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PSPrevious HitSealNext Hit Character and Variability Within Deep-Marine Depositional Systems: Previous HitSealNext Hit Quantification and Prediction

By

William R. Almon1 and William C. Dawson1

 

Search and Discovery Article #40125 (2004)

 

*Adapted from poster presentation at AAPG Annual Meeting, Dallas, Texas, April 18-21, 2004. closely related poster/article, prepared and presented by the authors and S.J. Johansen, is entitled “Previous HitSealNext Hit and Reservoir Characterization of Upper Slope Fan Lithofacies:Example of High-Frequency Variability,” (Search and Discovery Article #40124).

 1ChevronTexaco, Bellaire, TX ([email protected]; [email protected])

 

Abstract 

Seals are a key element of petroleum systems, yet they have received limited systematic study. Textural and compositional variations permit the recognition of six shale lithofacies in Tertiary, deep-marine, depositional settings. Each shale type end-member has distinctive textures and fabrics, which record variations in depositional conditions. Textural and compositional variations of shales, considered within the context of sequence stratigraphy, provide a basis for Previous HitsealNext Hit risk assessment. As determined from mercury injection capillary pressure (MICP) Previous HitanalysisNext Hit, the pressure required to attain critical Previous HitsealNext Hit pressure (10% non-wetting saturation) varies over a considerable range (15 to 20,000 psia). Tertiary shales from offshore Brazil have consistently low critical Previous HitsealNext Hit pressures relative to age-equivalent shales from offshore West Africa. Tertiary shales from wells in the Previous HitGulfNext Hit of Mexico have intermediate MICP values (mean: 4,700 psia). The organization of shale facies within a sequence stratigraphic framework reveals systematic variations in Previous HitsealNext Hit character. Silt-poor shales from uppermost transgressive systems tracts, and some condensed shales, have good to excellent Previous HitsealNext Hit potential. In contrast, silt-rich shales from highstand and lowstand systems tracts have moderate to low sealing capacities. Previous HitSealNext Hit quality generally increases as total clay and carbonate content increase; other compositional variables have limited predictive relationship with Previous HitsealNext Hit character. Likewise, log-derived parameters lack significant potential to accurately predict critical nonwetting saturation values. Additional Previous HitsealNext Hit variability factors include changes in the rate of deposition, early marine cementation, and depositional fabric. Available data provide a compelling argument for textural control of Previous HitsealNext Hit character induced by high-frequency stratigraphic cycles.

 

 

uAbstract

uIntroduction

uClay composition & log Previous HitanalysisNext Hit

uOutcrop analog Previous HitsealNext Hit data

uAngola Previous HitsealNext Hit data

uPrevious HitSealNext Hit stratigraphy

uConclusions

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uClay composition & log Previous HitanalysisNext Hit

uOutcrop analog Previous HitsealNext Hit data

uAngola Previous HitsealNext Hit data

uPrevious HitSealNext Hit stratigraphy

uConclusions

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uClay composition & log Previous HitanalysisNext Hit

uOutcrop analog Previous HitsealNext Hit data

uAngola Previous HitsealNext Hit data

uPrevious HitSealNext Hit stratigraphy

uConclusions

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uClay composition & log Previous HitanalysisNext Hit

uOutcrop analog Previous HitsealNext Hit data

uAngola Previous HitsealNext Hit data

uPrevious HitSealNext Hit stratigraphy

uConclusions

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uClay composition & log Previous HitanalysisNext Hit

uOutcrop analog Previous HitsealNext Hit data

uAngola Previous HitsealNext Hit data

uPrevious HitSealNext Hit stratigraphy

uConclusions

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uClay composition & log Previous HitanalysisNext Hit

uOutcrop analog Previous HitsealNext Hit data

uAngola Previous HitsealNext Hit data

uPrevious HitSealNext Hit stratigraphy

uConclusions

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uClay composition & log Previous HitanalysisNext Hit

uOutcrop analog Previous HitsealNext Hit data

uAngola Previous HitsealNext Hit data

uPrevious HitSealNext Hit stratigraphy

uConclusions

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uClay composition & log Previous HitanalysisNext Hit

uOutcrop analog Previous HitsealNext Hit data

uAngola Previous HitsealNext Hit data

uPrevious HitSealNext Hit stratigraphy

uConclusions

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Introduction

(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) Previous HitsealNext Hit potential. Silt-rich shales (types 3, 4 and 5) have considerably lower critical Previous HitsealNext Hit pressures.

Figure 1,2-4. The distribution of measured capillary pressure values in the data set fits within the distribution of critical Previous HitsealNext Hit 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 Previous HitGulfNext Hit 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 Previous HitsealNext Hit 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 Previous HitsealNext Hit 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.  

Previous HitSealNext Hit potential is quantified using mercury-injection capillary pressure (MICP) Previous HitanalysisNext Hit (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 Previous HitsealNext Hit potential, assuming the absence of open microfractures.

 

Clay Composition and Log Previous HitAnalysisNext Hit

(Figures 3-1, 3-2, 3-3, 3-4, 3-5, 3-6, 3-7, and 3-8) 

Figure 3-1. This bulk composition plot shows the variation in total clay abundance, quartz + feldspar + pyrite volume and cement (calcite + dolomite + siderite + ankerite) content. Composition varies over significant range.  

