مرکزی صفحہ AAPG Hedberg Series Sedimentology and petrophysical character of Cretaceous marine shale sequences in foreland basins -...
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15 Almon, W. R., Wm. C. Dawson, F. G. Ethridge, E. Rietsch, S. J. Sutton, and B. Castelblanco-Torres, 2005, Sedimentology and petrophysical character of Cretaceous marine shale sequences in foreland basins — Potential seismic response issues, in P. Boult and J. Kaldi, eds., Evaluating fault and cap rock seals: AAPG Hedberg Series, no. 2, p. 215 – 235. Sedimentology and Petrophysical Character of Cretaceous Marine Shale Sequences in Foreland Basins— Potential Seismic Response Issues W. R. Almon E. Rietsch Chevron Texaco Inc., Houston, Texas, U.S.A. Chevron Texaco Inc., Houston, Texas, U.S.A. Wm. C. Dawson S. J. Sutton Chevron Texaco Inc., Houston, Texas, U.S.A. Colorado State University, Fort Collins, Colorado, U.S.A. F. G. Ethridge B. Castelblanco-Torres Colorado State University, Fort Collins, Colorado, U.S.A. Chevron Texaco Inc., Bakersfield, California, U.S.A. ABSTRACT D evelopment of predictive models to estimate the distribution and petrophysical properties of potential mudstone-flow barriers can reduce risks inherent to exploration and exploitation programs. Such a predictive model, founded in sequence stratigraphy, requires calibration with outcrop and subsurface analogs. Detailed sedimentological, petrophysical, and geochemical analyses of Lewis Shale (lower Maastrichtian) samples from southeast Wyoming reveal considerable variability in petrophysically and seismically significant rock properties. Lower Lewis strata represent late-stage transgressive deposits that include a distinctive condensed interval. The overlying progradational Lewis interval consists mostly of interstratified very silty shales and argillaceous siltstones. High-frequency sheet and lenticular sandstone bodies occur in the progradational Lewis package. Sealing capacity, as measured by mercury injection-capillary pressure (MICP) analysis, varies with fabric, texture, and compositional factors that are related to sequence-stratigraphic position. Samples from the Lewis Shale transgressive interval have significantly; greater MICP values (average Copyright n2005 by The American Association of Petroleum Geologists. DOI:10.1306/1060766H231 215 216 Almon et al. 18,000 psia) and are markedly better seals relative to samples from the overlying Lewis Shale progradational package (average 3000 psia). Transgressive shales with enhanced sealing capacity are characterized by higher total organic carbon and hydrogen index values, lower permeability, and lower detrital silt content. These transgressive shales are enriched in iron-bearing clay minerals and authigenic pyrite. Greater shear wave velocities, larger shear moduli, and higher bulk density also characterize transgressive Lewis Shales. The most promising seal horizons are laterally extensive, silt-poor, pyritic shales occurring in the uppermost transgressive systems tract. Stacking patterns of slow and fast shale horizons can yield seismic responses comparable to those interpreted as hydrocarbon-bearing reservoirs. INTRODUCTION This chapter presents an initial effort to use sequence-stratigraphic-controlled variations in shale and mudstone petrophysical and seismic properties to generate predictive models of seal occurrence and to estimate top-seal capacity for application in hydrocarbon exploration and risk analysis. Few systematic studies of seal character and shale sedimentology are available. Consequently, seals remain one of the more poorly understood elements of petroleum systems. The Lewis Shale (Upper Cretaceous, Maastrichtian), which crops out along the eastern margins of the Great Divide and Washakie basins (Figure 1) in south-central Wyoming, provides an interesting analog for understanding stratigraphic architecture of turbidite depositional systems. Previous outcrop and subsurface studies (e.g., Pyles and Slatt, 2000b) established a high-frequency sequence- stratigraphic framework for the Lewis Shale. WittonBarnes et al. (2000) characterized sandstone lithotypes in the Lewis Shale, and Castelblanco-Torres (2003) completed a detailed study of shale lithotypes from Lewis Shale outcrops and cores. Almon et al. (2002) documented considerable variability in petrophysical properties of shales in the Lewis Shale. The paucity of information defining systematic variation in shale and mudstone properties reflects the general difficulty of determining the mineralogy and texture of fine-grained lithofacies, as well as the difficulty of accurately measuring the petrophysical properties in rocks having inherently low permeability. This study considers microscale sedimentological aspects of shales, including clay content; percentage of silt-sized grains; degree of bioturbation; organic content; preferred orientation of matrix and larger components; and authigenic components. All of these can be expected to FIGURE 1. The Lewis Shale is exposed intermittently along a 60-mi (96-km)-long outcrop belt on the Rawlins – Sierra Madre uplift west of Cheyenne, Wyoming. The database for Pyles’ study consists of outcrops, cores, and well logs. (modified from Pyles, 2000; base map modified after Love and Christiansen, 1985). Sedimentology and Petrophysics of Marine Shale Sequences in Foreland Basins influence pore-throat diameter and, consequently, seal character as measured by mercury injection-capillary pressure (MICP) analysis. Additionally, shale facies, shale petrophysical properties, and seal character appear to vary systematically in the context of a sequence stratigraphy. GEOLOGIC SETTING The lower Maastrichtian Lewis Shale and Fox Hills Sandstone (Figure 2) were deposited in the final transgression and regression of the Western Interior seaway (Weimer, 1960), which lasted approximately 2.3 m.y. in the study area (Pyles and Slatt, 2000a). The Dad Sandstone occurs in the Lewis Shale and comprises interbedded sandstones and shales (Hale, 1961). These sandstones occur in the middle of the Lewis Shale and are the basis for the informal division of the Lewis Shale into three members: the lower, Dad, and upper members (Gill et al., 1970). The upper member is dominantly dark-gray to olive-gray mudstone, whereas the lower member is comprised of black shale (Gill et al., 1970). On a regional scale, the Lewis Shale interfingers with the overlying Fox Hills Sandstone (Figure 2). Asquith (1970) constructed stratigraphic cross sections using well logs through the Great Divide and Washakie basins and concluded that the Lewis Shale and Fox Hills Sandstone were deposited as a series of southward-prograding clinoforms that represented a single, progradational event. The progradation was driven by the buildup of a large delta, which comprised welldeveloped marginal-marine, shelf slope, and basin environments. More recent workers (Winn et al., 1985, 1987; Perman, 1990) have reached similar conclusions. As seen in the Sierra Madre outcrops of southeastern Wyoming (Figure 3A), the lower Dad Member of the Lewis Shale consists of interbedded dark-gray shales and continuous (thin- to mediumbedded), fine-grained sandstones. These sheetlike sandstones have planar bases FIGURE 2. Stratigraphic cross section, demonstrating the interfingering nature of the Lewis Shale and Fox Hills Sandstone in the area of the Lost Soldier anticline, southcentral Wyoming (modified after Reynolds, 1976). marked by Glossifungities, which extend into the underlying shales. The middle Dad Member contains thick lenticular bodies of medium-grained sandstone (Figure 3B). These laterally discontinuous sandstones contain an abundance of imbricated, shale, rip-up clasts and have