PSSedimentology and Petrophysical Character of Cretaceous Marine Shale Sequences, Foreland Basins: Seismic Response of Seals Horizons*
Wm. C. Dawson1, W.R. Almon1, E. Rietsch1, F.G. Ethridge2, S.J. Sutton2, and B. Castelblanco-Torres3
Search and Discovery Article #40089 (2003)
*Adapted from poster presentation at AAPG Annual Convention, Salt Lake City, May, 2003.
1ChevronTexaco, Bellaire, TX ([email protected])
2Colorado State University, Fort Collins, CO
3ChevronTexaco, Bakersfield, CA
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Development 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 sedimentologic, petrophysical, and geochemical analyses of Lewis Shale (Lower Maastrichtian) samples from SE Wyoming reveal considerable variability in 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 within the progradational Lewis package. Sealing capacity, as measured by mercury injection capillary pressure analysis (MICP), 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 18,000 PSIA) and are markedly better seals relative to samples from the overlying Lewis Shale progradational package (average 3,000 PSIA). Transgressive shales with enhanced sealing capacity are characterized by higher total organic carbon and hydrogen index values, lower permeability, and less 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.
Figure Captions (1-2.1 - 1-2.3)
Figure 1-2.1. Location of study area: western part of Great Divide basin and Rawlins-Sierra Madre uplift.
Figure 1-2.2. Paleogeographic map for lower Maastrictian (approximately 69.4 Ma) (after McGookey et al., 1972).
Figure 1-2.3. Upper Cretaceous stratigraphy, south-central Wyoming (after Schell, 1973).
The ultimate goal of this research is to develop sequence stratigraphic-based models for predicting seal occurrence and estimating 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 the least understood element of petroleum systems.
The Lewis Shale (Upper Cretaceous, Maastrichtian), which crops out along the eastern margins of the Great Divide and Washakie basins in south-central Wyoming, provides an interesting analog for understanding stratigraphic architecture of turbidite depositional systems (Figures 1-2.1, 1-2.2, and 1-2.3). Previous outcrop and subsurface studies (e.g., Pyles and Slatt, 2000) established a high-frequency sequence stratigraphic framework for the Lewis Shale. Winton-Barnes et al. (2000) characterized sandstone lithotypes within the Lewis Shale, and Costeblanco-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 within the Lewis Shale.
The Lewis Shale is exposed intermittently along a 60-mile-long outcrop belt on the Rawlins-Sierra Madre uplift west of Cheyenne, Wyoming (1-2.1). Extensive subsurface data are provided by numerous producing fields west of the outcrop belt.
Stratigraphy (Figures 3.1-3.5)
Figure Captions (3.1-3.5)
Figure 3.1. Champlin 276 D-1, Section 13, T19N, R93W, Carbon County, Wyoming. Photograph of the core showing black, organic, fissile shale with laminated bentonite beds, together with section of well log containing cored interval (from that part of the Lewis Shale representative largely of aggradation).
Figure 3.2. Sierra Madre outcrop, Section 24/25, T16N, R92W, Carbon County, Wyoming. Photographs of outcrop area and log of stratigraphic interval examined (from that part of the Lewis Shale representative largely of progradation).
Figure 3.3. High-frequency sequence stratigraphic cross section of Lewis Shale, south-central Wyoming, with location and position of core in Figure 3.1 and of outcrop interval in Figure 3.2. (Modified after Pyles and Slatt, 2000).
Figure 3.4. Upper Cretaceous stratigraphic framework in terms of time, sequence stratigraphy, and polarity.
Figure 3.5. Relation between eustatic cycles, depositional geometry cycles, and systems tracts (modified after Rahmanian et al., 1990).
