uIntroduction
uClay
composition & log analysis
uOutcrop
analog seal data
uAngola
seal data
u Seal
stratigraphy
uConclusions
uReferences
uAcknowledgements
uIntroduction
uClay
composition & log analysis
uOutcrop
analog seal data
uAngola
seal data
u Seal
stratigraphy
uConclusions
uReferences
uAcknowledgements
uIntroduction
uClay
composition & log analysis
uOutcrop
analog seal data
uAngola
seal data
u Seal
stratigraphy
uConclusions
uReferences
uAcknowledgements
uIntroduction
uClay
composition & log analysis
uOutcrop
analog seal data
uAngola
seal data
u Seal
stratigraphy
uConclusions
uReferences
uAcknowledgements
uIntroduction
uClay
composition & log analysis
uOutcrop
analog seal data
uAngola
seal data
u Seal
stratigraphy
uConclusions
uReferences
uAcknowledgements
uIntroduction
uClay
composition & log analysis
uOutcrop
analog seal data
uAngola
seal data
u Seal
stratigraphy
uConclusions
uReferences
uAcknowledgements
uIntroduction
uClay
composition & log analysis
uOutcrop
analog seal data
uAngola
seal data
u Seal
stratigraphy
uConclusions
uReferences
uAcknowledgements
uIntroduction
uClay
composition & log analysis
uOutcrop
analog seal data
uAngola
seal data
u Seal
stratigraphy
uConclusions
uReferences
uAcknowledgements
|
(Figures 1,2-1, 1,2-2,
1,2-3, and 1,2-4)
 |
Figure 1,2-1. Photomicrograph and
mercury-injection curves (MICP) of six shale types .
A. Shale type 1, which is
well-laminated and slightly silty shale.
B. Shale type 2, which is laminated and
moderately silty shale.
C. Shale type 3, which is mottled and
moderately silty shale.
D. Shale type 4, which is mottled, very
silty shale.
E. Shale type 5, which is
interlaminated shale and siltstone.
F. Shale type 6, which is slightly
silty and calcareous claystone. |
 |
Figure 1,2-2. Mercury-injection curves
(MICP) for three shale types . Type 2 shales (red) have a mean
critical injection pressure of 6938 psia. Type 3
shales have a
mean critical value of 6809 psia. Type 6 shales exhibit a mean
critical injection pressure of 11,027 psia. |
 |
Figure 1,2-3. Shale types 1, 2, and 6
exhibit excellent top (membrane) seal potential. Silt-rich shales
( types 3, 4 and 5) have considerably lower critical seal
pressures. |
 |
Figure 1,2-4. The distribution of
measured capillary pressure values in the data set fits within the
distribution of critical seal pressures (10% nonwetting phase
saturation) from samples in other deepwater wells, analyzed to
date. |
Analyses of Tertiary-aged shales from
deepwater depositional settings (e.g., offshore West Africa, Brazil, and
Gulf of Mexico) reveal the
common occurrence of six shale end-member types (shale microfacies).
Each shale microfacies has distinctive textures and fabrics, which
represent variations in depositional conditions.
Additionally, systematic patterns of
seal character are evident where these shale types are organized within
a sequence stratigraphic context. In general, silt-poor shale types 1
and 2 (representing upper transgressive units) and some condensed
intervals (shale type 6) offer good to excellent seal potential. In
contrast, silt-rich highstand shales ( types 3 and 4) and lowstand shales
(type 5) have relatively low sealing capacities. Increased percentages
of detrital silt grains reduce sealing capacity by inhibiting mechanical
compaction, thereby allowing the preservation of relatively
large-diameter pore throats.
Seal potential is quantified using
mercury-injection capillary pressure (MICP) analysis (Berg, 1955;
Showalter, 1977; Jennings, 1987; Watts, 1987). Shale facies are defined
petrographically and interpreted sedimentologically on the basis of
fabric and texture (e.g., Schieber, 1999; Dawson, 2000). The content of
detrital silt appears to influence the effectiveness of mechanical
compaction processes (Krushin, 1997), shale permeability (Dewhurst et
al., 1999), and ultimately, sealing capacity (Almon et al., 2002; Dawson
et al., 2003).
The shale samples, MICP of which are
illustrated in Figure 1,2-2, have very good to excellent membrane seals.
Shapes of injection profile curves indicate that there are three pore
structure families in this data set, which can be related to total clay
content and shale fabric. Samples are color-coded by shale type. Type 2
shales (red) have a mean critical injection pressure of 6938 psia. Type
3 shales (red) have a mean critical value of 6809 psia. Type 6 shales
(red) exhibit a mean critical injection pressure of 11,027 psia
indicating exceptional seal potential, assuming the absence of open
microfractures.
