Lyons Sandstone Research Articles

A Stress‐Driven Double‐Phase–Field Framework for Tensile Fracturing Processes in Transversely Isotropic Rocks

ABSTRACTWe present a double‐phase–field framework for tensile fracturing processes in transversely isotropic rocks. Two distinct phase‐field variables are introduced to represent smeared approximations of tensile fractures along the weak bedding planes and through the anisotropic rock matrix, respectively. Driving forces that control fracture propagation in the phase‐field framework are constructed as a stress‐based formula with a recently developed tensile failure criterion that distinguishes the two failure modes in transversely isotropic rocks. For numerical implementation, we adopt a staggered integration scheme and decouple the governing equations so that the displacement field and phase‐field variables can be updated in sequence for a given loading step. The finite element formulation of the proposed framework is introduced in detail in this paper and is implemented in an in‐house finite element code. The numerical implementation is then validated by reproducing the uniaxial tension test results of Lyons sandstone. After that, we conduct simulations on a pre‐notched square plate loaded in tension to demonstrate the features of the proposed framework. Finally, we conduct simulations of three‐point bending tests of Pengshui shale and show that the proposed model can reproduce the force–displacement curves and failure patterns of specimens with different bedding plane orientations observed in laboratory experiments.

The edge of a Permian erg: Eolian facies and provenance of the Lyons Sandstone in northern Colorado

ABSTRACT Facies of the Permian Lyons Sandstone are described and interpreted based on analyses of 23 cores from Larimer and Weld counties, Colorado. Here, the Lyons Sandstone consists of very fine- to medium-grained sandstone with minor silt and mudstone interbeds. The unit has five recurrent siliciclastic facies that can be grouped into two facies associations (FA). FA1 consists of (1) high-angle, cross-laminated sandstone (Facies 1; interpreted as eolian dune remnants); (2) low-angle, cross-laminated and horizontally laminated sandstone (Facies 2; interdune); and (3) chaotically bedded to folded sandstone (Facies 3; lower dune flanks). FA2, in contrast, is mainly (4) wavy- to irregularly laminated silty sandstone (Facies 4; wet to damp interdune); and (5) massive to wavy-laminated silt-rich mudstone (Facies 5; ponded water areas between dunes) with minor amounts of high-angle, cross-laminated sandstone (Facies 1) and low-angle, cross-laminated and horizontally laminated sandstone (Facies 2). FA1 is hypothesized to have been produced in an eolian system akin to those that might exist in the dune-dominated portion of an erg, whereas FA2 was deposited in the intermittently wet portion of this eolian system, perhaps along erg margins or in flat dune-adjacent settings that were impacted by the water table. Isopach data suggests that the study area is on the fringe of a larger Lyons system that spans > 100,000 km2, and was deposited close to the Ancestral Rockies—a paleogeography consistent with deposition in erg to erg-margin paleoenvironments. Detrital zircon populations from nearby Colorado Front Range outcrops and from 12 correlative eolian units are dominated by small, well-rounded Paleoproterozoic and Mesoproterozoic grain populations that are remarkably similar between units, signaling a well-mixed system that also received an influx of distally sourced sediment from the Appalachian orogen. Detrital zircon-based maximum depositional ages of the Lyons Sandstone and its equivalents are internally consistent with deposition of the unit during the latest Artinskian to Kungurian.

