Denver Basin Research Articles

Petroleum Migration in Denver Basin Inferred from Thermal Maturity and Hydrologic Data: ABSTRACT

Cretaceous petroleum accumulations in the Denver basin of eastern Colorado and southwestern Nebraska occur in a productive fairway where potential source rocks are thermally immature for oil generation. Reconstructed potentiometric surfaces, vitrinite reflectance (R/sub 0/), and other thermal maturity data suggest that fluids within the basin have migrated hundreds of kilometers from western thermally mature areas (> 0.65% R/sub 0/) updip to eastern thermally immature areas (< 0.50% R/sub 0/). Oil fields such as Adena and Little Beaver with cumulative production of tens of millions of bbl of oil occur where R/sub 0/ is below the threshold 0.60% value, the commonly accepted value that indicates the beginning of thermogenic petroleum generation. Variations in cementation, evidenced in the Denver basin by present east-to-west reductions in porosity and permeability, may have affected secondary migration. Ground-water potentials for the Lower Cretaceous J sandstone, calculated from drill-stem test data, decrease from west to east across the basin with a gradient of about 3 m/km. Local potential minima in Morgan and Logan Counties, as well as an increase information water salinity from 1000 ppm to 12,000 ppm toward the basin center, suggest the concentration of formation fluids in those areas. About 65 Ma, when Cretaceous more » shales first became mature enough to expel hydrocarbons, the initial uplift of the Rocky Mountains created a fluid potential field similar to the present one but of greater magnitude. This ancestral potential caused the generated hydrocarbons to migrate eastward; oil pools then concentrated at paleopotential minima. The analysis of fluid potential gradients makes it possible to determine the dynamics of forces that redistribute fluids in a basin. « less

Oil and Gas Developments in Eastern and Northwestern Colorado in 1986

Drilling activity in eastern and northwestern Colorado was down sharply in 1986, with 1,114 wells drilled in the area. This figure represents a 42% decrease in drilling from 1985's 1,918 wells (but the 1985 figure includes development wells in all of Colorado). Slightly less than one-third of the total, or 333 wells, were exploration tests with a success rate of 21%, down from the 29% success rate in 1985. Activity in the Denver basin and Las Animas arch areas focused on development drilling of Cretaceous formations and continued exploration of Pennsylvanian sediments. This exploration concentrated on the deeper potential of existing fields and on field extensions. Development drilling in the northwestern part of the state also occurred in the Pennsylvanian Weber, along with exploration activity for deeper sediments.

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.

Organic Geochemistry and Petroleum Potential of Pennsylvanian Black Shales, Powder River and Denver Basins: ABSTRACT

Organic Geochemistry and Petroleum Potential of Pennsylvanian Black Shales, Powder River and Denver Basins: ABSTRACT

Geological Aspects of the Codell Sandstone, Weld and Larimer Counties, CO

Summary Since 1981, nearly 1,000 wells have been drilled in the Denver basin of northeastern Colorado with the Codell sandstone as their primary target. The majority of this exploration has been in the axial portion of the basin, in Townships 4 to 7 North, Ranges 64 to 68 West, in Weld and Larimer counties. Drilling depths of Codell wells range from 6,800 to 7,400 ft [2073 to 2256 m]. Recently discovered oil and gas production in the Codell sandstone encompasses several hundred square miles. Thickness and lithology of the formation are remarkably similar across this widespread area. Geologic limits of this reservoir are less distinct than in most sandstone exploration targets; therefore, geologic parameters must be considered over a large area.