erosional bases (Figure 3C). The flat pebble conglomerate formed by the shale rip-up clasts indicated significant depositional shear in the sand body. Witton-Barnes et al. (2000) interpreted lenticular sandstones in the middle Dad Member of the Lewis Shale as channel-fill lithofacies. Sandstones occurring in the upper Dad interval are fine-grained, thin-bedded, and laterally extensive. They exhibit well-developed internal sedimentary structures, including parallel laminations and climbing ripples (Figure 3D). HIGH-FREQUENCY SEQUENCE-STRATIGRAPHIC INTERPRETATION Pyles (2000) generated a high-frequency sequencestratigraphic framework using gamma-ray and resistivity logs of wells near the Lewis Shale outcrop belt (Figure 4). The datum that forms the base of the framework is the top of an organic-rich black shale unit, which is informally known as the Asquith marker. This organic-rich shale represents an anoxic basinal depositional environment throughout this study area. The Asquith marker is interpreted as a condensed section, representing the maximum transgression of the Lewis seaway (McMillen and Winn, 1991). It is likely that this surface was essentially flat but not necessarily horizontal during deposition of the overlying formations. The Lewis Shale and Fox Hills Sandstone contain only a single, third-order 217 218 Almon et al. FIGURE 3. Outcrop photo of lower Dad Sandstone Member of Lewis Shale consisting of (A) thick tan-weathering shales and interstratified thin-bedded sheet sandstones. These sharp-based sandstones are fine-grained and exhibit parallel laminations. The sheet sandstones weather into distinctive rust-colored ledges. (B) The middle Dad Sandstone Member of Lewis Shale consists of thick, tan-weathering, silty shales containing interstratified, thick-bedded, lenticular, sandstone bodies. These sharp-based sandstones are medium grained and range from massive to parallel laminated. The sandstone bodies have irregular (scoured) basal contacts and contain an abundance of shale rip-up clasts. These laterally discontinuous sandstones are resistant to weathering and form distinctive benches. Approximate thickness of sandstone is 25 ft (7.6 m) (gross). Outcrop photo (C) showing base of lenticular sandstone unit in middle Dad Sandstone. Sandstone has irregular (erosional) basal contact with the underlying light-gray claystone. Note the abundance of shale rip-up clasts incorporated into lower part of the irregularly bedded sandstone. Faint laminations are evident in the medium-grained sandstone (15-cm [6-in.] scale). The flat pebble conglomerate formed by the shale rip-up clasts indicated significant depositional shear in the sand body. The thin-bedded (centimeter-scale) sandstones in upper Dad Member of the Lewis Shale (D) are sheetlike and have planar, nonscoured bases and rippled upper surfaces. Detailed examination reveals that parallel-laminated, fine-grained sandstones overlie fine-grained sandstones exhibiting climbing ripples (scale in centimeters and inches). transgressive and highstand systems tract. Pyles’ (2000) high-frequency, sequence-stratigraphic interpretation detected at least 20 high-frequency (probably fourth-order) depositional sequences in the exposed portion of the third-order sequence (Figure 4). Transgressive Systems Tracts High-frequency transgressive systems tracts below the Asquith marker are interpreted to record deposition during a period when relative sea level was rising. Thus, they record a deepening succession of depositional environments in which sediment supply is low and probably decreasing. Eight retrogradational to aggradational high-frequency sequences were observed in the Lewis Shale third-order transgressive systems tract (Pyles, 2000). These sequences stack landward, to the north and west (Figure 4). Wire-line log correlations show that the internal stacking pattern is parallel to the upper and lower bounding surfaces (Pyles, 2000). These relatively deep-water shales are excellent seals. Sedimentology and Petrophysics of Marine Shale Sequences in Foreland Basins FIGURE 4. The high-frequency sequence-stratigraphic framework for the Lewis Shale and Fox Hills Sandstone reveals that the Lewis Shale consists of at least 20 (probably fourth-order) depositional sequences. Below the Asquith marker, deposition was basically aggradational. The overlying progradational unit consists dominantly of silty shales (thirdorder highstand) with interstratified fourth-order lowstand sandstones. The section shows systems tracts and significant surfaces. The location of the section is shown in Figure 1 (modified from Pyles, 2000). HST = highstand systems tract; TST = transgressive systems tract. Highstand Systems Tracts Thirteen high-frequency [fourth-order(?)] cycles are interpreted to be present in the third-order highstand systems tract (Pyles, 2000), which overlies the maximum flooding surfaces and underlies the sequence boundary. They record several successions of strata deposited in shallowing-upward depositional environments. Welllog correlations show that the internal stacking pattern displays sigmoid, divergent, and convergent geometries (Figure 4). The stratal relationships with respect to the lower bounding surface show onlap in proximal shelf and marginal marine settings and downlap in outer shelf, slope, and basinal environments (Pyles, 2000). These aggradational and progradational sequences contain sandy fourth-order lowstands developed in the thirdorder highstand systems tract. The high-frequency cycles stack basinward, from north to south (Figure 4). The welldeveloped, sandy, fourth order lowstand systems tract deposits record below storm wave base deposition from storm-induced gravity flows. Bouma sequences are not evident in these lowstand sandstones. Relatively weak seals (highstand systems tract [HST] shales) are interstratified with the sandstones (potential reservoirs). Depositional sequences in the Lewis Shale appear to be very similar to those in the Neocomian of West Siberia (Pinous et al., 2001). In the West Siberia basin, the productive sandstone intervals are in a series of clinoforms that have prograded out over organic-rich black, fossiliferous shales (Bazhenov Formation), which are succeeded, in most locations, by dark-gray shales deposited in deep-marine conditions prior to turbidite sedimentation from the approaching clinoforms (Achimov Formation). The Achimov Formation con- sists of a series of interbedded turbiditic sandstones and hemipelagic shales. The productive sandstones occur in the central parts and toes of the clinoforms. The capping strata are comprised of shales and siltstones, with some minor sandstone, and appear to represent slope deposits. It appears that the turbiditic sandstones in the West Siberia basin, as in the Lewis Shale, were deposited in high-frequency lowstand systems tracts in a third-order highstand systems tract. METHODS Representative shales were collected from cores in two wells, the Champlin 276 Amoco D-1 and the Colorado School of Mines (CSM) No. 61 Stratigraphic Test (Figures 5, 6), which gave essentially complete coverage of the Lewis Shale depositional sequence. A petrographic-based microfacies approach was used to develop sedimentologic interpretations of the Lewis shales (Dawson, 2000; O’Brian and Slatt, 1990). The shales were analyzed using quantitative x-ray diffraction and scanning electron microscopy (SEM) techniques. Whole rock mineral identification was based on correspondence of experimental d values with the diagnostic hkl reflections from the International Center for Diffraction Data (1993) reference file and/or other published works. The quantitative analysis method is based on a modification (Srodon et al., 2000) of the matrix-flushing technique by Chung (1974). Minerals that were detected by the presence of a diagnostic reflection but have contents less than 1 wt.