(Figures 3-1, 3-2,
3-3, 3-4,
3-5, 3-6,
3-7, and 3-8)
Total clay content varies from 48 to 80
percent (mean 67 %; standard deviation 9%). Quartz content ranges from
10 to 34 percent (mean 19 %; standard deviation 7 %). The amount of
K-feldspar varies from 3 to 11 percent (mean 6 %; standard deviation 2
%). Plagioclase feldspars are less abundant (1 to 4 %) with a mean value
of 2 percent and a standard deviation of 0.8 percent. Siderite abundance
ranges from 1 to 8 percent (mean 3.5 %; standard deviation 1.9 %).
Pyrite, ankerite, and calcite are minor accessory phases in the marine
shales. Clay mineralogy data suggest that these samples represent a
single compositional group with relatively limited variability.
Wire-line log response is used commonly to estimate total clay content,
porosity, and V-shale. A cross-plot of total clay and GR log-response
shows improved correlation if the data are considered in terms of shale
facies. A graph of measured porosity versus neutron density porosity
indicates that log responses tend to over-estimate porosity in
argillaceous rocks by an average of 3 to 5 porosity units. Likewise, log
evaluation techniques generally over-estimate V-shale values relative to
measured total clay content.
(Figures 4-1, 4-2,
4-3, and 4-4; Table
4-1)
Shale microfacies are recognizable in closely
spaced shale samples from outcrops (Cretaceous, Wyoming). Each shale
end-member type has distinctive fabrics, MICP character, and
composition. Seal character varies in a predictable manner within a
sequence stratigraphic framework. Well laminated, clay- and organic-rich
shales from uppermost transgressive units exhibit excellent seal
potential.
High-resolution sequence stratigraphy reveals
that this group of samples in this data set represent three of the six
shale types that typify deepwater marine depositional settings. Shale
type 2 occurs with 3rd- and 4th-order condensed sections and basal parts
of transgressive stratal packages. Shale type 3 occurs mainly with silt-
and sand-rich 4th-order lowstand units. Type 6 shales represent the most
distal shale facies and record pelagic sedimentation with minimal
bioturbation and slow sedimentation.
MICP values and porosity are reduced
significantly in the upper TST interval relative to all parts of the HST
interval. The reduced porosity in clay-rich TST shales is attributed to
improved organization of particles (well-developed laminar fabrics) as
well as the precipitation of Fe-carbonate cements during early submarine
diagenesis.
Additionally, there is a major difference in
the permeability of TST and HST shales. Within the Lewis HST there is a
weak trend of upward increasing permeability; this trend appears to
correlate with a vertical increase in the content of detrital silt.
(Figures 5-1, 5-2,
5-3, 5-4,
5-5, 5-6,
5-7, and 5-8)
 |
Figure 5-1. Composition of three shale
types in offshore Angola. |
 |
Figure 5-2. Shapes of mercury-injection
curves (MICP) of four shale types indicate that they represent
three classes of pore structure. A. Curves for shale types 4 and
5. B. Curves for shale type 3. C. Curves for shale type 2. D.
Graphs of MICP at 10% nonwetting saturation (PSIA) for shale types
2, 3, and 4. |
 |
Figure 5-3. MICP plots, plots of
pore-throat size distribution, and photomicrographs of three shale
types .
A. Shale type 2, seal for pay sections:
Oil: 860-1175 ft Gas: 1000-1355 ft.
B. Shale type 3, seal for pay sections:
Oil: 935-1235 ft Gas: 1125-1480 ft.
C. Shale type 4, seal for pay sections:
Oil: 715-900 ft Gas: 885-1115 ft. |
 |
Figure 5-4. MICP plots, plots of
pore-throat size distribution, and stratigraphic positions of
three shale types , as shown on wire-line log. |
 |
Figure 5-5. Frequency distribution
showing maximum sealing potential (10 percent nonwetting phase
saturation) of Tertiary mudstones, offshore Angola. These samples
(yellow) fit within the range of other seal data (red) from
offshore Angola wells. |
 |
Figure 5-6. Critical injection pressure
(10 percent nonwetting saturation) exhibits a strong correlation
with depth of burial for mudstone types 2 and 3 from offshore
Angola. |
 |
Figure 5-7. Total clay content
correlates strongly with 10 percent nonwetting saturation in
mudstone types 2 and 3 from offshore Angola. |
 |
Figure 5-8. Frequency distribution
showing maximum sealing potential (10 percent nonwetting phase
saturation) of Tertiary mudstones, offshore Angola.
Mudstone types
2 and 3 (yellow) exhibit a mean value that exceeds the mean value
of the other seal data (red) from offshore Angola wells.
|
Three distinctive mudstone lithotypes are
present in offshore Angola samples based on differences in composition
and fabric: silt-rich claystones and argillaceous siltstones; calcareous
shales claystones; and silt-poor sideritic claystones.
Shapes of mercury-injection curves (MICP
analysis) allow the recognition of three classes of pore structure
(i.e., seal types ). Silt-rich samples (type 4) have relatively low
injection pressures. In contrast, carbonate-cemented silt-poor samples
(type 2) have injection pressures that exceed 1,000 psia. Type 3 samples
have intermediate injection pressures.