Plasticity Effects in Hydraulic Fracturing

The importance of reservoir rock plasticity in fracturing operations has been investigated by laboratory experiments and field results. A Lagrangian formulation for crack propagation provided the basis for the laboratory experiments. A simple crack propagation experiment showed that plasticity effects can be observed and that the importance of plasticity depends on the relative magnitudes of surface energy and energy dissipated in plastic deformation of a reservoir rock. The latter can be evaluated by laboratory measurements of a plasticity coefficient, ..cap alpha.., which comes out of the Lagrangian analysis. To measure ..cap alpha.., the authors developed a triaxial system for applying tensile stress to rock cores under confining pressure at strain rates characteristic of fracturing operations. Strain gauges mounted on each core were used with a servo-controlled press to apply strain at a linear rate between 10/sup -4/ and 10/sup -6/ seconds /sup -1/ and to obtain stress/strain data to the point of tensile failure. To distinguish between plasticity and nonlinear elastic phenomena, the authors also obtained strain hysteresis data.

Delineating Producing Trends Within Plays by the Use of Computer-Generated Drill Intensity Maps, Denver Basin, Colorado, Nebraska, and Wyoming: ABSTRACT

Computer-generated exploration intensity maps were constructed for the Lower Cretaceous J and D sandstones of the Dakota Group in the Denver basin as part of the US Geological Survey's Federal Lands Assessment Program (FLAP). These maps illustrate producing and non-producing areas, distribution of hydrocarbon shows, and explored areas. They were compared with existing or generated maps of depositional environment, structure, thermal maturity, core porosity and permeability, and production data to delineate trends and to assess oil and gas resources for the Denver basin. Data from more than 36,000 drill holes in the Denver basin were entered into drill intensity programs, developed by the US Geological Survey, which tabulate show and production data for drill holes within 0.5 mi/sup 2/ grid cells. Primary production in the Denver basin is from stratigraphic traps of the J and D sandstones of the Dakota Group. Production and shows within the Dakota group are present in northeast-southwest-trending zones on the eastern flank of the basin in Colorado. Based on the incorporation of maps of depositional environment, porosity, and permeability, the trends may represent distributary-channel systems in this portion of the basin. Thermal maturation studies of J and D sandstone hydrocarbon source rocks indicate that muchmore » of the oil and gas present in the Dakota Group was generated deeper in the Denver basin. Hydrocarbon migration pathways from deep in the basin may also be indicated by these northeastern trends. Using drill intensity maps to illustrate zones of production is useful for delineating large-scale trends within plays and, therefore, for helping assess petroleum resources within the Denver basin. It may also be used to outline potential exploration targets by extending and analyzing the trends.« less

Application of Landsat Imagery to Oil Exploration in Niobrara Formation, Denver Basin, Wyoming

The Niobrara Formation produces oil from fractures in several places in the Denver basin. The Niobrara is an oil-prone, mature source rock that entered the oil-generating window during the Laramide orogeny. The Laramide orogeny began with maximum compressive stress oriented east-northeast during the Late Cretaceous to Paleocene, and ended with maximum stress oriented to the northeast in the Eocene. We believe the Eocene phase activated northeast-trending extension fractures that may have acted as pathways for migration and loci for storage of oil, locally generated in the Niobrara. Theoretically, the fracture pressures related to oil generation in the Niobrara would preferentially open and fill this northeast-trending fracture system. Using Landsat imagery to map fracture in the northern part of the Denver basin, we have identified areas prospective for Niobrara oil production within an exploration fairway that is based on subsurface isopach and resistivity mapping. Support for this concept is the location of wells, reported to produce oil from the Niobrara, along a zone of northeast-trending lineaments.

Use of Computer-Generated Maps of Oil and Gas Development and Exploration Intensity for Delineating Producing Trends, Denver Basin, Colorado, Nebraska, and Wyoming: ABSTRACT

Exploration intensity maps were used in conjunction with existing or generated maps of depositional environment, structure, thermal maturity, core porosity, and production data to delineate trends and assess oil and gas resources for the Denver basin as part of the US Geological Survey's Federal Lands Assessment Program. Maps illustrating oil and gas production, shows, and dry holes were constructed for the Denver basin using the Petroleum Information WHCS data base, with mapping and statistical software developed by the US Geological Survey. Data from more than 36,000 drill hoes in the Denver basin were entered into a program that divides the basin into 1/2 mi/sup 2/ grid cells and analyzes show and production data for drill holes within each grid cell.