High-frequency sequence stratigraphic cross-section reveals that the Lewis Shale consists of at least twenty (probable 4th-order) depositional sequences (Figure 3.3). Beneath the “Asquith Marker” Lewis Shale deposition was basically aggradational (Figure 3.1). The overlying progradational unit consists dominantly of silty shales (3rd-order highstand [HST]) with interstratified 4th-order “lowstand” (LST) sandstones (Figure 3.2). These sandstones record below storm wave base deposition from storm-induced gravity flows. Relatively weak seals (HST shales) are interstratified with the sandstones (potential reservoirs).
Champlin 276 D-1, Section 13, T19N, R93W, Carbon County, Wyoming
Figure Captions (4.1-4.2)
Figure 4.1. Mercury injection capillary pressure curves, pore size distribution, photomicrographs, and SEM photographs for representative core samples, from the TST part of the Lewis Shale, in Champlin 276 D-1, together with section of well log that shows calibrated cored interval and positions of samples. Samples are from microfacies 1 (finely laminated, pyritic, black shales) and microfacies 4 (fossiliferous, slightly to moderately silty claystones).
Figure 4.2. (Left) Major constituents of Lewis Shale in cored interval in Champlin 276 D-1. (Right) Clay-mineral composition of Lewis Shale in cored interval in Champlin 276 D-1.
The Champlin 276 D-1 core (Figure 4.1) represents the transgressive (TST) part of the Lewis Shale. These samples have significantly higher MICP values (mean 18,000 psia) relative to other Lewis Shale samples (Figure 4.1). Shales exhibiting well-developed laminar fabrics and enrichment in iron-bearing clay minerals, TOC, and authigenic pyrite have excellent to exceptional seal.
Total clay content varies from 54 to 64 percent (Figure 4.2) with a mean of 51 percent (std dev = 2.5 %). Quartz content ranges from 23 to 34 percent. The mean is 28 percent (std dev = 3.9 %). Detrital feldspars, pyrite, and carbonate are common accessory (18 to 26 percent; mean 20) minerals. The dominant clay type is the 2:1 aluminum family (Figure 4.2). Abundance ranges from 17 to 32 percent with a mean of 25 (std dev = 5.1 %). The 2:1 iron-bearing clays are also major components. Their abundance ranges from 15 to 27 percent with a mean of 21 percent (std dev = 4.6 %). Kaolinite (mean 4 %) and iron-bearing chlorite (mean = 1%) are minor components.
Section 25/25, T16N, R92W, Carbon County, Wyoming
Figure Captions (5.1-5.3)
Figure 5.1. Mercury injection capillary pressure curves, pore size distribution, and photomicrographs for representative samples from the HST part of the Lewis Shale, Sierra Madre outcrop, together with log of stratigraphic interval and positions of samples. Samples are from microfacies 2 (moderately to very silty calcareous shales) and microfacies 5 (very silty shales and mottled argillaceous siltstones).
Figure 5.2. Photographs of outcrop area. A. General view. B. HST shale (15 cm scale). C. Sandstone-filled channel within HST shale. D. Sheet sandstone within HST shale.
Figure 5.3. (Left) Major consitituents of Lewis Shale in Sierra Madre outcrop. (Right) Clay-mineral composition of Lewis Shale in Sierra Madre outcrop.
The Sierra Madre outcrop represents the highly progradational (3rd-order highstand) part of the Lewis Shale; the dominant lithofacies are silty shales (microfacies 2) and argillaceous siltstones (microfacies 5) (Figure 5.1). Several high-frequency (4th- or 5th-order) lowstand sandstone units are interstratified with this highstand systems tract (HST). Two major types of sandstone bodies (lenticular and tabular) are recognizable in this outcrop (Witton-Barnes, 2000) (Figure 5.2).
Massive to weakly laminated shales and siltstones that compose the Lewis Shale HST are characterized by relatively high (mean 37 %) content of detrital silt, low TOC values, and the lowest sealing capacities (mean 1.150 psia) measured within the Lewis Shale (Figure 5.1). These relatively low sealing capacities are typical of shales from proximal parts of marine depositional systems (Dawson and Almon, 2002).