Impact of Surfactants on Hydrocarbon Mobility in Shales

SummaryUnconventional reservoirs such as Wolfcamp and Eagle Ford formations have played an important role in boosting the oil and gas production in the United States, but unfortunately, primary recovery from these reservoirs seldom exceeds 10%. Thus, operators are exploring enhanced oil recovery (EOR) techniques such as miscible gas injection (huff ‘n’ puff) and surfactants to increase the production from shales. This study evaluates several commercial surfactants and the commonly used solvent limonene for their ability to increase hydrocarbon recovery. The results show that the various surfactants at 2 gallons per ton (gal/t) or 0.8 wt% concentration recover up to 29, 33, and 34% hydrocarbons from Lyons sandstone, Wolfcamp, and Eagle Ford rock samples, respectively. This is significantly more than the base case (no surfactants), which recovers only 16, 19, and 14%, respectively. The increased recovery by surfactants can be partially explained by the reduction in interfacial tension (IFT) between crude oil and brine (up to 90%) caused by the surfactant solutions. Another important reason governing the hydrocarbon recovery is the ability of the surfactants to prevent asphaltene precipitation. This study focused on the interaction of the surfactants with the asphaltenes and found some surfactants can cause a linear decrease in asphaltene precipitation with increasing surfactant concentration. Finally, the contact angle measurements were used to study the change in wettability of the rock surface caused by surfactant solutions that can preferentially change the oil-wet and mixed-wet pores to more water-wet pores, thereby further aiding the hydrocarbon recovery. This study shows that an integrated approach including a broad spectrum of measurements such as aqueous stability, IFT, contact angle, phase behavior, spontaneous imbibition hydrocarbon recovery, and asphaltene precipitation is required to adequately characterize any surfactant and its ability to increase the hydrocarbon recovery.

Evaluation of an Ultrasonic Method for Damage Characterization of Brittle Rocks

An intact rock specimen, when subjected to uniaxial compression, experiences multiple stages of deformation. This begins with the nucleation of microcracks at low stresses (crack initiation—CI) and their subsequent transition into unstable crack propagation (crack damage—CD) close to the ultimate strength. In the present study, an active ultrasonic monitoring method was used during uniaxial compression testing of Lyons sandstone specimens to evaluate the potential of the technique for damage characterization. The sensitivity of ultrasonic monitoring in relation to the input excitation frequency was also analyzed using four ultrasonic transducers with different central frequencies. A LabVIEW-controlled active ultrasonic system was used to acquire active seismic waveforms, which were made to propagate perpendicular to the direction of uniaxial stress. With increasing deformation, the corresponding changes in amplitude, frequency, and velocity of the active seismic signals were analyzed to characterize the CI and CD stress thresholds. Using statistical analysis, it was concluded that the changes in the amplitude and frequency of the active signals could be potential indicators of CI and CD. The comparison of wave characteristics corresponding to different input excitations also indicated that appropriate selection of transducer frequency is crucial for a representative interpretation of damage processes.

Experimental Relationship Between Compressional Wave Attenuation and Surface Strains in Brittle Rock

AbstractLinear ultrasonic testing (LUT) has been extensively used as a tool for the evaluation of damage processes in various materials ranging from synthetic metals to natural geomaterials, such as rocks. A key limitation of LUT‐based damage studies to date is the lack of explicit evidence used in associating material damage with the changes in measured LUT attributes (e.g., ultrasonic wave amplitude and velocity). In this study, the evolution of the full‐field strains in brittle rock specimens (Lyons sandstone) subjected to failure are analyzed in real time and linked with the changes in the ultrasonic wave amplitude in localized areas illuminated by ultrasonic beams, termed as the ultrasonic image areas. The noncontact optical full‐field displacement measurement method of 2‐D digital image correlation is implemented in combination with the LUT procedure to continuously track changes in the ultrasonic wave amplitude with the evolution of strains across the surface of the uniaxially loaded intact rock specimens. The ultrasonic amplitude showed near‐linear correlation with the intensity of inelastic tensile strain recorded in the rock specimens. The results from the study corroborate that the ultrasonic changes are in fact influenced by the regions of tensile cracking, which is the primary inelastic deformation mechanism in brittle rocks.

Non-linear ultrasonic monitoring of damage progression in disparate rocks

This paper focusses on non-destructive characterization of stress-induced damage progression in three types of rocks by experimentally capturing the elasto-dynamic non-linear response of the rocks, with the hypothesis that non-linear approaches have increased sensitivity relative to linear ultrasonic testing approaches. For this task, a non-linear ultrasonic testing procedure known as the Scaling Subtraction Method (SSM) has been implemented on uniaxially loaded rock specimens. The SSM procedure is based on exciting the damaged medium with two acoustic signals at different amplitudes consecutively. The linearly rescaled acoustic response at low excitation is subtracted from the response at large amplitude excitation for quantification of the elastic non-linearity of the medium by a non-linear indicator θ. At first, aluminum, Lyons sandstone, granodiorite and Gosford sandstone specimens were characterized using SSM and their inherent non-linearity was quantified. After this, the rock specimens were loaded under uniaxial compressive step-loading and ultrasonic measurements were performed simultaneously at each loading step. The non-linear indicator θ was calculated as the specimens were progressively damaged, and the changes in the non-linear response were linked to the different physical processes accompanying damage progression in rocks. The study concluded that the non-linear SSM technique is capable of sensitively recording signatures of the different stages of damage evolution in rocks.