Oil and Gas Developments in Eastern and Northwestern Colorado in 1985

Drilling activity in eastern and northwestern Colorado was at record levels in 1985, with 1,918 wells drilled in the area. This represents a 21% increase in drilling from 1984's 1,589 wells. One-third of the total, or 644 wells, were exploration tests with a success rate of 29%, up from the 24% success rate in 1984. Activity in eastern Colorado focused on Pennsylvanian rocks along the Las Animas arch and Cretaceous formations in the Denver basin, especially in the Greeley area. Limited activity was also seen in the deeper zones in the Denver basin, in Tertiary and Cretaceous sediments of the Raton basin, and in subvolcanic rocks in the San Luis basin area.

Microcomputer Data Analysis and Mapping Applied to Exploration in Cretaceous Sands of Denver Basin: ABSTRACT

Cretaceous fluvial and marine sandstones produce petroleum in the Denver basin. Standard petrophysical and engineering tests provide considerable quantities of many data types. Only a small portion of these data is used to produce surface and interval maps, cross sections, and models of conditions in vertically limited areas immediately adjacent to wells. A microcomputer and commercial software allow more types and quantities of data to be used. Statistical analysis, statistical mapping, evaluation of longer vertical intervals, determination of attributes, and statistical analysis and mapping of these attributes produce models that predict productive and nonproductive trends for the target sandstones. These procedures provide an exploration approach that is effective and more time efficient than conventional methods.

Thermal Maturity of Codell Sandstone-Carlile Shale Interval (Cretaceous) in Part of Denver Basin, Colorado: ABSTRACT

Based on several geochemical parameters, hydrocarbons in the Codell Sandstone appear to have been derived from the underlying Carlile Shale. Both units are past peak thermal maturity and are at the upper limit of petroleum generation and preservation. The Turonian Codell Sandstone produces oil, gas, and condensate from wells drilled in the northwestern Denver basin. The zone of greatest thermal maturity follows the basin's north-northwest axis. Vitrinite reflectance (R/sub 0/) analyses reveal abundant weathered and reworked particles; R/sub 0/ values are 0.65 to 1.50% for the freshest, least altered particles. Pyrolysis analyses suggest thermal maturities near the upper limit for oil and gas generation and preservation. T/sub max/ values of 400/sup 0/C and bifurcated S/sub 2/ peaks are common. Data plotted on a modified van Krevelen diagram suggest that the Codell contains mainly Type III organic material and the Carlile more Type II material. This Type II organic matter may be the source for the Codell oil and gas. Genetic potential calculations for the Carlile samples support such a possibility. TTI calculations based on Lopatin diagrams predict that the Codell and Carlile lie within the liquid window. These TTI calculations correspond to lower geochemical parameters than those observed, suggesting thatmore » both the Codell and Carlile have passed peak thermal maturation.« less

Heat flow and ground water flow in the Great Plains of the United States

Regional groundwater flow in deep aquifers adds advective components to the surface heat flow over extensive areas within the Great Plains province. The regional groundwater flow is driven by topographically controlled piezometric surfaces for confined aquifers that recharge either at high elevations on the western edge of the province or from subcrop contacts. The aquifers discharge at lower elevations to the east. The assymetrical geometry for the Denver and Kennedy Basins is such that the surface areas of aquifer recharge are small compared to the areas of discharge. Consequently, positive advective heat flow occurs over most of the province. The advective component of heat flow in the Denver Basin is on the order of 15 mW m −2 along a zone about 50 km wide that parallels the structure contours of the Dakota aquifer on the eastern margin of the Basin. The advective component of heat flow in the Kennedy Basin is on the order of 20 mW m −2 and occurs over an extensive area that coincides with the discharge areas of the Madison (Mississippian) and Dakota (Cretaceous) aquifers. Groundwater flow in Paleozoic and Mesozoic aquifers in the Williston Basin causes thermal anomalies that are seen in geothermal gradient data and in oil well temperature data. The pervasive nature of advective heat flow components in the Great Plains tends to mask the heat flow structure of the crust, and only heat flow data from holes drilled into the crystalline basement can be used for tectonic heat flow studies.