% were left as decimal amounts. These and other decimal values are not meant to imply greater precision than indicated from the 219 220 Almon et al. the Lewis Shale. Because any rock type can function as a hydrocarbon seal, provided that the minimum displacement pressure of the potential seal is greater than the buoyant pressure generated by the hydrocarbon column in the accumulation, it is important to understand which lithotypes provide the best potential seals. Lithology is recognized as an important control on sealing capacity of top seals (Ingram and Urai, 1999). A general trend from high capillary seal capacity in finegrained, clay-rich rocks to low seal capacity in coarse grained, clay-poor rocks is present. If systematic differences exist in fine-grained rock properties and textures in a depositional sequence, it should be possible to predict seal quality from sequence-stratigraphic analysis. High capillary pressure measurements are used to FIGURE 5. Wire-line logs showing the cored interval from the transgressive systems tract in the Champlin 276 Amoco D-1 well. Arrows show the depths of samples examined in this study. GR = gamma ray; SFLA = spherically focused log; CILD = deep induction log. errors presented in Srodon et al. (2000). Accuracy for major phases ranges from 0.1 to 0.9%, with a mean of 0.5%. Zero values, as used here to indicate that the phase, were below limits of detection. Thirty-one thin sections were studied petrographically and photographed using polarized light microscopy. Percentages of components in thin section were determined by counting (100 points per thin section). Seal capacity was determined by MICP analysis. Physical rock properties were determined by measuring sonic velocities, porosity, permeability, and density at net confining stress from 1000 to 7000 psi. SEAL CAPACITY ASSESSMENT The use of these Lewis Shale outcrops as analogs for subsurface turbidite systems (Pyles, 2000; Pyles and Slatt, 2000b) suggested that they should provide a unique opportunity to examine the potential seal characteristics of the shales related to the sandy turbidite deposits (Dad Sandstone Member) in the highstand systems tract of FIGURE 6. Gamma-ray and resistivity log tracks form the highstand systems tract in the CSM Stratigraphic Test No. 61 well in south-central Wyoming. Sample locations are noted to the left of the gamma-ray trace. Sedimentology and Petrophysics of Marine Shale Sequences in Foreland Basins evaluate seal capacity. The resulting capillary pressure curves provide quantitative estimates of pore-throatsize distribution, which should define the largest diameter of interconnected, continuous pore throats. These pore throats will determine the ultimate capillary seal capacity. Schowalter (1979) has shown that failure by capillary leakage typically occurs at an average nonwetting phase saturation of 10%. We have adopted the pressure required to achieve 10% nonwetting phase saturation in the seal pore system as the critical value for determining capillary seal capacity. Standard techniques for evaluating seals are discussed in Berg (1975), Schowalter (1979, 1981), and Jennings (1987). SHALE COMPOSITION Compositional analyses (XRD) indicate that the Lewis Shale samples belong to a single, moderately variable compositional family (Figure 7). Total clay content ranges from 35 to 71%, with a mean of 52%. Detrital silt (quartz + feldspar mineral) abundance ranges from 24 to 59%, with a mean of 37%. Pyrite (trace to 4%), siderite (trace to 2%), and magnesium calcite (1 – 4%) occur in all samples as accessory components. The abundance of calcite and dolomite are highly variable. Calcite abundance ranges from 0 to 10%, whereas dolomite abundance ranges between 1 and 8%. With the exception of local bentonite layers, the normalized clay mineral composition is dominated by illite, which accounts for 56 – 78% (mean 67%) of the clay size fraction. Smectite content ranges from 15 to 36%. Kaolinite (5 – 10%) and chlorite (0 – 6%) are minor components. Most illite and smectite are aluminum rich, although iron-rich 2:1 type clays are common in shales from the transgressive systems tract. FACIES ANALYSIS Mudstones and shales are essential elements of the petroleum system, serving as both source for and seal on hydrocarbons. Additionally, hydrocarbons must be able to move through the shales and mudstones on a geologic (migration) timescale. Unfortunately, the sedimentologic study of mudstones lags far behind that of sandstones and carbonates. Detailed examinations of sedimentary features are sparse, but Schieber’s (1999) work has revealed lateral facies variability in mudstones and has defined several distinct facies types, which are similar to those seen in the Lewis Shale. Five endmember Lewis Shale microfacies are recognizable: (1) massive organic mudstones; (2) organic laminated shales; (3) calcareous-laminated shales; (4) organic bioturbated shales; and (5) massive calcareous shales. These microfacies are described and illustrated below (Figures 8, 9). The average or range of compositional and petrophysical data for each microfacies is given in Tables 1 and 2. Seismically important parameters are listed in Table 3. The distribution of these argillaceous microfacies can be related to the sequence-stratigraphic position. That is, shales from transgressive, highstand, and condensed sequences have distinctive petrographic aspects, seal characteristics, and seismic characteristics. Late transgressive systems tract deposition (microfacies 1 and 2) in the Lewis Shale is similar to Schieber’s (1999) carbonaceous facies associations carbonaceous mudstones, which indicates slow overall deposition in disoxic to anoxic conditions and displays minor bioturbation. Deposits from the lower portions of the highstand systems tract (microfacies 3) are similar to those described in Schieber’s (1999) graded mudstone facies (facies association graded mudstones). They show features related to deposition from the waning flow of FIGURE 7. Compositional plots for Lewis Shale samples examined in this study. Data are symbol coded by systems tract. (A) Both transgressive systems tract and highstand systems tract samples have relatively constant bulk composition. (B) The clay mineral types do not change between the transgressive and highstand systems tracts. (C) The iron content of the clay mineral suite is greater in the transgressive than in the highstand systems tract. 