Observations of Tensile Fracturing of Anisotropic Rocks

Summary Hydraulic fracturing is crucial to hydrocarbon recovery from resource plays and is essential to exploitation of geothermal energy. This process creates new tensile fractures and reactivates existing natural fractures, forming a highly conductive stimulated-reservoir volume (SRV) around the borehole. Although this process has been extensively studied and modeled for isotropic rock, only a limited number of studies have been performed for anisotropic rocks, such as shales, gneisses, and foliated granites. The fracturing process of anisotropic rocks such as shales is examined in this study. We divide the rock anisotropy into two anisotropic groups: conventional and veined. Two members of the conventional first group are Lyons sandstone, a brittle, quartz-dominated, low-porosity and -permeability, anisotropic (11%) material; and pyrophyllite, a monomineralic-clay-rich, strongly anisotropic (19%) metamorphic rock similar chemically and mechanically to shale with extremely low porosity and permeability. The second group consists of a suite of natural shale samples (18% anisotropy) from the Wolfcamp formation containing mineralized veins. Fracture initiation and propagation are studied during Brazilian tests. Strain gauges and acoustic-emission (AE) sensors record the deformation leading to and during failure. Scanning-electron-microscope (SEM) imaging and surface profilometry are used to study the post-failure fracture system and failed surface topology. Post-fracture permeability is measured as a function of effective stress. The influence of anisotropy on fracturing is investigated by rotating the sample-fabric direction relative to the loading axis through increments of 15°. The rock microstructure, lamination, and brittleness control the activation of the layers. Lyons sandstone shows a wide brittle fracture with larger process zone with twice as much layer activation at lower stress levels than pyrophyllite. The fracturing process in veined shale is, however, a coupled function of rock fabric and mineral veins. The veins easily activate at 15° orientation with respect to the loading axis at stress levels of 30% of the unveined-failure load. The resulting unpropped fracture has enhanced permeability by orders of magnitude. We suggest that fracturing from a deviated well reduces the breakdown pressure significantly (compared with a vertical well) and activates a large number of veins with enhanced conductivity without the need for excessive proppant.

An experimental investigation into hydraulic fracture propagation under different applied stresses in tight sands using acoustic emissions

Abstract Hydraulic fracturing is crucial in unlocking tight gas and shale gas and oil resources. The success of any hydraulic fracture depends on the fracture dimensions and proppant placement. Microseismicity (MS) is now a common mapping hydraulic fracture technique. In this paper, we report on the acoustic emission (AE) monitoring during laboratory hydraulic fracture studies conducted on Lyons sandstone samples under different applied external stress. We compute AE hypocenter locations, analyze event frequency content and compute focal mechanisms (FMS). Shear failure reflected in the focal mechanism is more common than tensile failure. AE locations agree well with visual expression of fractures intersection on the sample surface. Fracture orientation and development is controlled by the direction and magnitude of applied stresses. Below a critical stress magnitude, the sample inhomogeneities control the hydraulic fracture development. At lower stresses, the hypocenters indicate a greater stimulated reservoir volume, suggesting stage spacing should consider the magnitudes of in-situ stresses. The sequential acoustic emission activity is found to be episodic and discretized implying fracture propagation is not a simple continuum. SEM fracture morphology studies document a complex and non-planar development of the hydraulic fractures, affirming shearing consistent with the FMS. Furthermore, SEM imaging suggests a surface area creation far more than simple planar models would imply.