Tectonic and Sedimentation Model For Morrow Sandstone Deposition, Sorrento Field Area Denver Basin, Colorado

Pennsylvanian Morrow sandstones are oil and gas productive throughout a large area in southeast Colorado. The Sorrento field is a recent major Morrow discovery with recoverable reserves estimated at over 10 million barrels of oil from an area of 3200 acres (1295 ha) at depths of 5400 to 5600 ft (1646 to 1707 m). Minor production also occurs from the Mississippian Spergen Formation, the Mississippian Saint Louis Formation, and the Pennsylvanian Marmaton Group. On the basis of subsurface mapping, productive Morrow sandstones are interpreted to be fluvial valley-fill deposits, consisting mainly at channel sandstones. These deposits are encased in marine shale and range in thickness from O to 55 ft (O to 16.7 m); net pay ranges from 5 to 30 ft (1.5 to 9.1 m). Porosities average 19% and permeabilities range from 1 to 4000 md. Isopach maps of the Morrow and associated stratigraphic intervals indicate that paleostructure influenced Morrow depositional patterns. Morrow channel sandstones accumulated in paleostructural low areas created by movements on basement fault blocks. Structural nosing is present in the same location and trend as the Morrow channels, indicating structural inversion. Analyses of stratigraphic intervals above the Morrow indicate that the structural inversion occurred during the Early and Middle Pennsylvanian. The field is regarded as a combination structural-stratigraphic trap. Knowledge of paleostructural control on reservoir facies provides a new idea for exploration for Morrow reservoirs in southeast Colorado.

Mineralogical and Morphological Evidence for the Formation of Illite at the Expense of Illite/Smectite

AbstractThe conversion of smectite to illite by way of a mixed-layer illite/smectite (I/S) series was found to be the major depth-related reaction in clay-mineral assemblages from two cored sedimentary sequences in the Rocky Mountains. The I/S reaction occurred in both interbedded sandstone and shale of Upper Cretaceous and lower Tertiary age in the Green River basin, Wyoming, and in chalk and chalky shale of the Upper Cretaceous Niobrara Formation, Denver basin, Colorado. As the proportion of illite layers in I/S increased with depth in these rocks, the amount of I/S in the clay fraction decreased, and the amount of discrete illite increased. Scanning electron microscopy revealed that the morphologies of highly expansible, randomly interstratified I/S clay (samples from shallow cores) exhibited no distinctive intergrowth or overgrowth textures. In deeply buried rocks containing highly illitic, ordered I/S and abundant discrete illite, however, fibers or laths of illite were formed on earlier I/S substrates. Less commonly, I/S of low expandability shows morphological features of both smectite and illite whereby rigid laths of illite appear to have formed diagenetically from the wall surfaces of I/S honeycombs. This combined morphology suggests some dissolution and reprecipitation (or some reorganization) of materials from the I/S substrate as the substrate was transformed into a more illitic mixed-layer clay.These data suggest that some I/S clay was destroyed by the selective cannibalization of smectite layers in I/S to provide the components needed to make a more illitic I/S. Moreover, discrete illite and other minerals apparently were formed during the reaction. Also, coarser mineral phases, such as potassium feldspar and detrital micas, may not have been required to supply the chemical components in the reaction. The observations provide an explanation for late diagenetic I/S reactions that occurred in restricted or relatively closed geochemical systems, as in early cemented rocks having extremely low permeability and little or no potassium feldspar.