Each shale type occupies a particular
stratigraphic position. Type 2 shales represent upper transgressive and
condensed intervals. Type 3 shales occur in middle to lower parts of
transgressive units, and very silty (type 4) shales represent lowstand
and highstand stratal packages.
Seal Stratigraphy
(Figures 6-1, 6-2, and
6-3)
Each shale facies occupies a limited
stratigraphic range where considered within a high-resolution (wire-line
log scale) sequence stratigraphic framework. Enhanced membrane (top)
sealing capacity occurs consistently within the upper parts of
shale-dominated transgressive units. Lower sealing capacities are
characteristic of silty shales from highstand, lowstand and lower parts
of transgressive stratal packages.
Six shale types are recognizable within
deepwater marine depositional settings (based on differences in shale
fabric and MICP analyses). These shale types appear to correspond with
high-frequency (wire-line log scale) stratigraphic fluctuations.
Clay-rich shale types 1 and 2 consistently
have excellent seal potential. Silt-rich mudstones (shale types 3, 4 and
5) have relatively low seal capacities. There is a strong positive
correlation between total clay content and critical seal pressure (10%
non-wetting phase saturation). Carbonate-cemented mudstones (shale type
6) can have excellent to exceptional membrane seal capacity , but they
are brittle and tend to fracture.
Variations in depositional fabric strongly
influence seal character. In particular, the presence of laminar fabric,
low (<10%) content of detrital silt (siliciclastic and/or bioclastic),
and elevated content (> 70%) of detrital clay matrix appear to enhance
seal potential of marine shales.
Excellent to very good seal capacity is found
in shales from uppermost 3rd- and 4th-order transgressive units and some
condensed intervals. Shales from silt-rich parts of highstand and
lowstand stratal packages have markedly reduced seal capacities. Both
silt content and the organization of silt (laminae and mottles)
influence seal character.
Wire-line log derived parameters appear to
have reasonable ability to estimate critical seal pressure in these
samples. The entire set of critical injection pressures can be predicted
from log-derived bulk density values. Seal capacity for shale type 6 can
be predicted from GR-log data.
Almon, W.R., Dawson, Wm. C.,
Sutton, S.J., Ethridge, F.G., and Castelblanco, B., 2002, Sequence
stratigraphy, facies variation and petrophysical properties in deepwater
shales, Upper Cretaceous Lewis Shale, south-central Wyoming: GCAGS
Transactions, v. 52, p. 1041-1053.
Berg, R.R., 1975, Capillary
pressures in stratigraphic traps: AAPG Bulletin, v. 59, p. 939-956.
Dawson, Wm. C., 2000, Shale
microfacies: Eagle Ford Group (Cenomanian-Turonian) north-central Texas
outcrops and subsurface equivalents: GCAGS Transactions, v. 50, p.
607-621.
Dawson, Wm. C., and Almon,
W.R., 2002, Top seal potential of Tertiary deep-water Gulf of Mexico
shales: GCAGS Transactions, v. 52, p. 167-176.
Dewhurst, D.Y., Yang, Y., and
Aplin, A.C., 1999, Permeability and flow in natural mudstones, in
Aplin, A.C. et al., eds., Muds and Mudstones, Geological Society London
Special Publication 38, p. 23-43.
Downey, M. W., 1984,
Evaluating seals for hydrocarbon accumulations: AAPG Bulletin, v. 68, p.
1752-1763.
Jennings, J.J., 1987,
Capillary pressure techniques: application to exploration and
development geology: AAPG Bulletin, v. 71 (10), p. 1196-1209.
Krushin, J.T., 1987, Seal
capacity of non-smectite shales, in R. C. Surdam, ed., Seals,
Traps, and the Petroleum System: AAPG Bulletin, v. 67, p. 31-67.
Schieber, J., 1999,
Distribution of mudstone facies in Upper Devonian Sonyea Group of New
York: Journal Sedimentary Research, v. 69, p. 909-925.
Showalter, T.T., 1979, Mechanics of secondary hydrocarbon
migration and entrapment: AAPG Bulletin, 63, p. 723-760.
Sutton, S.J., Ethridge, F.G., Almon, W.R., and Dawson,
Wm. C., 2004, Variable controlling sealing capacity of Lower and Upper
Cretaceous shales, Denver Basin, Colorado: AAPG Bulletin – accepted for
publication.
Watts, N.L., 1987,
Theoretical aspects of cap- rock and fault seals for single- and
two-phase hydrocarbon columns: Marine and Petroleum Geology, v. 4, p.
274-307.
We thank ChevronTexaco for granting
permission to present these data and interpretations. W.T. Lawrence
prepared thin sections and assisted with photography. E. Donovan and J.L.
Jones provided SEM images, and D.K. McCarty completed XRD analyses. R.
Lytton offered paleontological data and biostratigraphic
interpretations. Poro-Technology, Houston, TX, conducted MICP analyses.
Graphic design by L.K. Lovell.
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