221 222 Almon et al. FIGURE 8. Low-magnification, thin-section photomicrographs (plane-polarized light) of the fine-grained Lewis Shale microfacies reveal a wide range of depositional fabrics. (A) The massive organic mudstones of microfacies 1 display wispy laminations and dispersed pyrite. Note foraminifera tests. (B) The organic laminated shales (microfacies 2) are characterized by strong, bedding-parallel organization of clay and organic particles. Note the probable fish bone on one depositional lamination. (C) The calcareous laminated shale (microfacies 3) is marked by the alternation of silty and thin organic-rich laminae and the presence of foraminifera tests on the organic-rich laminations. (D) The organic bioturbated shales (microfacies 4) displays alternating sandy and silty laminae, some of which are disrupted by burrowing. Pelagic deposition is significantly suppressed. (E) In the massive calcareous shale (microfacies 5), lamination is much less pronounced than in microfacies 4. Bioturbation has nearly destroyed any original depositional fabric. Silt is well sorted. Sedimentology and Petrophysics of Marine Shale Sequences in Foreland Basins FIGURE 9. High-pressure MICP plots for the Lewis Shale microfacies reveal clear differences in seal character and pore system structure. (A) The pore system of the massive organic mudstones of microfacies 1 is controlled by well-sorted pore throats with a modal diameter of about 0.0065 Mm. (B) The organic laminated shales (microfacies 2) also possess a pore system controlled by well-sorted pore throats with a modal diameter of approximately 0.005 Mm. These facies have excellent seal capacity. The other microfacies have more complex pore systems. (C) The calcareous laminated shales (microfacies 3) have a pore system containing two populations of pore throats. The dominant population in the silt-rich laminations controls nearly 85% of the pore volume and has a modal diameter around 0.015 Mm. (D) In the organic bioturbated shales (microfacies 4), pore system bimodality is more pronounced, and pore throat diameters are slightly larger than in microfacies 3. (E) In the massive calcareous shale (microfacies 5), pore system is controlled by a bimodal, moderately sorted population of pore throats with moderate displacement pressures. The tail of small pore throats is more pronounced than in other microfacies. 223 224 Almon et al. TABLE 1. Average or range of compositional data for five microfacies in Upper Cretaceous Lewis Shale, south-central Wyoming. Microfacies Detrital Clay (wt.%) Total Organic Carbon (wt.%) Framboidal Pyrite (wt.%) Total Carbonate (wt.%) Dolomite (wt.%) Siderite (wt.%) 1 2 3 4 5 50 – 53 50 – 54 58 – 69 43 – 61 39 – 44 1.0 – 1.3 1.3 – 2.8 1.1 – 1.5 0.6 – 1.8 0.5 – 0.6 0.5 – 2.0 2.0 – 4.0 0.6 – 1.0 0.2 – 3.0 0.2 – 0.8 5.0 – 7.0 7.0 – 15 1.0 – 6.0 7.0 – 14 8.0 – 11 2.0 – 3.0 2.0 – 4.0 0.2 – 1.0 2.0 – 8.0 4.0 – 6.0 0.5 – 2.0 1.0 – 2.0 0.0 – 2.0 0.4 – 2.0 0.0 – 1.0 fine-grained turbidites in disoxic conditions. Turbidite influence increases upsection, so that late HST deposits are similar to the burrowed mudstone facies (facies association burrowed mudstones). Microfacies 1 (Massive Organic Shales) Microfacies 1 consists of dark-gray and black shales that are thin bedded in core. At the scale of a thin section, observations reveal that the detrital matrix in microfacies 1 has a wispy appearance (Figure 8A). Occasional wavy laminations are present. Local areas in which the long axis of elongate silt grains and thinshelled pelecypod fragments are aligned parallel with depositional laminae are present in the more massive appearing areas of the matrix. Detrital clay minerals are the dominant (51%) component. Silt-sized grains of detrital quartz and feldspar are conspicuous accessory components. Tests of planktonic foraminifera occur as floating grains in the laminated detrital clay matrix. The chambers of foraminifera tests are cemented with sparry calcite and pyrite. Elongate fragments of terrestrially derived, organic matter comprise an accessory component. Total organic carbon (TOC) content ranges from 1.0 to 1.3 wt.%. Framboidal pyrite (0.5 – 2.0%) is scattered throughout the compacted clay matrix as a volumetrically minor authigenic component. Total carbonate averages 6.0%, with dolomite being the dominant carbonate species. Siderite (0.5 – 2.0%) comprises a significant portion of the carbonate fraction. Microfacies 1 is interlaminated with and grades upward into microfacies 2. Scanning electron microscopy images reveal that microfacies 1 has a strongly compacted appearance. Porosity ranges between 3 and 6%, whereas permeability averages 0.003 md. Shale bulk density ranges from 2.52 to 2.55 g/cm3. This microfacies provides excellent seal potential. The injection pressure required to achieve 10% nonwetting phase saturation ranges from 15,735 to 18,495 psia (Table 2; Figure 9A). Several seismically significant physical parameters were measured on samples of microfacies 1. The compressional wave velocity of the samples ranges from 14,400 to 15,100 ft/s (4389 to 4571 m/s), whereas the shear velocity ranges from 8070 to 9300 ft/s (2459 to 2834 m/s). Poisson’s ratio ranges from 0.145 to 0.275; Young’s modulus ranges from 5.60 to 7.22; and the Shear modulus ranges from 2.20 to 3.03. Interpretation The abundant framboidal pyrite records bacterial activity near an oxic-anoxic interface (Wilkin and Barnes, 1997). These shales are petrographically comparable to the sparsely fossiliferous transgressive shales described by Abed and Sadaqah (1998). Cretaceous black marine shales are known to coincide with widespread marine transgressions (e.g., Demanison and Moore, 1980; Hallam, 1987; Schlanger et al., 1987). Contrary to the assertion of Heckel (1977), transgressive shales do not necessarily record a deep-marine paleoenvironment of deposition but can represent relatively shallow-marine portions of transgressive depositional sequences (Leckie et al., 1990; Wignall and Newton, 2001). Microfacies 1 TABLE 2. Average or range of petrophysical data for five microfacies in Upper Cretaceous Lewis Shale, south-central Wyoming. Microfacies Porosity (%) Permeability (md) Mercury Injection Capillary Pressure (psia) 1 2 3 4 5 3.0 – 6.0 2.0 – 5.0 12.8 – 20.0 13.9 – 18.2 16.6 – 17.4 0.0003 – 0.0009 0.0001 – 0.0005 0.001 – 0.098 0.005 – 0.032 0.007 – 0.019 15,735 – 18,495 16,685 – 21,350 2755 – 5355 1740 – 7655 1105 – 2390 Sedimentology and Petrophysics of Marine Shale Sequences in Foreland Basins TABLE 3. Range of seismically important data for five microfacies in Upper Cretaceous Lewis Shale, south-central Wyoming. Microfacies Bulk Density (g/cm3) Compressional Wave Velocity (ft /s) 1 2 3 4 5 2.52 – 2.55 2.47 – 2.58 2.15 – 2.26 2.18 – 2.31 2.18 – 2.25 14,400 – 15,100 13,700 – 15,200 11,000 – 13,400 13,600 – 15,400 13,700 – 13,900 represents a low-energy (below storm wave base), oxygendepleted paleoenvironment. The juxtaposition of rock textures suggests that the shales have experienced extensive bioturbation. The planktonic foraminifera represent an overlying oxygenated water column. Deposits in this microfacies were probably the result of hemipelagic deposition (Stow et al., 2001), which involved both vertical settling and slow lateral advection through the water column. Microfacies 2 (Organic Laminated Shales) Microfacies 2 deposits consist of dark-gray to black shales that display well-developed fissility (Figure 8B) and contain accessory phosphatic nodules, bones, and possible fish teeth. Thin-section examination reveals that microfacies 2 possesses a well-laminated fabric developed by the organization of organic debris, with their long axes parallel to bedding. Detrital clay minerals are the dominant (52%) component. The clay-rich laminae are slightly wavy because of compaction around detrital silt grains and bioclastic components. Thinshelled pelecypod fragments are aligned parallel with depositional laminae. Most shells have been flattened and broken during compaction. Chambers of foraminifera tests are cemented by calcite and pyrite. Microfacies 2 contains a greater percentage of foraminifera tests than microfacies 1. Framboidal pyrite, a conspicuous accessory component, comprises 2.0 – 4.0% of the sample mass. These are the highest pyrite abundances in the Lewis Shale. Microfacies 2 contains an average TOC content of 1.3 – 2.8%, the highest of any microfacies in the Lewis Shale. Total carbonate ranges from 7.0 to 15.0%, with calcite being the dominant carbonate species. Dolomite (2.0–4.0%) and siderite (1.0–2.0%) comprise a significant portion of the carbonate fraction. Scanning electron microscopy images reveal an abundance of authigenic carbonate, pyrite, and apatite crystals. These components occur as both cements and nodular replacive phases. Microfacies 2 is strongly compacted. Porosity ranges