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PSSeal and Reservoir Characterization of Upper Slope Fan Previous HitLithofaciesNext Hit:

Example of High-Frequency Variability

By

William C. Dawson1, William R. Almon1, and S.J. Johansen2

 

Search and Discovery Article #40124 (2004)

 

*Adapted from poster presentation at AAPG Annual Meeting, Dallas, Texas, April 18-21, 2004; closely related poster/article, prepared and presented by Wm. R. Almon and Wm. C. Dawson, is entitled "Seal Character and Variability Within Deep-Marine Depositional Systems: Seal Quantification and Prediction" (Search and Discovery Article #40125).

 

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

2Ameriven, Venezuela

 

Abstract 

Conventional cores of a lowstand sequence (interpreted as a slope fan) reveal fine-scale variability within potential seal and reservoir units and provide insights concerning depositional process, sedimentation rates, and stratigraphic compartmentalization, which are below wire-line log and seismic resolution. The lower cored interval consists of dark gray to black foraminiferal shale representing slow (hemipelagic to hemi-turbiditic) deposition during a highstand. This maximum flooding shale is a major correlation marker because of its distinct gamma ray signature; it has an erosional upper contact (sequence boundary). This erosional contact is overlain by stacked, fining-upward stratal packages consisting of: deformed, argillaceous, fine-grained sandstones; sandy mudstones; and very silty gray shales. The sand-prone units consist of thinly interstratified shale, siltstone, and sandstone interpreted as blocks of levee deposits that probably slumped into channels. The interstratified sandy mudstones represent thin debris flows. Compartmentalization by numerous shale laminations and clay smears (along micro-faults) is conspicuous. The character of this argillaceous slope-fan reservoir is interpreted as poor (< 10% porosity). Results of high-pressure mercury capillary injection Previous HitanalysisNext Hit reveal excellent seal character (10% nonwetting saturation > 10,000 psia) is exhibited by these shales below the sequence boundary. In contrast, silty shales and argillaceous siltstones from the overlying lowstand units have moderate to poor seal potential. Seal character is related to shale texture and fabric, content of detrital silt, early marine diagenesis (carbonate cementation), and stratigraphic position. These data provide a compelling argument for textural control of seal character induced by high-frequency sedimentary cycles.

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uIntroduction

uCore descriptions

uAngola seal data

uSeal stratigraphy

uReservoir character

uSummary

uReferences

uAcknowledgements

 

 

Introduction

(Figures 1,2-1, 1,2-2, and 1,2-3)

 

Several important discoveries have been made in channelized slope fans along the margin of West Africa and other deepwater basins (Weimer et al., 2000; Prather, 2003). Seismic elements isolated from within these muddy slope packages commonly exhibit sinuous patterns on plan-view maps (Kolla et al., 2001; and Fonnesu, 2003). In offshore Angola, and elsewhere, these sinuous features are interpreted as migrating deep marine channels that acted as conduits for turbidity flows (e.g., Sinclair and Tomasso, 2002). High-resolution data (wire-line logs and cores) reveal very complex association of Previous HitlithofaciesNext Hit within this depositional setting.  

Considerable by-passed oil (~30% OOIP) can be trapped in thin-bedded channel-margin Previous HitlithofaciesNext Hit (Weimer et al., 2000). Recognition of shale occurrences, bed thickness and geometries, and variations in net-to-gross are major issues related to maximizing hydrocarbon recovery from fine- to very fine-grained, channel-margin reservoirs and associated channel-levee units. In particular, slumping, small-scale faulting, and the presence of mud drapes reduce intra-reservoir connectivity and lower recovery efficiency. Furthermore, facies-influenced diagenesis can induce variations in reservoir character.

 

Core Descriptions

(Figure 3-1) 

 

General Statement 

Fine-scale variability in Previous HitlithofaciesNext Hit and reservoir character is not evident from seismic data. Detailed (foot-by-foot) comparison of cores and wire-line log curves is critical to the development of reservoir models. This sub-seismic variability may control the economic viability of a prospect.

 

 8035 to 8057 feet  

Lithology: Yellowish-orange, fine-grained sandstones, interstratified with dark gray shales, argillaceous siltstones, and pebbly mudstones. Convoluted bedding is developed throughout.

Wire-line log character: GR curve has an irregular profile reflecting thin alteration of shales and sandstones with values ranging from 30 to 80 AMP units. Resistivity log compromised by washout and caving of bore hole.

Interpretation: Lowstand systems tract (slope fan depositional system). Probable abandonment channel filled with slumped channel-levee blocks and debris flow lags.

 

8057 to 8068.4 feet  

Lithology: Moderate dark gray to grayish black noncalcareous shales. Sub-fissile with scattered lenses of siltstone. Bedding ranges from planar to convoluted.

Wire-line log character: Slightly elevated GR (~ 90 API units) with low resistivity values (1.2 to 2 ohms).

Interpretation: Minor condensed interval separating two stacked channel-levee units or shale-filled channel (abandoned channel).