Total clay content ranges from 35 to 71% (mean 52%) (Figure 5.3). Detrital silt (quartz + feldspars) abundance varies from 24 to 59% (mean 37%). Pyrite, siderite, Mg-calcite, and dolomite are accessory (1 to 4%) components. The normalized clay mineral composition is dominated (56 to 78%) by 2:1 aluminum clays (mean 67%) (Figure 5.3).
Behind Outcrop Core
Colorado School of Mines Stratigraphic Test 61
Section 25, T16N, R92W, Carbon County, Wyoming
Figure Captions (6.1-6.2)
Figure 6.1. Mercury injection capillary pressure curves, pore size distribution, photographs, photomicrographs, and SEM photographs for representative core samples, from the LST part of the Lewis Shale, in Colorado School of Mines Strat Test 61, together with wireline log that shows positions of samples. Samples are from microfacies 2 (moderately to very silty calcareous shales), microfacies 3 (moderately to very silty, mottled, calcareous shales), microfacies 4 (fossiliferous, slightly to moderately silty claystones), and microfacies 5 (very silty shales and mottled argillaceous siltstones).
Figure 6.2. (Left) Major constituents of Lewis Shale in Colorado School of Mines Strat Test 61. (Right) Clay-mineral composition of Lewis Shale in Colorado School of Mines Strat Test 61.
Samples from the Colorado School of Mines Strat Test 61 represent the lowstand Lewis Shale. These samples consist of very silty shales and siltstones that have relatively low MICP values (mean 2886 paia). Lower MICP values are typical of silt-rich shales wherein detrital sized grains are concentrated into high-frequency laminae (Figure 6.1).
Total clay content varies from 35 to 69 percent (Figure 6.2) with a mean of 51 percent (std dev = 8.5 %). Quartz content ranges from 3 to 41 percent. The mean is 27 percent (std dev = 8.6 %). Detrital feldspars, pyrite and carbonate are common accessory (16 to 32 percent; mean 21) minerals. The dominant clay type is the 2:1 aluminum family. Abundance ranges from 0 to 46 percent with a mean of 31 (std dev = 5.1 %). The 2:1 iron-bearing clays are also major components (Figure 6.2). Their abundance ranges from 7 to 24 percent with a mean of 14 percent (std dev = 3.8 %). Kaolinite (mean 6 %) and iron-bearing chlorite (mean = 1%) are minor components.
Figure Captions (7.1-7.8)
Figure 7.1. Microfacies of the Lewis Shale and some of their characteristics.
Figure 7.2. Average mercury injection capillary pressure curve for each of the five microfacies of the Lewis Shale, with TST showing the best seal character.
Figure 7.3. Canonical discriminant analysis distinguishes the five Lewis Shale microfacies, which are illustrated by photomicrographs.
Figure 7.4. Iron 2:1 clay content of TST and HST shales plotted against MICP @ 10% saturation (psia), with the former showing higher values.
Figure 7.5. Plot of porosity of TST and HST shales, with the former showing lower values. (MFS=maximum flooding surface.)
Figure 7.6. Plot of 10%MICP saturation of Lewis Shale samples according to depositional systems, with TST shales, condensed shales, and paleosols showing the greatest seal capacity.
Figure 7.7. Plot of porosity and permeability shows a strong correlation between subsurface and surface samples.
Figure 7.8. Tmax values of TST and HST shales are effectively the same.
Five microfacies have been recognized in the Lewis Shale in the study area; they are tabulated in Figure 7.1 and listed below:
Distal marine (TST) shales (microfacies 1 and 4) exhibit the “best” seal character based on MICP analysis (Figure 7.2). Discriminant function analysis of Lewis Shale microfacies yielded two functions that account for nearly 99% of the total variance (Figure 7.3). TST shales are enriched in iron-bearing clay minerals and pyrite and have strongly elevated MICP values relative to HST shales (Figure 7.4).