between 2 and 5%, whereas permeability Shear Velocity (ft/s) 8070 – 9300 7630 – 10,000 6370 – 7080 6480 – 8260 6810 – 7560 Poisson Ratio Young’s Modulus Shear Modulus 0.145 – 0.275 0.114 – 0.273 0.198 – 0.320 0.264 – 0.350 0.281 – 0.272 5.60 – 7.22 5.02 – 7.92 2.57 – 4.10 4.07 – 6.03 3.86 – 4.98 2.20 – 3.03 2.20 – 3.03 1.19 – 1.63 1.51 – 2.32 1.44 – 1.96 averages 0.001 md. Shale bulk density ranges from 2.47 to 2.58 g/cm3. This microfacies provides excellent seal potential. The injection pressure required to achieve 10% nonwetting phase saturation ranges from 16,685 to 21,435 psia (Table 2; Figure 9B). Among the seismically significant physical parameters, compressional velocity of the microfacies 2 ranges from 13,700 to 15,200 ft/s (4175 to 4632 m/s), whereas the shear velocity is between 7630 and 10,000 ft/s (2325 and 3047 m/s). Poisson’s ratio ranges from 0.114 to 0.273; Young’s modulus ranges between 5.02 and 7.92; and the shear modulus ranges from 2.20 to 3.03. Interpretation These phosphatic shales are comparable to condensed shales discussed by Loutit et al. (1988) and Schutter (1998). Condensed shales are characterized by high-abundance and low-diversity assemblages of planktonic fossils, as well as low abundance of benthic fossils. Moderate to high TOC content and elevated abundances of authigenic minerals are also characteristic. Concentrations of phosphatic bioclasts, elevated abundance of authigenic minerals, and high radioactivity are also common features. The abundance of authigenic pyrite, the lack of benthic fossils, and the scarcity of bioturbation attest to an oxygen-depleted depositional setting for microfacies 2. The abundance of authigenic pyrite, carbonate, and apatite is the end result of a complicated diagenetic history induced by sulfate reduction during early burial diagenesis (Lev et al., 1998). Sedimentologically, condensed shales record highly reduced rates of deposition, which is accompanied by phosphate authigenesis, in a marine setting having minimal current activity (below storm wave base). Microfacies 3 (Calcareous Laminated Shales) Microfacies 3 consists of dark-gray to black silty shales that exhibit well-developed fissility (Figure 8C). Thin-section examination reveals that microfacies 3 225 226 Almon et al. consists of very finely interlaminated organic-rich black shale and very silty shale. Many of the silt-rich laminae appear graded. Detrital clay minerals are the dominant (61%) component, whereas silt content ranges from 32 to 34%. Planktonic foraminifera tests occur along some of the most clay-rich laminations. These tests are cemented with sparry calcite. Framboidal pyrite, a minor accessory component, comprises 0.6 – 1.0% of the sample mass. Microfacies 3 contains a TOC content of 1.1 – 1.5%. Total carbonate ranges from 1.0 to 6.0%, with calcite being the dominant carbonate species. Dolomite (0.2 – 1.0%) and siderite (0.0 – 2.0%) comprise a significant portion of the carbonate fraction. Scanning electron microscopy images reveal an abundance of authigenic carbonate, pyrite, and apatite crystals. These components occur as both cements and nodular replacive phases. Microfacies 3 is not as strongly compacted as microfacies 1 and 2. Porosity ranges from 12.8 to 20%, whereas permeability ranges between 0.001 and 0.098 md. Shale bulk density is between 2.15 and 2.26 g/cm3. This microfacies provides relatively poor seal potential. The injection pressure required to achieve 10% nonwetting phase saturation ranges from 2755 to 5355 psia (Table 2; Figure 9C). Among the seismically significant physical parameters, compressional velocity of the microfacies 3 ranges from 11,000 to 13,400 ft/s (3352 to 4084 m/s), whereas the shear velocity is between 6370 and 7080 ft/s (1941 and 2157 m/s). Poisson’s ratio ranges from 0.198 to 0.320, Young’s modulus ranges between 2.57 and 4.10, and the shear modulus ranges from 1.19 to 1.63. Interpretation This microfacies reflects the increase in depositional rates produced by the beginning of progradation of the toes of a highstand sediment wedge. Deposition probably resulted from hemiturbidite sedimentation (Stow and Wetzel, 1990), which involved dispersion from dilute turbidity currents during the final stages of deposition or following interaction with positive topographic features. The fine-grained material carried by the turbidity current dispersed beyond the terminal deposit of the turbidite and mixed with any background pelagic or hemipelagic material and deposits formed slowly by vertical settling (Stow et al., 2001). Deposition was episodic. Planktonic foraminifera tests occur along some of the most clay-rich laminations. The lack of bioturbation suggests that microfacies 3 represents a low-energy (below storm wave base), oxygendepleted paleoenvironment. The planktonic foraminifera were derived from an overlying oxygenated water column. Microfacies 4 (Organic Bioturbated Shales) Microfacies 4 consists of dark-gray and black, silty, calcareous shales that are thin bedded in core and break out with a poker chip aspect (Figure 8D). Occasional siltstone and sandstone laminations are present. Slump structures occur in the shale sequence. At the scale of a thin section, the detrital matrix in microfacies 4 has a wispy to massive appearance. Occasional wavy laminations are present. The long axis of elongate silt grains and thin-shelled pelecypod fragments are aligned parallel with depositional laminae. The shales appear to have experienced extensive bioturbation. Detrital clay minerals are the dominant (51%) component. Silt-sized grains of detrital quartz and feldspar are conspicuous accessory components. Silt and sand content ranges from 27 to 41%. In some instances, the coarse detrital grains form a self-supporting framework, but generally, they appear to float in the clay-rich matrix. Framboidal pyrite is a significant accessory component and comprises 2 – 3% of the sample mass. These values are only slightly lower than those of microfacies 2. Elongate fragments of terrestrially derived, organic matter are an accessory component. Microfacies 4 contains a TOC content of 1.2 – 1.8%. Total carbonate ranges from 7.0 to 14.0%, with dolomite (2.0 – 8.0%) being the dominant carbonate species. Siderite (0.5 – 2.0%) comprises a significant portion of the carbonate fraction. Scanning electron microscopy images reveal an abundance of authigenic carbonate and pyrite crystals. Microfacies 4 is moderately compacted. Porosity ranges from 13.9 to 18.1%, whereas permeability ranges between 0.005 and 0.007 md. Shale bulk density ranges between 2.25 and 2.31 g/cm3. This microfacies provides relatively poor seal potential. The injection pressure required to achieve 10% nonwetting phase saturation ranges from 1975 to 3710 psia (Table 2; Figure 9D). These are the lowest values encountered in shales and mudstones of the Lewis Shale. The compressional velocity of the microfacies 4 (14,200 – 15,400 ft/s; 4328 – 4693 m/s) and the shear velocity (6480 and 8260 ft/s; 1975 and 2517 m/s) are significantly higher than in microfacies 3. Poisson’s ratio (0.264 – 0.350), Young’s modulus (4.07 – 6.03) and the shear modulus (1.51 – 2.32) are larger than in microfacies 3. Interpretation Microfacies 4 records deposition under variable conditions in terms of current energy and oxygenation levels. This microfacies contains less pyrite and organic matter relative to microfacies 1 and 2 and may record a shift to a somewhat more oxygenated paleoenvironment because the highstand depositional system was Sedimentology and Petrophysics of Marine Shale Sequences in Foreland Basins firmly established. The large volumes of mud, as well as the significant volumes of silt and sand-sized material, suggest