 

 8068.4 to 8105.25 feet  

Lithology: Complex of thinly interstratified oil-stained, yellowish-gray, fine-grained sandstones, argillaceous siltstones, dark gray shales, and pebbly mudstones. Exhibits syndepositional deformation (convoluted laminae) and microfaulting.

Wire-line log character: GR ranges from 20 to 85 API units (fining upward). Resistivity readings vary between 2.5 (siltstones) and 45 ohms (oil-bearing sandstones).

Interpretation: Lowstand systems tract (slope-fan depositional setting). Probable abandoned channel filled with slumps (levee-derived) and debris flows.

 

8105.25 to 8117.5 feet  

Lithology: Grayish black to brownish black shales. Less calcareous than underlying unit. Sub-fissile with moderately developed laminations.

Wire-line log character: Modest resistivity (~ 25 ohms) with depressed sonic (100 to 110 ms/ft). Exhibits prominent GR spike (160 to 175 API units).

Interpretation: Highstand systems tract or initial falling stage systems tract.

 

8117.5 to 8123 feet 

Lithology: Grayish black, calcareous and pyritic shale. Exhibits blocky fracture and faint laminations (accentuated by concentrations of foraminifer tests).

Wire-line log character: High GR (130 to 150 API units); elevated resistivity (> 40 ohms).

Interpretation: Maximum flooding shale.

 

Angola Seal Data

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

Figure 4-1. 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.

G. Graphs of mercury-injection curves (MICP) at 10% nonwetting saturation (PSIA) for the six shale types.

Figure 4-2. 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 mercury-injection curves (MICP) at 10% nonwetting saturation (PSIA) for shale types 2, 3, and 4.

Figure 4-3. Mercury-injection curves (MICP), 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 4-4. Mercury-injection curves (MICP), plots of pore-throat size distribution of three shale types, and their stratigraphic positions, as shown on wire-line log.

Figure 4-5. 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 4-6. 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 4-7. Total clay content correlates strongly with 10 percent nonwetting saturation in mudstone types 2 and 3 from offshore Angola.

Figure 4-8. 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.

 

Our seal analyses reveal the common presence of six recurring shale types in deepwater depositional settings. Shale types 1, 2, and 6 exhibit excellent top (membrane) seal potential. Silt-rich shales (types 3, 4, and 5) have considerably lower seal capacity. 

Shapes of mercury-injection curves (MICP Previous HitanalysisNext Hit) 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 1000 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 5-1 and 5-2) 

Figure 5-1. Shale facies and seal capacity--mercury-injection (MICP) curve, distribution of pore-throat diameters, and photomicrographs of samples--within the context of sequence stratigraphy, offshore Angola, calibrated on well log. TST: Transgressive Systems Tract shale. LST: Lowstand Systems Tract shale. HST: Highstand Systems Tract shale. MFS: Minimum Flooding Shale.

Figure 5-2. Shale composition and clay-mineral composition.

A. Total clay content varies from 42 to 67 percent (mean 54%). The content of detrital quartz ranges from 16 to 28 percent (mean 23%). Detrital feldspars, pyrite, and carbonates are accessory (2 to 7 percent) components.

B. The dominant clay type is mixed-layer illite/smectites (mean 46%). Illite (mean 38%) and kaolinite (mean 14%) are major components of all samples.

 

This core penetrated stacked submarine channels, which are encased in marine shales. Our data show clearly that shale facies and variations in shale fabric are important factors in determining seal competency. Shale facies and seal capacity vary within the context of sequence stratigraphy.  

The underlying fossiliferous black shale has exceptional seal character, and the overlying dark gray fissile shale (probable condensed interval) exhibits excellent seal potential. The sequence boundary at 8105 ft is a significant pressure barrier. These marine shales are expected to have lateral continuity exceeding that of the channelized sandstone units.

 

Reservoir Character

(Figures 6-1, 6-2, 6-3, 6-4, 6-5, 6-6, 6-7, 6-8, 6-9, 6-10, 6-11, 6-12, and 6-13) 

Figure 6-1. Photomicrographs of fine-grained channel-margin reservoir, medium-grained channel-axis reservoir, and levee deposit. 

Figure 6-2. At a given burial depth, fine-grained subarkosic sandstones have lower porosity relative to medium-grained, quartzose sandstones. Also, porosity in the fine grained-sandstones decreases more rapidly during burial.

Figure 6-3. Fine-grained sandstones have lower permeability relative to medium-grained sandstones in this model. Fine-grained sandstones exhibit a more rapid loss of permeability during burial.

Figure 6-4. At a given burial depth, fine-grained (subarkosic) sandstones have less macroporosity relative to medium-grained, quartzose sandstones. Also, porosity in the fine-grained sandstones decreases more rapidly during burial.  

Figure 6-5. Fine-grained sandstones are more susceptible to porosity reduction by quartz cementation as compared with medium-grained sandstones in this model.