A model of isotope fractionation in reacting geochemical systems

The authors present a numerical technique that predicts how the stable isotopes {sup 2}H, {sup 13}C, {sup 18}O, and {sup 34}S fractionate among solvent, aqueous species, minerals, and gases over the course of a geochemical reaction process. This model is based on mass balance techniques similar to those already presented in the literature but differs from previous techniques in that it allows minerals to be segregated form isotopic exchange instead of remaining in isotopic equilibrium. Such an approach allows us to simulate the fractionation of isotopes between rock and fluid resulting solely from mineral dissolution and precipitation. The technique was tested by modeling isotopic fractionation during several reaction processes, including (1) dolomitization of limestone by a migrating pore fluid, (2) diagenetic alteration of the Permian Lyons sandstone in the Denver basin, and (3) hydrothermal alteration of the Okanagan Batholith in southern British Columbia. The results of calculations in which minerals are segregated from isotopic exchange compare well to isotopic trends observed in nature but differ markedly from calculations that assume isotopic equilibrium. 54 refs., 4 figs., 3 tabs.

Influence of Permian Salt Dissolution on Distribution of Shallow Niobrara Gas Fields, Eastern Colorado: ABSTRACT

Subsurface analysis of Permian salt and related strata in the shallow Niobrara gas area on the eastern flank of the Denver basin reveals that the location of faulted anticlines which produce gas from porous chalk is related to the occurrence of six Nippewalla Group (Leonardian) salt zones. Salt distribution is controlled by the configuration of evaporate basins during the Leonardian, truncation at a sub-Jurassic unconformity (which has completely removed Guadalupian salts), and post-Jurassic subsurface dissolution. Significant dissolution took place in response to Laramide orogeny and subsequent eastward regional groundwater flow within the Lyons (Cedar Hills) Sandstone aquifer. Initially, dissolution occurred along a regional facies change from sandstone to salt. Solution collapse allowed for cross-formational flow and removal of younger salts. Shallow Niobrara gas fields are situated above salt outliers or along regionally updip salt edges. No significant Niobrara production exists in areas where salt is absent. Structural relief across fields is related to Leonardian thickness variations, rather than subsalt offset. Seismic data reveal abrupt Leonardian thinning at the regionally updip limit of Eckley field, which has produced over 33 BCFG. Thickness of residual salt may be important in controlling the amount of gas trapped within the Niobrara. Where thick saltsmore » are preserved, structural relief is greater, the gas-water transition zone is thicker, and gas saturation is higher at the crests of faulted anticlines.« less

Influence of Permian Salt Dissolution on Cretaceous Oil and Gas Entrapment and Reserve Potential, Denver Basin, Western Nebraska: ABSTRACT

Location and trap type of Cretaceous oil and gas fields in the D-J Fairway of Nebraska are related to the occurrence of 12 Permian salt zones. Salt distribution is controlled by the configuration of evaporate basins, truncation at a sub-Jurassic unconformity, and post-Jurassic subsurface dissolution. The Sidney Trough, which marks the eastern (regionally updip) limit of Cretaceous oil production in western Nebraska, is a rootless salt-dissolution collapse feature, whose location and origin is controlled by an abrupt linear facies change from thick, porous Lyons Sandstone to Leonardian salt. Eastward gravity-driven groundwater flow within the Lyons occurred in response to hydraulic gradient and recharge along the Front Range Uplift following Laramide orogeny. Dissolution of salt at the facies change caused collapse of overlying strata, producing fractures through which cross-formational flow occurred. Younger salts were dissolved, enhancing relief across the regional depression and subsidiary synclines. Timing of post-Jurassic dissolution influenced entrapment within D and J sandstone reservoirs. Where Early Cretaceous (pre-reservoir) dissolution occurred, structure at the D and J sandstone level is relatively simple, and stratigraphic traps predominate. Where Late Cretaceous - Tertiary (post-reservoir) dissolution occurred, structure is more complex, formation waters are more saline, oil and gas are localized on dissolution-inducedmore » anticlines, and per-well reserves are significantly higher.« less

Groundwater Flow, Late Cementation, and Petroleum Accumulation in the Permian Lyons Sandstone, Denver Basin