Geologic Aspects of Tight Gas Reservoirs in the Rocky Mountain Region

Summary The Rocky Mountain region contains major gas resources in tight (low-permeability) reservoirs of Cretaceous and Ternary age. These reservoirs usually have an in-situ permeability to gas of 0.1 md or less and can be classified into four general geologic and engineering categories:marginal marine blanket,lenticular,chalk, andmarine blanket shallow. Microscopic study of pore/permeability relationships indicates the existence of two varieties of tight reservoirs. One variety is tightly because of the fine grain size of the rock. The second variety is tight because the rock is relatively tightly cemented and the pores are poorly connected by small pore throats and capillaries. Other characteristics of tight gas reservoirs are:discrete gas/water contacts are absent in lenticular and marginal marine blanket reservoirs,most of the gas occurs in stratigraphic traps,well log analysis is difficult in tight reservoirs.many Rocky Mountain tight gas basins are either overpressured or underpressured, andformation damage may occur when wells are drilled and completed. Introduction Gas-bearing, tight (low-permeability) reservoirs are present in sandstone, siltstone, silty shale, and chalk in the Rocky Mountain region. Most of the gas occurs in rocks of Cretaceous and Tertiary ages. Organic-rich dark shales and coals are the source of the gas. A combined engineering and geologic effort is needed to identify, to map, and to recover gas from tight gas reservoirs. It is particularly important that geologists working on tight gas reservoir analyses be aware of problems being encountered in well log interpretation and reservoir stimulation. It is equally important for the engineer to understand the geologic differences between tight (unconventional) and conventional gas reservoirs. Tight gas reservoirs exhibit several unique characteristics compared with conventional reservoirs. One of the most significant differences is that conventional reservoirs have a reasonably consistent relationship between porosity and permeability, whereas tight reservoirs may or may not exhibit a consistent relationship between porosity and laboratory-measured permeability except that the in-situ permeability to gas is generally less than 0.1 md. The following discussion will describe some geologic characteristics of tight gas reservoirs in the Rocky Mountain region. Types of Tight Gas Reservoirs Fig. 1 shows basins and areas within and adjacent to the Rocky Mountains that contain tight gas reservoirs. Most of these localities also contain conventional reservoirs. Many sandstone stratigraphic intervals that are tight in the deep parts of basins have conventional reservoir characteristics at shallow burial depth. Tight gas reservoirs in the Rocky Mountains are predominantly Cretaceous and early Tertiary age. They can be grouped into four general reservoir types:marginal marine blanket,lenticular,chalk, andmarine blanket shallow. Marginal Marine Blanket Reservoirs Marginal marine blanket reservoirs are strata deposited on or near a shoreline that occur within a relatively predictable stratigraphic interval. These reservoirs commonly are overlain by marine shales and may be underlain by marine shale or continental deposits. They are called "blanket" for engineering reasons and normally would not be considered blanket sandstones by geologists. Tight blanket reservoirs are strata that have relatively better horizontal continuity than lenticular reservoirs. Blanket reservoirs usually respond to hydraulic fracturing in a somewhat predictable (blanket-like) manner. When the volume of fracture proppant is increased, there is a general increase in well productivity up to certain limits. Some examples of marginal marine blanket reservoirs are the Lower Cretaceous "J" sandstone in the Denver basin, the Upper Cretaceous Upper Almond formation and the Frontier formation in the Greater Green River basin, and the Upper Cretaceous Corcoran and Cozzette sandstones in the Piceance Creek basin. The locations of these basins are shown in Fig. 1. Lenticular Reservoirs Lenticular reservoirs are reservoirs that were deposited predominantly by rivers. These fluvial sandstones are very discontinuous and exhibit many internal permeability variations. The geometry and dimensions of these reservoirs are difficult to predict. The response of lenticular sandstones to hydraulic fracturing is very erratic, and generally the stimulation results are poorer than usually possible in marginal marine blanket sandstones. Some examples of lenticular reservoirs are fluvial sandstones in the Upper Cretaceous Mesaverde group and Tertiary in the San Juan, Uinta, Piceance Creek, and Greater Green River basins. JPT P. 1308^

Mineral, Chemical, and Textural Relationships in Rhythmic-bedded, Hydrocarbon-productive Chalk of the Niobrara Formation, Denver Basin, Colorado