Figure 3-2. Plotting the compositional variation of the bulk clay types on a ternary graph of kaolinite, 2:1 aluminum clay and 2:1 iron clay + chlorite + trioctahedral 1:1 clay abundance reveals no significant compositional variation. All samples appear to belong to a single family with limited variation. 

Figure 3-3. Plotting the compositional variation of the less than two-micron-size fraction on a ternary graph as functions of kaolinite, illite, and illite/smectite volume indicates that composition is moderately variable. There appears to be a single compositional group, which is dominated by mixed-layer illite/smectite. 

Figure 3-4. Kaolinite and Ro-ordered illite/smectites are major components of these seals, and their abundances appear to compensate for each other. Illite is a minor component of the less than 2-micron fraction of these shale samples. 

Figure 3-5. The abundance of iron-rich clay minerals exhibits an irregular, but decreasing, trend with increasing depth of burial. The abundances of 2:1 aluminum clay and kaolinite vary in a compensatory manner. 

Figure 3-6. Plotting the total clay content against normalized Gamma Ray log response suggests that the two parameters are essentially unrelated for facies 2. Facies 3 and facies 6 display moderate to good correlations between the parameters. Samples labeled by measured depth.  

Figure 3-7. Cross plot of GR-log response and critical Previous HitsealNext Hit pressure shows a weak correlation for the six shale facies considered simultaneously. However, shale type 6 (blue line) exhibits a moderate to good correlation value. 

Figure 3-8. Graph of critical Previous HitsealNext Hit pressure and log-derived bulk density. These data reveal that the two parameters are related moderately. Data labeled by sample depth. 

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.

 

Outcrop Analog Previous HitSealNext Hit data

(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. Previous HitSealNext Hit character varies in a predictable manner within a sequence stratigraphic framework. Well laminated, clay- and organic-rich shales from uppermost transgressive units exhibit excellent Previous HitsealNext Hit 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.

 

Angola Previous HitSealNext Hit Data

(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, Previous HitsealNext Hit for pay sections: Oil: 860-1175 ft Gas: 1000-1355 ft.

B. Shale type 3, Previous HitsealNext Hit for pay sections: Oil: 935-1235 ft Gas: 1125-1480 ft.

C. Shale type 4, Previous HitsealNext Hit 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 Previous HitsealNext Hit 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 Previous HitsealNext Hit 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 Previous HitanalysisNext Hit) allow the recognition of three classes of pore structure (i.e., Previous HitsealNext Hit 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.

 

Previous HitSealNext Hit Stratigraphy

(Figures 6-1, 6-2, and 6-3) 

Figure 6-1. High resolution sequence stratigraphy of this interval from offshore Nigeria shows that the samples are from two sand-rich, high frequency lowstand systems tracts and the 3rd order condensed section below the 6.3 Ma sequence boundary. Samples labeled by critical capillary pressure. The silty LST shale has a lower critical Previous HitsealNext Hit pressure (5,339 psia).

Figure 6-2. High resolution sequence stratigraphy, offshore Nigeria, indicates that the sample from this interval is from the base of a relatively sand-rich 4th order lowstand systems tract near the middle of the 3rd order LST. The best potential seals in the 4th order condensed sections were not sampled. Samples labeled by critical capillary pressure.

Figure 6-3. Offshore Nigeria high frequency sequence stratigraphy reveals that the samples in this interval mostly represent the sand-rich portions of 4th order lowstand systems tracts. The best Previous HitsealNext Hit (9,420’ MD) probably represents a very high frequency condensed section. Samples labeled by critical capillary pressure.  

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.

 

Summary and Conclusions 

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 Previous HitsealNext Hit potential. Silt-rich mudstones (shale types 3, 4 and 5) have relatively low Previous HitsealNext Hit capacities. There is a strong positive correlation between total clay content and critical Previous HitsealNext Hit pressure (10% non-wetting phase saturation). Carbonate-cemented mudstones (shale type 6) can have excellent to exceptional membrane Previous HitsealNext Hit capacity, but they are brittle and tend to fracture. 

Variations in depositional fabric strongly influence Previous HitsealNext Hit 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 Previous HitsealNext Hit potential of marine shales. 

Excellent to very good Previous HitsealNext Hit 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 Previous HitsealNext Hit capacities. Both silt content and the organization of silt (laminae and mottles) influence Previous HitsealNext Hit character. 

Wire-line log derived parameters appear to have reasonable ability to estimate critical Previous HitsealNext Hit pressure in these samples. The entire set of critical injection pressures can be predicted from log-derived bulk density values. Previous HitSealNext Hit capacity for shale type 6 can be predicted from GR-log data.

 

References 

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 Previous HitsealNext Hit potential of Tertiary deep-water Previous HitGulfNext Hit 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, Previous HitSealNext Hit 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 Previous HitfaultTop seals for single- and two-phase hydrocarbon columns: Marine and Petroleum Geology, v. 4, p. 274-307.

 

Acknowledgements 

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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