The gray diagenetic facies of the Permian Lyons Sandstone, which is associated with all known petroleum accumulations in the formation, formed late in the history of the Denver basin as an alteration product of the formation's red facies. The red facies that makes up most of the sandstone contains iron oxide coatings, quartz overgrowths and calcite cements. The gray facies, which occurs locally in the deep basin, is distinguished by pore-filling dolomite and anhydrite cements and by a lack of iron oxide and calcite. The dolomite and anhydrite cements overlie bitumen that was deposited by migrating oil, and hence formed after oil was first generated in the basin, late in the Cretaceous or early in the Tertiary. The isotopic composition of oxygen in the dolomite ranges to s ch light values that the cement must have formed deep in the basin in the presence of meteoric water. The gray facies likely formed in a regime of groundwater flow resulting from Laramide uplift of the Front Range during the Tertiary. In our model, saline groundwater flowed eastward through the Pennsylvanian Fountain Formation and then upwelled along the basin axis, where it discharged into the Lyons Sandstone. The saline water mixed with more dilute groundwater in the Lyons, driving a reaction that dissolved calcite and, by a common-ion effect, precipitated dolomite and anhydrite. The facies' gray color resulted from reduction of ferric oxide in the presence of migrating oil or the Fountain brine. Underlying source beds by this time had begun to generate petroleum, which migrated by buoyancy into the Lyons. The association of the gray facies with petroleum accumulations can be explai ed if the Fountain brines discharged across aquitards along the same fractures that transmitted oil. As petroleum accumulated in the Lyons, the newly formed cements prevented continued migration, as is observed in shallower strata, by sealing oil into the reservoirs from which it is produced today.

Synthesis of late Paleozoic and Mesozoic eolian deposits of the Western Interior of the United States

Late Paleozoic and Mesozoic eolian deposits include rock units that were deposited in ergs (eolian sand seas), erg margins and dune fields. They form an important part of Middle Pennsylvanian through Upper Jurassic sedimentary rocks across the Western Interior of the United States. These sedimentary rock units comprise approximately three dozen major eolian-bearing sequences and several smaller ones. Isopach and facies maps and accompanying cross sections indicate that most eolian units display varied geometry and complex facies relations to adjacent non-eolian rocks. Paleozoic erg deposits are widespread from Montana to Arizona and include Pennsylvanian formations (Weber, Tensleep, Casper and Quadrant Sandstones) chiefly in the Northern and Central Rocky Mountains with some deposits (Hermosa and Supai Groups) on the Colorado Plateau. Lower Permian (Wolfcampian) erg deposits (Weber, Tensleep, Casper, Minnelusa, Ingleside, Cedar Mesa, Elephant Canyon, Queantoweap and Esplanade Formations) are more widespread and thicken into the central Colorado Plateau. Middle Permian (Leonardian I) erg deposits (De Chelly and Schnebly Hill Formations) are distributed across the southern Colorado Plateau on the north edge of the Holbrook basin. Leonardian II erg deposits (Coconino and Glorieta Sandstones) are slightly more widespread on the southern Colorado Plateau. Leonardian III erg deposits formed adjacent to the Toroweap-Kaibab sea in Utah and Arizona (Coconino and White Rim Sandstones) and in north-central Colorado (Lyons Sandstone). Recognized Triassic eolian deposits include major erg deposits in the Jelm Formation of central Colorado-Wyoming and smaller eolian deposits in the Rock Point Member of the Wingate Sandstone and upper Dolores Formation, both of the Four Corners region. None of these have as yet received a modern or thorough study. Jurassic deposits of eolian origin extend from the Black Hills to the southern Cordilleran arc terrain. Lower Jurassic intervals include the Jurassic part of the Wingate Sandstone and the Navajo-Aztec-Nugget complex and coeval deposits in the arc terrain to the south and west of the Colorado Plateau. Major Middle Jurassic deposits include the Page Sandstone on the Colorado Plateau and the widespread Entrada Sandstone, Sundance Formation, and coeval deposits. Less extensive eolian deposits occur in the Carmel Formation, Temple Cap Sandstone, Romana Sandstone and Moab Tongue of the Entrada Sandstone, mostly on the central and western Colorado Plateau. Upper Jurassic eolian deposits include the Bluff Sandstone Member and Recapture Member of the Morrison Formation and Junction Creek Sandstone, all of the Four Corners region, and smaller eolian deposits in the Morrison Formation of central Wyoming and apparently coeval Unkpapa Sandstone of the Black Hills. Late Paleozoic and Mesozoic eolian deposits responded to changing climatic, tectonic and eustatic controls that are documented elsewhere in this volume. All of the eolian deposits are intricately interbedded with non-eolian deposits, including units of fluvial, lacustrine and shallow-marine origin, clearly dispelling the myth that eolian sandstones are simple sheet-like bodies. Rather, these units form some of the most complex bodies in the stratigraphic record.

