Abstract The Green River and Hoback Basins of northwest Wyoming contain very large, regionally pervasive, basin-centered gas accumulations (BCGAs). Published estimates of the amount of in-place gas resources in the Green River Basin range from 91 to 5036 trillion cubic feet (tcf). The Hoback Basin, like the Green River Basin, contains a BCGA in Cretaceous rocks. In this chapter, we make a distinction between regionally pervasive BCGAs and BCGA sweet spots. The Pinedale field, located in the northern part of the Green River Basin, is one of the largest gas fields in America and is a sweet spot in this very large BCGA. By analogy with the Pinedale field, we have also identified a similar BCGA sweet spot in the Hoback Basin. BCGA sweet spots probably always have characteristics in common with conventional accumulations but are different in that they are always contiguous with the underlying more regional BCGA. In this way, they are inseparable from the more regionally pervasive BCGA. We conclude that the probability of forming sweet spots is highly dependent on the presence of faults and/or fractures that have served as conduits for hydrocarbons originating in regional BCGAs. Finally, we propose that the Paleocene “unnamed unit” overlying the Lance Formation be renamed the Wagon Wheel Formation.

Abstract The Devonian gas shales of the Appalachian basin constitute a sequence of dark brownish–gray to black laminated rocks that contain 0.5 to 2 0 weight percent (wt%) organic matter, the source of the gas in the shale. The gas shales underlie about 170,000 mi 2 (440,300 km 2 ) of the basin, mainly under the Appalachian plateaus. Their total volume exceeds 12,600 mi 3 (52,517 km 3 ), and they contain more than 3.3 trillion tons (3.6 X 10 12 Mg) of organic matter. The gas shales are low–permeability, low–porosity rocks having permeabilities of 0.1 to 10 microdarcys (µd) and porosities in the 1 to 3 % range. They have produced slightly more than 3 trillion cubic feet (8.5 X 10 10 m 3 ), mainly from the Big Sandy area of eastern Kentucky and adjacent West Virginia, but their adsorbed gas in place is large; estimates range from less than 200, (5.66 X 10 12 m 3 ) to more than 1,860, (5.27 X 10‘ 3 m 3 ). Near outcrops on the west side of the basin, the gas shales yield gases of low thermal maturity that have a large component of biogenic gas; deep in the basin at depths of 8,000 to 11,000 ft (2.438 to 3.352 km) below sea level, the shales yield high–maturity dry gas at approximately the upper limit of gas generation. Because the gas shales have low permeability and most of the generated gas is adsorbed on organic matter, the Devonian gas shales must be broken by extensive natural fracture systems before the shales will yield gas in commercial volumes. Shallow gas wells near Lake Erie yield 5,000 to 100,000 cubic feet (5 to 100 mcf) (142 to 2,832 m 3 ) per day at nearly atmospheric pressure, whereas the deeper wells of the Big Sandy field may yield as much as 5 million cubic feet (mmcf) (1.416 X 10 5 m 3 ) per day at normal rock pressure. Production rates even in the larger wells usually drop to about 20% of the initial rate before stabilizing to a nearly flat rate. The ensuing slow decline over several decades is attributed to a nearly steady–state flow of gas from the shale matrix through the fracture system to the well bore. The size and geometry of the fracture system may be the most important factor in determining a well’s productivity.

Abstract Most Upper Devonian and Lower Silurian reservoirs in Pennsylvania have stratigraphic traps (pinch-outs, porosityture trends throughout western Pennsylvania probably influenced the migration of fluids and the diagenesis of sediments. Reservoirs comprise a variety of quartzose, lithic, and feld- spathic sandstones whose diagenetic histories included formation of authigenic clays, cementation, dolomitization, solution of cements and grains (resulting in secondary porosity development), and recementation. Permeabilities and porosities (most of which are secondary) tend to be low.

Abstract The Anadarko basin is one of the most prolific hydrocarbon provinces in North America. Examination of more than 50 cores from the Pennsylvanian Morrow sandstones reveals a complex diagenetic history. Although quartz is the major framework constituent of sandstones, shell fragments, glauconite, and clayey matrix occur in considerable amounts throughout the section. Diagenetic complexity is a function of depositional environment and burial and thermal history of the basin. Most porosity in the Morrow sandstones throughout the Anadarko basin is secondary in origin. Such porosity results from the dissolution of clayey matrix, carbonate fragments and cement, glauconite, and quartz grains and their overgrowth. Evolution of secondary porosity is related to the hydrogen (H + ) ions produced directly from the organic material maturation processes of Morrow shales. Carbon dioxide (C0 2 ) gas, with concentrations ranging from 0.3 to 4.7% by volume, was detected in more than 150 natural gas wells monitored in the basin. Based on geothermal and geopressure gradients and on experimental investigations of the solubility potential of CO 2 in formation fluids under elevated temperatures and pressures, a good estimate of solubility of CO 2 in the Morrow formation water may be attained. Because the concentration of CO 2 appears to increase with depth in the basin, secondary porosity should not be restricted to a particular zone or to particular depths but should persist with depth. Organic acids at shallow depths and H 2 S in deeper zones may be important in secondary porosity enhancement. Amounts of porosity and the geometry of pore space are directly related to the original lithology. A better understanding of lithofacies is critical in evaluating reservoir quality.