that these sediments may represent deposition from turbidity currents (Stow et al., 2001). Individual flows were discrete events that recurred at irregular intervals. The pulsed nature of deposition generated the depositional laminations. Microfacies 5 (Massive Calcareous Shales) Microfacies 5 is comprised of gray laminated mudstones interbedded with thin, black, organic-rich mudstones (Figure 8E). The bedding is parallel and continuous except where interrupted by scour surfaces. Thin-section examination reveals that the individual laminations in microfacies 5 are disrupted and display a wispy to massive aspect. Very fine silt-sized particles of quartz and feldspar (51 – 59%) are the dominant component. Clay minerals (39 – 44%) are of secondary importance. The poor organization of the individual detrital laminae may be a result of burrowing. Total organic carbon content ranges from 0.5 to 0.6 wt. %. Framboidal pyrite (0.2 – 0.8%) is scattered throughout the compacted clay matrix as a volumetrically minor authigenic component. The TOC and pyrite contents are the lowest seen in the Lewis Shale. Total carbonate ranges from 8.0 to 11.0%, with dolomite (4.0 – 6.0%) being the dominant carbonate species. Siderite (0.0 – 1.0%) comprises a minor portion of the carbonate fraction. Scanning electron microscopy images reveal that microfacies 5 is moderately compacted. Small crystals of carbonate cements are scattered throughout the clay-rich matrix. The detrital silt grains do not form self-supporting frameworks. Porosity ranges between 16.6 and 17.4%, whereas permeability ranges from 0.007 to 0.019 md. Shale bulk density ranges from 2.18 to 2.25 g/cm3. This microfacies provides poor seal potential. The injection pressure required to achieve 10% nonwetting phase saturation ranges from 1105 to 2390 psia (Table 2; Figure 9D). Several seismically significant physical parameters were measured on samples of microfacies 5. The compressional wave velocity of the sample ranges from 13,700 to 13,900 ft/s (4175 to 4236 m/s), whereas the shear velocity is 6810 – 7560 ft/s (2075–2304 m/s). Poisson’s ratio ranges from 0.281 to 0.272; Young’s modulus ranges from 3.86 to 4.98; and the shear modulus ranges from 1.44 to 1.96. Interpretation The argillaceous siltstones of microfacies 5 mark the top of turbidite deposition (Dad Sandstone Member) in the Lewis Shale depositional sequence. This microfacies contains the smallest volumes of pyrite, siderite, and organic matter in the Lewis Shale. The scarcity of these components suggests that this microfacies was deposited in the most oxygenated setting extant during Lewis Shale deposition. The near equal volumes of mud and silt- and sand-sized material and the poor organization of the individual laminae suggest homogenization of interlaminated shales and siltstones by biologic activity. Microfacies 5 probably represents deposition by hemiturbidite sedimentation (Stow and Wetzel, 1990), which involves dispersion from dilute turbidity currents during the final stages of deposition or following interaction with positive topographic features. The fine-grained material carried by the turbidity current disperses beyond the terminal deposit of the turbidite and mixes with any background pelagic or hemipelagic material and deposits slowly by vertical settling (Stow et al., 2001). Deposition is episodic, but accumulation is commonly sufficiently slow that a restricted ichnofauna is present throughout the microfacies. Source Rock Character The average TOC for all analyzed Lewis Shale samples is 1.23 wt.%. However, the bulk of the preserved organic matter is contained in the late stages of the transgressive systems tract (Champlin 276 Amoco D-1 well ), where TOC values average 1.68 wt.%. The maximum measured TOC value in this unit is 2.78 wt.%. The TOC values (Figure 10A) in the transgressive systems tract (CSM Stratigraphic Test no. 61 well) range from 0.12 to 1.79 wt.%, with a mean of 1.07 wt.%. In this instance, the organic laminated shales of the condensed section (microfacies 2) are slightly more organic rich than the massive organic mudstones of the latest stage of the transgressive systems tract (microfacies 1). The calcareous laminated shales (microfacies 3), which form the base of the transgressive systems tract, have moderate and highly variable TOC values. The organic bioturbated shales (microfacies 4) and massive calcareous shales (microfacies 5) contain small amounts of organic carbon, and TOC variability is low. The organic matter in the Lewis Shale is uniformly type III (terrestrial organic matter). The organic matter in the transgressive systems tract is significantly more oxidized than that in the highstand systems tract (Figure 10B). Understanding the reason for this difference will require additional study. The temperature of maximum organic generation (Figure 10C) is essentially the same for all samples examined in this study. This fact suggests that the maximum depth of burial has been similar for both cores, although the Champlain 276 D-1 core is still buried to 8100 ft (2468 m) below ground level. 227 228 Almon et al. FIGURE 10. Some of the organic properties of the transgressive and highstand systems tracts are significantly different. (A) The transgressive systems tract is more organic rich than the highstand systems tract. (B) The organic matter in the transgressive systems tract is more oxidized than that in the transgressive systems tract. (C) Tmax values for the two intervals are nearly identical, indicating that they have seen very similar burial histories. TST = transgressive systems tract; HST = highstand systems tract. DISCUSSION On the basis of detailed petrographic and petrophysical data, the Lewis Shale can be divided into five microfacies (Figure 11) based on samples from outcrops and continuous cores in portions of the Great Divide and Washakie basins in south-central Wyoming. These facies, listed from best to worst top seals, include organic laminated shales, massive organic mudstones, silty shales, silty calcareous shales, and massive calcareous shale. Transgressive shales and basal transgres- sive shales are characterized by low species diversity and sparsity of benthic organisms and trace fossils. The relative organic richness and the scarcity of infaunal organisms are consistent with oxygen-depleted bottom conditions (Charvat and Grayson, 1981). Textures observed in the interstratified siltstones of the middle highstand systems tract record a shift to more oxygenated bottom conditions. The upper highstand is marked by increased current activity and the proliferation of bioturbation under significantly more oxygenated bottom conditions (Figure 12). The best two seals comprise deposits of condensed sections and upper portions of transgressive systems tracts (Figure 13A). Poorer seals comprise deposits from the lower portions of highstand systems tract deposits. These conclusions agree with conclusions reached by Dawson and Almon (2002) for deposits from Gulf Coast-style FIGURE 11. Numerous petrographic parameters and seismically important parameters vary systematically through the third-order transgression and highstand recorded by the Lewis Shale. TST = transgressive systems tract; HST = highstand systems tract. Sedimentology and Petrophysics of Marine Shale Sequences in Foreland Basins FIGURE 12. The Lewis Shale records deposition under anoxic bottom conditions during the late transgressive systems tract (microfacies 1 and 2) and early highstand (microfacies 3). Bottom conditions become more oxygenated in the middle highstand (microfacies 4), and full oxygenation in the upper highstand systems tract (microfacies 5) leads to an explosion of biologic activity and decrease in