Geochemical Correlation of Paleozoic Oils, Northern Denver Basin--Implications for Exploration: GEOLOGIC NOTES

Analyses of 22 oil samples produced from Pennsylvanian and Permian rocks across the northern Denver basin suggest that three genetically distinct oil types are present. One type, produced from the Permian Lyons Sandstone in fields located near the axis or west flank of the basin, has pristane-phytane ratios of less than 1 (average 0.8), ^dgr13C values for saturated hydrocarbons of -28.5 to 29.1 ppt, low amounts of n-alkanes relative to branched-cyclic alkanes, and absence of pentacyclic biomarker compounds. The second oil type, produced from rocks of Virgilian and Wolfcampian age in northeastern Colorado and southwestern Nebraska, has pristane-phytane ratios of about 1.5, predominantly n-alkanes in the saturated hydrocarbon fraction, abundant hopanoid biomarker compounds, and C15+ saturated hydrocarbon fractions depleted in carbon-13 compared to the Lyons oil type (^dgr13C values -28.8 to -30.4 ppt). Oil produced from the Pennsylvanian (Missourian) Lansing Group (F zone) and Cambrian rocks at Boveau Canyon and Sleepy Hollow fields (Nebraska), respectively, is geochemically similar to this second oil type. The third oil type, produced from rocks of Desmoinesian age along the eastern flank of the Denver basin, has a pristane-phytane ratio near 1, intermediate amounts of n-alkanes relative to isoprenoids compared to the other oil types, and the isotopically heaviest saturated hydrocarbons of the three oil types (^dgr13C values -27.7 to -27.8 ppt). This oil also contains pentacyclic biomarkers, but the pentacyclic do not readily distinguish the Desmoinesian oil type from the Virgilian-Wolfcampian oil type. These three oil types probably were generated from three different source rocks. The geographic distribution of the Virgilian-Wolfcampian and the Desmoinesian oil types suggest at least two broad areas for possible future exploration: (1) in Desmoinesian rocks, along a trend subparallel to the eastern limit of Desmoinesian rocks in the subsurface from the Nebraska Panhandle to the Las Animas arch, and (2) in Virgilian-Wolfcampian rocks, along a generally east-west trend.

Permian Tectonism in Rocky Mountain Foreland and Its Importance in Exploration for Minnelusa and Lyons Sandstones: ABSTRACT

Permian sandstones are important producers of oil in the Powder River and Denver basins of the Rocky Mountain foreland region. In the Powder River basin, Wolfcampian Minnelusa Sandstone produces oil from structural and stratigraphic traps on both sides of the basin axis, whereas in the Denver basin, the Leonardian Lyons Sandstone produces oil mainly from structural traps on the west flank of the basin. Two fields, North Fork-Cellars Ranch in the Powder River basin, and Black Hollow in the Denver basin, are examples of Permian growth of structural features. At North Fork-Cellars Ranch, a period of Permian structural growth and resultant differential sedimentation is documented by structure and isopach maps of the Minnelusa and overlying Goose Egg Formation. Structural growth began at the end of Minnelusa deposition and resulted in deposition of a much thicker Goose Egg section on the west flank of the field. At Black Hollow, mapping indicates structural growth was initiated before deposition of the Lyons Sandstone and continued throughout Leonardian time. In both fields growth abruptly ceased in the Late Permian. Both North Fork-Cellars Ranch and Black Hollow are located on structural highs, or arches, which trend east-west across the Powder River and Denver basins. These arches were present during the pre-Laramide migration of Paleozoic-sourced hydrocarbons into the basins and acted as pathways for migration. Exploration for Permian reservoirs in the two basins should be concentrated on the arches, as the early formed traps were present when migration began. End_of_Article - Last_Page 857------------