Figure 6-6. At a given burial depth, channel-margin sandstones have less porosity relative to coarser channel-axis sandstones. Also, the rate of porosity loss in channel-margin sandstones exceeds that of the modeled channel-axis sandstones.

Figure 6-7. Channel-margin sandstones have lower permeability relative to channel-axis sandstones, and model results show channel-margin sandstones losing permeability more rapidly during burial.

Figure 6-8. At a given burial depth, channel-margin sandstones have considerably less macroporosity relative to coarser grained channel-axis sandstones. Also, porosity in channel-margin sandstones decreases more rapidly during burial.

Figure 6-9. Channel-margin sandstones are more susceptible to porosity reduction by quartz cementation as compared with channel-axis sandstones in this model.  

Figure 6-10. Regression sensitivity for core porosity.

Figure 6-11. Regression sensitivity for permeability.

Figure 6-12. Regression sensitivity for macroporosity.

Figure 6-13. Regression sensitivity for quartz cement.

 

Petrographic Previous HitanalysisNext Hit and Touchstone (porosity-depth) modeling show these fine- and medium-grained sandstones respond differently to burial diagenesis. Porosity and permeability of fine-grained (channel-margin) Previous HitlithofaciesNext Hit are consistently lower at a given burial depth relative to medium-grained (channel-axis) Previous HitlithofaciesNext Hit. Also, finer grained Previous HitlithofaciesNext Hit are more susceptible to intergranular cementation by syntaxial quartz during burial diagenesis.  

 

Summary and Conclusions 

 Seal character in slope-fan settings is related to variations of shale fabric and texture (e.g., content of detrital silt). At least three distinctive shale microfacies, each having different MICP (seal) profiles are present in the cored interval.

·        Top seal potential ranges from moderate to excellent (in the absence of fractures).

·        Lateral seal potential ranges from moderate to poor.

 

Variations in depositional fabric, which correlate with high-frequency (wire-line log-scale) stratigraphic fluctuations, are responsible for observed variations in seal capacity.  

Reservoir compartmentalization, induced by shale laminae and clay smears (micro-faults), is a common aspect of channel-margin Previous HitlithofaciesNext Hit within this deep-marine (slope-fan) depositional system. Hemipelagic shales and argillaceous debris flows also compartmentalize the studied LST reservoir interval.  

Reservoir character (especially permeability) is compromised by ductile folding and small-scale faulting. Slumping along with the deposition of mud drapes contribute to limited internal connectivity in channel-margin Previous HitlithofaciesNext Hit.  

Porosity-depth modeling suggests that the reservoir potential of fine-grained channel-margin Previous HitlithofaciesNext Hit degrades more rapidly during burial relative to coarser channel-axis Previous HitlithofaciesTop.

 

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.

Dawson, Wm. C., and Almon, W.R., 2002, Top seal potential of Tertiary deepwater Gulf of Mexico shales: GCAGS Transactions, v. 52, p. 167-176.

Fonnesu, F., 2003, 3D seismic images of a low-sinuosity slope channel and related depositional lobe (West Africa deep-offshore): Marine and Petroleum Geology, v. 20, p. 615-629.

Galloway, 1998, Siliciclastic slope and base-of-slope depositional system: Component facies, stratigraphic architecture, and classification: AAPG Bulletin, p. 569-595.

Jennings, J.J., 1987, Capillary pressure techniques: application to exploration and development geology: AAPG Bulletin, v. 71 (10), p. 1196-1209.

Kolla, V., Bourges, P., Urruty, J.M., and Safa, P., 2001. Evolution of deep-water Tertiary sinuous channels offshore Angola (west Africa) and implications for reservoir architecture: AAPG Bulletin, v. 85 (8), p. 1373-1405.

Prather, B.E., 2003, Controls on reservoir distribution, architecture and stratigraphic trapping in slope settings: Marine and Petroleum Geology, v. 20, p. 529-545.

Prather, B.E., Booth, J.R., Steffens, G.S., and Craig, P.A., 1998, Classification, lithologic calibration and stratigraphic succession of seismic facies from intraslope basins, deep water Gulf of Mexico, USA: AAPG Bulletin, v. 82 (5), p. 701-728.

Sinclair, H.D., and Tomasso, M., 2002, Depositional evolution of confined turbidite basins: Journal Sedimentary Research, v. 72 (4), p. 451-456.

Weimer, P., Slatt, R.M., Dromgoole, P., Bowman, M., and Leonard, A., 2000, Developing and managing turbidite reservoirs: case histories and experiences: results of the 1998 EAGE/AAPG Research Conference: AAPG Bulletin, v. 84, p. 453-465.

 

Acknowledgements 

We thank ChevronTexaco for granting permission to present these data and interpretations. W.T. Lawrence prepared thin sections and assisted with core photography. J.L. Jones provided SEM images, and D.K. McCarty completed XRD analyses. Poro-Technology, Houston, TX conducted MICP analyses. Graphic design by L.K. Lovell.  

 

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