DKLH permeability to air, depth-corrected DPORHE helium porosity DT sonic log GR gamma-ray log KLOGH log-evaluated permeability PHIF PHIN RHOB RHOMA RXO
A P P E N D I X
porosity computed from a combination of log measurements neutron porosity log formation density log matrix density (from core samples) microresistivity log
R E F E R E N C E S
ALMON W.R. (1979) A geologic appreciation of shaly sands. SPWLA 20thAnn. Logg. Symp., WW. ALMON W.R. & DAVIES D.K. (1979) Regional diagenetic trends in the lower Cretaceous Muddy Sandstone,
Powder River Basin. Pp. 379--400 in: Aspects ofDiagenesis (P. A. SchoUe and P. R. Schluger, editors). SEPM Spec. Publ. 26.
ALMON W.R. & DAVmS D.K. (1981) Formation damage and the crystal chemistry of clays. Pp. 81-103 in: Clays and the Resource Geologist (F. J. Longstaffe, editor) Min. Soc. Canada, Short Course Handbook 7.
BJOm~YKKE K., ELVEm~OI A. & MALM O.A. (1979) Diagenesis in Mesozoic sandstones from Spitzbergen and the North Sea--a comparison. GeoL Rundschau 6& 1152-1171.
BOLES J.R. & FRANKS S.G. (1979) Clay diagenesis in Wilcox sandstones of south-west Texas: implications of smectite diagenesis on sandstone cementation. J. Sedim. Petrol 49, 55-70.
BOBEK J.E., MATrAX C.C. & DENEKAS M.O. (1958) Reservoir rock wettability--its significance and evaluation. Pet. Trans., AIME 213, 155-160.
CRAIO F.F. (1971) The reservoir engineering aspects of waterflooding. Soc. Pet. Eng., AIME Monograph, 3. CoRns C.D. (1978) Possible links between sandstone diagenesis and depth-related geochemical reactions
occurring in enclosing mudstones, or. geoL Soc. London 135, 107-118. DAVaES D.K., ALMON W.R., BONIS S.B. & HUNTER B.E. (1979) Deposition and diagenesis of Tertiary-
Holocene volcaniclastics, Guatemala. Pp. 281-306 in: Aspects ofDiagenesis (P. A. Scholle and P. R. Schluber, editors). SEPM Spec. Publ. 26.
826 A. H u r s t and J. S. A r c h e r
FERTL W.R. & FROST E. (1980) Evaluation of shaly clastic reservoir rocks. J. Pet. Tech. Sept, 1641-1645. GUVEN N., HOWER W.F. & DAVIES D.K. (1980) Nature of authigenic illites in sandstone reservoirs. J. Sedim,
Petrol. 50, 761-766. HANCOCK N.J. (1978) Diagenetic modelling in the middle Jurassic Brent sandstones of the Northern North
Sea. Proc. Europ. Offshore Petrol. Conf. Exhib., London, 275-280. HEARN C.L., EBANKS W.J., TYE R.S. & RANGANATHAN V. (1984) Geological factors influencing reservoir
performance of the Hartzog Draw Field, Wyoming. J. Pet. Tech. August, 1335-1344. HUaST A. & ARCHER J.S. (1986) Reservoir description: an overview of the role of geology and clay
mineralogy. Clay Miner. 21, 791-811. HURST A. & BULLER A.T. (1984) Dish structures in some Paleocene deep-sea sandstones (Norwegian Sector,
North Sea): origin of the dish-forming clays and their effect on reservoir quality. J. Sedim. Petrol. 54, 1206-1211.
HURST A. & IRWIN H. (1982) Geological modelling of clay diagenesis in sandstones. Clay Miner. 17, 5-22. MCHARDY W.J., WILSON M.J. & TAXT J.M. (1982) Electron microscope and X-ray diffraction studies of
filamentous illitic clay from sandstones of the Magnus Field. Clay Miner. 17, 23--40. MUECgE T.W. (1979) Formation fines and factors controlling their movement in porous media. J. Pet. Tech.
February, 144-150. NADEAU P.H., TAIT J.M., MCHARDY W.J. & WILSON M.J. (1984) Interstratified XRD characteristics of
physical mixtures of elementary clay particles. Clay Miner. 19, 67-76. OWENS W.W. & ARCHER D.L. (1971) The effect of rock wettability on oil-water relative permeability
relationships. Proc. 45th Ann. Fall Meet. SPE., paper 3034. PALLATT N., WILSON M.J. & MCHAgDY W.J. (1984) The relationship between permeability and the
morphology of diagenetic illite in reservoir rocks. J. Pet. Tech. December, 2225-2227. QtaREIN J.A., BALDWIN J.L., TERRY R.L. & HENDPaX M. (1981) Estimation of clay types and volumes from
well log data--an extension of the global method. Proc. 8th Formation Evaluation Syrup. Canadian Well Logging Soc., Calgary, paper 8.
RUHOVETS N. & FERTL W.R. (1981) Digital shaly sand analysis based on Waxman-Smiths model and log-derived clay typing. Trans. 7th European SPWLA Symp., 21-37.
SCHLUMBERGER (1972) The Essentials of Log Interpretation Practice. Services Techniques Schlumberger, 58 pp.
SEEMAN U. (1979) Diagenetically formed interstitial clay minerals as a factor in Rotliegende sandstone reservoir quality in the Dutch sector of the North Sea. J. Petrol. Geol. 1, 55-62.
SOMMER F. (1978) Diagenesis of Jurassic sandstones in the Viking Graben. J, Geol. Soc. London 135, 63-67. WALKER T.R., WAUGH B. & CRONE A.J. (1978) Diagenesis of first-cycle desert alluvium of Cenozoic age,
southwestern U.S. and northwestern Mexico. Geol. Soc. Am. Bull. 89, 19-32.