Three Oil Types in Paleozoic Rocks of Northern Denver Basin--Implications for Exploration: ABSTRACT

Analysis of 22 oil samples produced from Pennsylvanian and Permian rocks across the northern Denver basin revealed three genetically distinct oil types. One type is produced from the Permian Lyons Sandstone from fields located near the structural axis and along the west flank of the basin. This oil type is characterized by pristane-phytane ratios of less than 1.0 (average 0.8), ^dgr13C values of -28.5 to -29.1 ppt for saturated hydrocarbons, low relative amounts of n-alkanes, and absence of hopanoid biomarker compounds. The second oil type is produced from rocks of Virgilian and Wolfcampian ages in northeastern Colorado and southwestern Nebraska. This oil has a pristane-phytane ratio of about 1.5, n-alkanes dominant in the saturated hydrocarbon fraction, abunda t hopanoid biomarker compounds, and C15+ saturated hydrocarbon fractions depleted in carbon-13 compared to the Lyons oil type (^dgr13C values -28.8 to -30.4 ppt). Oil produced east of the Denver basin from rocks of the Lansing Group (F zone) and Ordovician rocks at Boveau Canyon and Sleepy Hollow fields, respectively, is geochemically similar to this second oil type. The third oil type is produced from rocks of Desmoinesian age. This oil has a pristane-phytane ratio near 1.0, contains intermediate amounts of n-alkanes relative to isoprenoids compared to the other oil types, and contains the isotopically heaviest saturated hydrocarbons of the three oil types (^dgr13C values -27.7 to -27.8 ppt). These three oil types have probably been generated from thre different source rocks. The geographic distribution of the Virgilian-Wolfcampian and the Desmoinesian oil types suggest at least two broad areas for possible future exploration: for the Desmoinesian type, along a trend subparallel to the eastern limit of Desmoinesian rocks in the subsurface from the Nebraska panhandle to east-central Colorado; and for the Virgilian-Wolfcampian type, along a generally east-west trend in northern Colorado, southwestern Nebraska, and northwestern Kansas. End_of_Article - Last_Page 845------------

Anisotropic Permeability, Eolian Lyons Sandstone: ABSTRACT

Directional permeabilities from nine attitude-oriented core samples of well-laminated eolian Lyons Sandstone from Larimer County, Colorado, were measured with a gas permeameter. Intrinsic permeabilities across the laminae, parallel to lamination and dip, and parallel to lamination End_Page 306------------------------------ and strike, were quantified and compared. Relative permeabilities of gas over the spectrum of oil saturation and porosities were also determined. Permeability across the laminae ranged from 0.5 to 4 md, whereas permeability parallel to lamination ranged from 3 to 97 md. Permeability parallel to lamination was not significantly different when strike and dip directions were compared. Quantitative analyses of textures and fabrics of individual laminae explain the observed diversity of permeabilities. Relative permeabilities were highest at a given oil saturation measured downdip and along the laminae and lowest when measured perpendicular to lamination. End_of_Article - Last_Page 307------------

The Pierce Field Structure

The Permian Lyons Sandstone is oil productive in a number of anticlinal structures in the Denver basin. The Pierce field has produced in excess of 10,200,000 barrels of oil and 488,000 Met gas from an asymmetric anticlinal closure. Approximately 100 ft of structural closure is present at Lyons level. The field has a gentle west flank and steeply dipping northeast and southeast flanks. The axis of the asymmetric anticline is concave to the west. The structure in the field is Laramide in age and is interpreted to result from force folding of sedimentary layers over a high side corner of a rotated basement fault block. An understanding of the type of basement structure involved may provide a key to further exploration in the Lyons Sandstone in the Denver basin.