Porosity of TST shales is significantly lower than porosity in HST shales (Figure 7.5). MICP values are increased as porosity is 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. There is a correlation between seal capacity and depositional systems, with an progressive increase in capacity from slumps/debris flows, HST, MFS, TST, condensed shales, to paleosols (Figure 7.6).
A strong correlation between subsurface and outcrop samples, along with evidence of comparable burial history (Tmax data), suggests that other factors (e.g., diagenetic processes) are responsible for differences in seal character (Figure 7.7). Tmax values are essentially the same for all Lewis Shale samples; this implies that they have undergone comparable burial histories (Figure 7.8).
Figure Captions (8.1-8.10)
Figure 8.1. Bulk density of TST shales greatly exceeds the bulk density of HST shales.
Figure 8.2. Poisson’s ratio in TST shales is generally less than Poisson’s ratio of HST shales.
Figure 8.3. Shear velocity of TST shales exceeds the maximum shear velocity of HST shales.
Figure 8.4. HST shales exhibit an overall increase in compressional velocity above the MFS. The average compressional velocity of TST shales is approximately equal to the maximum HST compressional velocity.
Figure 8.5. Data used for seismic model.
Figure 8.6. Synthetic seismogram for model 1.
Figure 8.7. Synthetic seismogram for model 2.
Figure 8.8. Synthetic seismogram for model 3.
Figure 8.9. Comparison of the seismic data from model 1 (red) and model 3 (green) shows the relatively minor effect of removing the orange and green layers.
Figure 8.10. Seismic profile, with features of high-reflectivity shale resembling those of sandstone saturated with hydrocarbons.
Measurements reveal significant differences in the bulk density, Poisson’s ratio, and shear velocity of TST and HST shales (Figures 8.1, 8.2, and 8.3). The differences in rock properties across a shale-shale contact (i.e., low velocity and low density HST shale immediately above a high velocity and high density TST shale—Figures 8.1, 8.3, and 8.4) could generate a strong seismic reflection.
Shale Reflection Modeling Experiment
The basic modeling performed in this experiment used measured elastic rock properties data and layer thicknesses from well logs (Figure 8.5). Angle-specific reflection coefficients were computed for all interfaces and for angles ranging from 0 to 60 degrees. 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 analog well data and stretched/squeezed to simulate the effect of NMO. The result is a synthetic seismic angle gather that shows the AVA effect of the gather (model 1--Figure 8.6).
To assess the effect of the thin high-impedance shale (orange layer), it was removed, and the calculations repeated without it. The result (model 2--Figure 8.7) shows that the overall effect on the synthetic seismic is minimal. After removing both the orange and green layers (model 3--Figure 8.8), the effect is more noticeable but remains small (Figure 8.9).
The example of a seismic profile in Figure 8.10 shows a shale horizon (strong seismic reflector) that could be misinterpreted as hydrocarbon-saturated sandstone. Results from a well confirm the absence of sandstone.
Figure Caption (9.1)
Figure 9.1. Wireline log of LST reservoir, immediately overlain by waste-zone shale composed microfacies 2 and microfacies 3, which in turn is overlain by the top-seal shale, composed of microfacies 4.
Lewis Shale strata consist of at least 5 argillaceous microfacies that exhibit distinctive sedimentological and petrophysical features along with significant variations in seal character.
Uppermost transgressive and condensed shales (Lewis Shale microfacies 1 and 4) 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 2 and 5) and lowstand (Lewis Shale microfacies 3 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) (Figure 9.1).
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 Fe- and 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 3rd-order sequence stratigraphic framework of the Lewis Shale.
Seismic modeling reveals a potential of some shales to exhibit an AVO response comparable to that exhibited by hydrocarbon-saturated sandstones.
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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.W. Ward aided with the collection of samples. W.T. Lawrence prepared thin sections, and J.L. Jones contributed SEM images. D.K. McCarty completed XRD analyses, and Poro-Technology (Houston, TX) provided MICP analyses. Graphic design by L.K. Lovell (ChevronTexaco).