Indigenous hydrocarbons are produced from organic-rich chalk beds of the Upper Cretaceous Niobrara Formation in the Denver basin, eastern Colorado. The types of hydrocarbons produced from these chalks are determined by the level of thermal maturity associated with present-day burial or paleoburial conditions. Detailed analyses of deeply-buried chalk from core of the Smoky Hill Chalk Member of the Niobrara Formation in the Champlin Petroleum #2 Boxelder Farms well combined with core data from other Niobrara wells have helped identify many depositional and diagenetic relationships. Porosity of the chalk is proportional to maximum burial depth and inversely proportional to the amount of non-carbonate material (acid-insoluble residue content) in the chalk. Total organic carbon content in the chalk is proportional to the amount of acid insoluble residue and relative abundance of pyrite in the acid-insoluble fraction. Quartz is inversely proportional to the amount of insoluble material, and the amount of clay tends to increase as insolubles increase, suggesting that detritus in these chalks is greatly influenced by reworked, altered, volcanic products rather than siliceous clastics. Mixed-layer illite/smectite clay of bentonite beds in the Niobrara Formation appears to be a good geothermometer, and its composition provides an indication of thermal maturity of the indigenous hydrocarbons. Scanning electron microscopy of the chalk fabric shows progressive cementation with increasing burial depth. Oxygen isotopes of the carbonate become progressively more negative with increasing burial. Oxygen Isotopes, therefore, record the effect of progressive cementation in these chalks and support the idea that pressure solution and reprecipitation of the carbonate is the primary process for porosity reduction in chalk reservoirs of the Niobrara Formation in the Denver basin and adjacent areas.

Seismic Evidence of Tectonic Influence on Development of Cretaceous Listric Normal Faults, Boulder-Wattenberg-Greeley Area, Denver Basin, Colorado

Reflection seismic studies in the Denver basin near Greeley, Colorado, illustrate an association between listric normal faults (which sole out in detachment or decollement zones) and basement-controlled faults. Recurrent movement on basement-controlled faults triggered development of listric normal faults in tectonically sensitive stratigraphic intervals of the Cretaceous. Stratigraphic intervals exhibiting listric normal faults include the Cretaceous Laramie-Fox Hills-Upper Pierre, Middle Pierre Hygiene zone, and the Niobrara-Carlile Greenhorn. Listric normal faults are prevalent on the flank of a fault-bounded basement-controlled paleostructural block termed the Wattenberg block by Weimer and Sonnenberg (1982). Listric normal faults influence Cretaceous reservoir systems in the Hambert field area on the north flank of the Wattenberg-Greeley Lineament Zone.

Regional Trends in Porosity and Permeability of J Sandstone in Denver Basin--Controls of Burial History: ABSTRACT

The Lower Cretaceous J sandstone is the principal reservoir for oil and gas in the Denver basin of Colorado, Wyoming, and Nebraska. Net pay of the J sandstone depends strongly on sandstone depositional environments, but other important aspects of reservoir quality reflect the burial history. Most notable of these are porosity, permeability, depth, and degree of thermal maturation (as indicated by vitrinite reflectance). An understanding of the regional interrelationships between these variables is important in predicting reservoir quality and in estimating undiscovered petroleum resources in the Denver basin. Statistical treatment of the core analysis and well-log data from 134 widespread boreholes across the basin, for which the U.S. Geological Survey has core, reveal the following. (1) Thermal maturity increases exponentially with depth, indicating increased temperature with burial. (2) Porosity decreases linearly with increasing Ro and depth. The presence of authigenic clays and carbonate cements are important to porosity reduction. In many examples across the basin, however, quartz pressure solution and precipitation processes are the main causes of porosity reduction, and these phenomena may be temperature-limited. (3) Permeability decreases exponentially with increasing depth. The permeability data exhibit more scatter than porosity, indicating a less direct relationship t depth and reflecting the effects of both porosity loss and increased surface area of the pore network. Authigenic clays, especially ordered illite-smectite, control the specific surface area of the pore network in the J sandstone. End_of_Article - Last_Page 851------------

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------------