Organic Geochemistry of Pennsylvanian-Permian Oils and Black Shales, Northern Denver Basin: ABSTRACT

We performed organic geochemical analyses of Paleozoic shales and oils from the northern Denver basin to determine oil-source bed relationships. We recognized two general oil types: oil produced from reservoirs of Virgilian and Wolfcampian age in northeastern Colorado and Nebraska, and oil produced form the Lower Permian Lyons Sandstone near the basin axis in Colorado. Low-gravity oil (20° API) produced from the Virgilian-age reservoir at the Amazon field (Nebraska) and a higher gravity oil (37° API) produced from a well near the Amazon field (Wexpro 1-23 Lyngholm) can be distinguished geochemically from the other Virgilian-Wolfcampian oils studied and may be genetically unrelated to them. For comparison, we analyzed oils from the Minnelusa Formation (Permian-Pe nsylvanian) in the Powder River basin. These oils are geochemically unlike any Paleozoic oils analyzed in this study in southeastern Wyoming and Colorado. We evaluated shale samples of Desmoinesian, Wolfcampian, and Leonardian age for source rock potential. Shales of Leonardian and Wolfcampian age in southwestern Nebraska contain as much as 6% organic carbon and 4,000-7,000 ppm extractable hydrocarbons. However, the Wolfcampian samples analyzed contain hydrocarbons that are enriched in carbon-13 by 3-5 per mil compared to nearby oil occurrences and are, therefore, improbable source rocks for current oil discoveries. Hydrocarbons extracted from one sample of Leonardian shale are isotopically similar to the Virgilian-Wolfcampian oils. Thermally mature shales of Desmoinesian age in northwestern Nebraska containing as much as 18% organic carbon and about 800-8,000 ppm hydrocarbons are considered excellent potential source rocks. End_of_Article - Last_Page 463------------

Undrilled Shallow Giant Trap in Denver Basin, Colorado: Mountain-Front Thrust: ABSTRACT

Along the southwestern margin of the Denver basin, Precambrian rocks have been upthrusted at least 15,000 ft (4,600 m) in the Front Range and 8,000 to 10,000 ft (2,400 to 3,000 m) or more in the Wet Mountains. Strongest deformation apparently was during latest Cretaceous, Paleocene, and possibly earliest Eocene. The sedimentary strata of the basin were folded upward and were overridden by the Precambrian to create the steep west flank of the basin. Below the Precambrian, the precise configuration of the strata and the faults is unknown because there are no available seismic or drilling data, but reasonable interpretations can be made by analogy with other similar areas. Important reservoirs in the basin are the Permian Lyons Sandstone, the Lower Cretaceous J and D sandstones, and the Upper Cretaceous Codell Sandstone, Niobrara Formation, and Pierre Shale. The Lyons Sandstone, largely eolian, is about 700 ft (210 m) thick on outcrop at Colorado Springs in front of the upthrust. The J sandstone is thicker in drill holes directly in front of the upthrust than almost anywhere else in the basin. Distributary complexes in the J form clastic wedges almost 200 ft (60 m) thick that extend eastward from the mountains. The wedges provide migration paths that can funnel hydrocarbons from the basin upward into traps in the wedges themselves below the Precambrian. Deposits of southwest-oriented barrier islands and lagoons in the 40-ft (12 m) thick Codell S ndstone trend under the upthrust of the Wet Mountains. Figure Directly overlying the J are the major hydrocarbon-source rocks in the basin (in ascending order: the Graneros Shale, Greenhorn Limestone, Carlile Shale, and Niobrara Formation). Black shale is interstratified with the Lyons Sandstone in at least one drill hole in front of the upthrust. All source rocks probably reached maturity in late Cretaceous time and still are generating today. Oil and gas fields are present in front of the Front Range and Wet Mountains, and oil seeps are present at each end of the Front Range mountain-front thrust system. Below the Precambrian, simple upfolding permits an oil column as much as 5,000 ft (1,500 m) high, or more, in the J, and as much as 4,000 ft (1,200 m) high, or more, in the Lyons, assuming a fault dip of 70° at depth; lower fault dips permit higher oil columns. Clayey fault gouge, breccia, and minute faulting, in a zone that is in many places hundreds of feet wide at the fault, should be a good hydrocarbon seal, like a cork in a tilted 5,000-ft (1,500 m) high bottle. If the strata to the west to form a large anticline below the Precambrian, a different kind of trap of very large dimensions would be present. Any kind of trap can extend a combined north-south distance of nearly 65 mi (105 km). Even if roll over is absent and the fault dips steeply, drilling depths to ost traps are likely to be only several thousand feet. End_of_Article - Last_Page 488------------