the preservation of organic carbon. basins and by Sutton et al. (2001) for Upper and Lower Cretaceous deposits of the Denver basin. Porosity is significantly reduced in the late-stage transgressive systems tract (Figure 13B), relative to all portions of the highstand systems tract. The reduced porosity in microfacies 1 and 2 appears to result from the better organization of the detrital clays resulting from suspension settling and associated microcrystalline carbonate cement formed during early submarine diagenesis. No obvious trend in porosity is present with microfacies in the highstand systems tract. This may result from the fact that deposition appears to be dominated by hemiturbiditic and turbiditic processes. Additionally, a strong contrast in shale permeability exists between the transgressive systems tract and the highstand systems tract (Figure 13B). Within the highstand systems tract, a minor tendency for permeability to increase upward is present in the stratigraphic section. This trend appears to be weakly related to increasing silt content, upward in the highstand systems tract. Crossplotting porosity with permeability (Figure 13B) shows that all samples fall along the same trend line, and that a moderate correlation coefficient exists (R2 = 0.88). Discriminant Function Analysis of the Lewis Shale Quantitative petrographic and TOC data from the Lewis Shale were used in a discriminant function analysis (DFA) to determine if the five identified microfacies could be discriminated. Data used in this analysis include seven variables: TOC, degree of bioturbation, percent of nonreflecting opaques (including organic FIGURE 13. Porosity and permeability are strongly controlled by sequence-stratigraphic position. Mercury injectioncapillary pressure values and porosity are significantly reduced in the late transgressive systems tract (TST) relative to all parts of the highstand systems tract (HST) interval. (A) Transgressive systems tract shales enriched in iron-bearing clay minerals and pyrite have strongly elevated MICP values. (B) Porosity and permeability in the TST shales is significantly lower than in the HST shales. A strong correlation exists between the two parameters. LST = lowstand systems tract. 229 230 Almon et al. TABLE 5. Percentage of variance accounted for by each discriminant functions in separating samples from microfacies 1–5, Lewis Shale. FIGURE 14. Graphic plot of multiple discriminant function analysis, Lewis Shale microfacies. Scores for discriminant functions one and two are plotted for each sample for all microfacies. Note the excellent separation among microfacies groups. Irregular circles enclosing each microfacies group are informally sketched. matter), average grain size of silt grains, percent silt grains, percent cement, and percent matrix. The TOC was determined on powdered samples as a weight percent of the total sample. The degree of bioturbation was estimated on a scale of 1 – 6 in thin sections. Average grain size was determined from the measurements of the apparent long axes of 30 grains in thin section. Percent opaques, silt grains, total cement, and matrix were estimated by point counting a minimum of 200 points per thin section. A total of 101 samples was analyzed from all five microfacies (Castelblanco-Torres, 2003). Because the variables are measured on different scales, each variable was transformed to standardized scores before being analyzed statistically. In DFA, lines of best separation (discriminant functions) are calculated among preestablished groups based on any number of variables. The coefficients of these discriminant functions illustrate the relative importance of the direct contribution of each variable in TABLE 4. Predicted microfacies group membership based on counts of all samples over five microfacies groups from the Lewis Shale. Predicted Group Membership Microfacies 1 2 3 4 5 Total 1 2 3 4 5 7 0 0 1 0 0 4 0 0 0 0 0 48 3 0 1 0 0 12 0 0 0 0 0 25 8 4 48 16 25 Function Eigenvalue % of Variance Cumulative Variance (%) 1 2 3 4 4.033 2.973 0.630 0.240 56.9 41.9 0.9 0.3 56.9 98.8 99.7 100.0 discriminating among groups. Three points are important concerning DFA. Discriminant functions are linear combinations of all variables. All groups are predetermined on the basis of other criteria, and it is assumed that all samples can be assigned to one of the established groups. Another aspect of DFA, the assignment of unknown samples to one of the established groups, is not considered in this study. Results of the DFA on the Lewis Shale are given in Figure 14 and Tables 4 – 7. Figure 14 shows a distinct separation among all five microfacies, with only five samples statistically assigned to a group other than the one in which it originated (Table 4). The first two discriminant functions account for almost 99% of the total variation in the data set (Table 5). Correlations among the variables and the discriminant functions are shown in Table 6. Variables with high correlations are most important in discriminating among microfacies. Thus, samples with relatively high bioturbation indices and TABLE 6. Structure matrix showing pooled withingroup correlations between discriminating variables and standardized canonical discriminant functions. Results are shown for all four discriminant functions. Variables are ordered by absolute size of correlation within functions. Only the first two functions are plotted in Figure 14 and considered in this study because they account for 99% of the variation (Table 5). Variables Function 1 Bioturbation index Opaques Weight % TOC Average silt grain size % silt % cement % matrix 2 3 4 0.924 0.286 0.112 0.130 0.180 0.108 0.089 0.881 0.444 0.063 0.098 0.816 0.213 0.252 0.004 0.663 0.164 0.018 0.138 0.131 0.277 0.011 0.202 0.241 0.060 0.367 0.303 0.272 Sedimentology and Petrophysics of Marine Shale Sequences in Foreland Basins TABLE 7. Means and standard deviations of raw data from all seven variables used in the DFA and MICP for each of the five microfacies of the Lewis Shale, Wyoming. The best seals are defined as those samples or microfacies with the highest MICP values. Microfacies MICP TOC Total Silt Total Matrix Opaques Total Cement Average Size (Phi) Bioturbation Index Mean MF 1 Standard deviation MF 1 Mean MF 2 Standard deviation MF 2 Mean MF 3 Standard deviation MF 3 Mean MF 4 Standard deviation MF 4 Mean MF 5 Standard deviation MF 5 12,464.42 7876.35 1.60 0.56 18.10 11.90 64.54 13.22 13.76 5.62 3.55 3.82 4.25 1.00 5.00 0.93 18,735.52 2148.83 1.58 0.35 7.85 6.28 71.35 9.89 16.53 5.68 4.38 4.37 4.76 0.10 0.00 0.00 1249.04 418.97 0.41 0.66 20.34 7.63 69.56 11.03 1.10 1.03 9.00 5.80 4.56 0.25 1.39 1.11 3123.23 994.25 1.09 0.50 14.31 9.47 69.39 12.33 12.98 7.81 3.36 1.97 4.68 0.79 2.5 0.73 1046.51 497.58 0.31 0.29 28.51 12.21 61.93 14.55 1.48 1.02 8.12 4.74 4.60 0.31 5.36 0.86 Bold numbers = highest mean value for all five facies; italic numbers = lowest mean value for all five facies; grain size data in Phi units; largest number = smallest grain size. high silt content plot to the left, and samples with high percentages of opaques and matrix plot to the right along discriminant function 1 (Figure 14). Organic laminated shales of microfacies 2 with the highest percentages of opaques, matrix, and TOC and the lowest percentage of silt grains, the lowest mean grain size, and a lack of bioturbation are the best seals (Table 7). Massive calcareous shales of microfacies 5 with the lowest percentages of TOC and matrix and the highest percentage of silt grains and the greatest degree of bioturbation are the poorest seals (Table 7). These two microfacies groups plot on opposite ends of the diagram in Figure 14. Calcareous laminated shales of microfacies 3 with the lowest percentage of opaques, the next to lowest TOC and matrix, and highest percentage of cement are also poor seals (Table 7). Organic bioturbated shales and massive organic mudstones of microfacies 1 and 4 are variable and are moderate to poor seals. Shale Reflection Modeling Experiment The presence of a low-velocity and low-density zone (microfacies 3) immediately above a high-velocity, highdensity zone (microfacies 2) produces a very strong positive acoustic impedance contrast in the vicinity of the maximum flooding surface (Figure 15). This contrast in acoustic properties, at a shale-on-shale contact, will generate a strong seismic reflection. The arrangement of slow rocks above fast rocks may also generate an amplitude-vs.-offset anomaly similar to those generated by hydrocarbon-filled sandstones. Seismic data has become the primary tool for exploration. It would be highly beneficial to possess a seismicbased tool for the predrill evaluation of seal capacity. This work has shown that several seismically important parameters display systematic differences and trends in the third-order transgressive and highstand systems tracts of the Lewis Shale (Figure 15). The ability to relate seismic interval velocity to important parameters such as porosity is important in the prediction of pore pressure from seismic data. In the Lewis Shale, the compressional velocity of the mudstone-rich portions of the highstand systems tract is moderately related to both total clay content and total carbonate content. It is poorly related to porosity. Within the transgressive systems tract, compressional velocity is unrelated to these compositional parameters but is still poorly related to porosity. Simple seismic modeling of the third-order transgression and highstand represented by the Lewis Shale confirmed the speculation that the facies stacking pattern should produce a strong seismic reflection and significant amplitude-vs.-offset response. The basic modeling performed in this experiment used elastic rock properties and layer thicknesses (Figure 16A) observed in the Lewis Shale cores and outcrops in the study area. Shuey’s (1985) approximation was used to compute angle-specific reflection coefficients for all interfaces and for angles ranging from 0 to 608. The result was an angle gather of reflection coefficients. Each trace of this gather represents a specific reflection angle and was convolved with an angle-specific wavelet. These wavelets were derived from one extracted from data in a major exploration area and stretched or squeezed to 231 232 Almon et al. FIGURE 15. Several seismically important parameters vary in systematic ways among the various shale microfacies. (A) Poisson’s ratio is generally less in the highstand systems tract (HST) shales than in the transgressive systems tract (TST) shales. (B) The TST shales are generally denser than the HST shales. In the HST, density shows a slight tendency to decrease upsection. (C) Highstand systems tract shales exhibit an overall increase in compressional velocity above the maximum flooding surface (MFS). The average compressional velocity of the TST shales is approximately equal to the maximum HST compressional velocity. (D) Highstand systems tract shales exhibit a slight general increase in shear velocity above the MFS. The average shear velocity of the TST shales significantly exceeds the maximum HST shear velocity. simulate the effect of normal moveout. The result is a synthetic seismic angle gather that shows the amplitudevs.-offset effect of the gather (Figure 16B). To assess the effect of the thin, high-impedance layer (representing the condensed interval, microfacies 2), it was removed, and the calculations were repeated without it. The result shows that the effect on the seismic response is minimal (Figure 16C). If the deepest two layers, those from the transgressive systems tract (microfacies 1) and condensed interval (microfacies 2), are removed, the effect is more noticeable but still small (Figure 16D). This suggests that the properties in the low-impedance layer, representing microfacies 3, are key to the amplitude-vs.-offset response. The model response is very similar to responses seen on seismic response in some exploration areas, such as the example in Figure 17, which shows a shale horizon (strong seismic reflector) that could be misinterpreted as a hydrocarbon-saturated sandstone. Results from a well confirm the absence of sandstone and hydrocarbons. CONCLUSIONS Lewis Shale strata consist of at least five argillaceous microfacies that exhibit distinctive sedimentological and petrophysical features along with significant variations in seal character. The uppermost transgressive and condensed shales (Lewis Shale microfacies 1 and 2) offer excellent to exceptional top seal potential. These shales occur preferentially in distal parts of marine depositional systems. The top seal capacity of highstand (Lewis Shale microfacies 3 and 5) and lowstand (Lewis Shale microfacies 4 and 5) intervals is reduced mainly because of elevated content (>25%) of detrital silt and disrupted fabrics (extensive bioturbation). Significant stratigraphic separation (several hundred feet) can exist between a lowstand sandstone reservoir and its controlling top seal horizon (i.e., overlying transgressive shale). Sedimentology and Petrophysics of Marine Shale Sequences in Foreland Basins FIGURE 16. Input data (A) and results from a simple seismic model of the shale stacking pattern found in the Lewis Shale. (B) This model is a synthetic seismic angle gather that shows the amplitude-vs.-angle (AVA) effect when all shale facies layers are present. (C) The overall effect of removing the thin, high-impedance layer representing microfacies 2 is minimal. (D) Removing the thicker, high-impedance layer representing microfacies 1 reduces the AVA effect, but the difference is still small. This suggests that the properties in the low-impedance layer, representing microfacies 3, are key to the AVA response. Factors that tend to enhance sealing characteristics of marine shales include low content (<25%) of detrital silt; relatively slow rates of accumulation; low oxygen levels and limited bioturbation (preservation of laminar fabrics); and increasing content of Feand Mg-enriched minerals. Seismically significant parameters (e.g., density, shear velocity, Poisson’s ratio, and compressional velocity) exhibit systematic variations that are consistent within the third-order sequence-stratigraphic framework of the Lewis Shale. Seismic modeling reveals a potential of some shales to exhibit an amplitude-vs.-offset response comparable to that exhibited by hydrocarbon-saturated sandstones. ACKNOWLEDGMENTS The authors thank ChevronTexaco for permission to present these data and interpretations. We are especially grateful to R. M. Slatt, D. R. Pyles, and S. M. Goolsby for sharing their knowledge concerning the Lewis Shale. C. Ward and A. Koenig made initial stratigraphic observations and collected outcrop samples. W. T. Lawrence prepared the thin sections. D. K. McCarty completed the XRD analyses, and B. J. Katz provided insight into the organic geochemical analyses. PoroTechnology (Houston, Texas) performed mercury injection capillary pressure analyses. The authors have benefited greatly from discussions concerning sequence stratigraphy with J. B. Sangree and L. M. Liro. REFERENCES CITED Abed, A. M., and R. Sadaqah, 1998, Role of Upper Cretaceous oyster bioherms in the deposition and accumulation of high-grade phosphorites in central Jordan: Journal Sedimentary Research, v. 68, p. 1009 – 1020. Almon, W. R., Wm. C. Dawson, S. J. Sutton, F. G. Ethridge, and B. 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