Abstract Major blanket-geometry, low-permeability gas sandstones in Texas include the Cotton Valley sandstone, the Travis Peak Formation, the Cleveland formation, and the Olmos Formation. The Cotton Valley (Upper Jurassic) and the Travis Peak (Lower Cretaceous) are widespread, sand-rich units within the East Texas basin that contain marginal marine deltaic, barrier-strandplain, and fan-delta facies. Gas production from the Cotton Valley is more extensively developed than from the Travis Peak, in part because today’s hydraulic fracturing technology was either developed or improved during completion of Cotton Valley tight gas reservoirs. The Pennsylvanian Cleveland sandstone of the Anadarko basin is in a mixed gas and oil to somewhat gas-prone province wherein the Cleveland produces gas from thin, distal deltaic facies or prodelta sediments reworked by shelf processes. Clay is abundant in the fine to very fine sandstone of the Cleveland. The Upper Cretaceous Olmos Formation contains gas within broadly lenticular delta-front deposits of the Maverick basin. The Olmos contains fine-grained to very-finegrained silty sandstones within massive shales. In 1980 tight gas sandstones accounted for 28% of gas wells completed in the 5,000- to 15,000-ft-depth range in Texas. Most of the completions in blanket-geometry hydropressured sandstones were within the formations reviewed herein.

Abstract Coal beds are known to exist in parts of most major sedimentary basins in the conterminous United States, from outcrop to depths in places exceeding 15,000 ft (4,572 m). The environments of deposition conducive to the formation of organic-rich swamps are the same as those favoring deposition of regressive sand bodies presently identified as underlying many coal beds. Many of these sand bodies are present in the San Juan and Piceance basins and are currently identified as tight gas reservoirs. Methane generated during the coalification process exceeds 5,000 ft 3 of gas per ton of coal (ft 3 /ton) (1 56.2 5 cm 3 /g) through the rank of low-volatile bituminous coal. Seldom have coal samples been collected, however, that contain more than 600 ft 3 /ton (18.75 cm 3 /g) of gas in place. The excess gas—generated gas minus in-place gas—must have escaped, possibly into adjacent tight gas reservoirs. The bulk of the coal in the San Juan basin, estimated to contain more than 31 tcf (0.9 X 10 12 m 3 ), of coalbed and gas, is found in the Upper Cretaceous Fruitland Formation. An unknown volumeof gas has been fed by the coals into the underlying Pictured Cliffs Sandstone and other nearby reservoirs. Coals in the Piceance basin of western Colorado are found in the Mesaverde Group immediately above the Rollins Sandstone or its equivalent. The coal-bed methane resource for the Piceance basin is estimated to be about 60 tcf (1.7 X 10 12 m 3 ). An assessment of the coal-bed methane resources in the Colorado-New Mexico area indicates the presence of 7 4 tcf (2.1 X 10 12 m 3 ) in the San Juan, Piceance, and Raton basins, all within 125 mi (2 01 km) of the center of a high thermal gradient area. Only a small portion of the large volumes of gas generated during coalification is found within the coal beds themselves.Additional gas has migrated into adjacent reservoir rocks or escaped to the atmosphere. Because of depositional environment continuity, tight gas sand reservoirs are a ready recipient for the large volumes of excess coal-bed gas.

Abstract The Raton basin of southern Colorado is geologically analogous to other Rocky Mountain Laramide basins that contain areally and volumetrically large accumulations of natural gas reservoired in tight Cretaceous and Tertiary sandstones and located in the deeper parts of the basins. Such basin-centered gas accumulations are recognized as a class distinct from conventional structural or stratigraphic traps. Based on geologic analogy, specific detailed geologic mapping, observed gas shows, and bore-hole log analysis, a basin-centered gas accumulation is postulated to exist in the deeper part of the Raton basin in the Trinidad Sandstone.

Abstract Chalk beds of the Upper Cretaceous (Coniacian-Campanian) Niobrara Formation were deposited in a shallow epicontinental seaway in the Western Interior of the United States during a major global sea-level rise. Biogenic gas is produced from the thermally immature, organic-rich chalk beds of the Niobrara in the eastern part of the Denver basin in eastern Colorado, northwestern Kansas, and southwestern Nebraska. These chalks have high porosity and low permeability. Accumulations of shallow gas are not controlled by major structural closures but by local, faulted, low-relief domal structures, or noses. Fracture stimulation, primarily with the use of foam treatments, is necessary to make gas production from these wells economically feasible. Westward and at greater depth in the basin, however, oil is produced from much tighter, naturally fractured chalk beds that are thermally mature and capable of thermogenic oil generation. The reservoir properties (mainly porosity and permeability) and types of hydrocarbons produced in the chalk of the Niobrara Formation from a given location within the basin are primarily controlled by diagenetic processes. Maximum burial depth (with associated differential pressure and temperature history) is the main controlling factor in reservoir quality. Thus, reservoir characteristics and source-rock potential of the Niobrara can be predicted from an understanding of the post-Niobrara depositional and thermal history of the region coupled with research that has identified systematic diagenetic changes.

Abstract The most important mineral resource activity in Colorado during the past decade has been the discovery and development of the Wattenberg and adjacent petroleum fields. Located north of Denver across the axis of the Denver basin, the Wattenberg is estimated to have reserves of 1.3 trillion cubic feet (tcf) in the tight J (Muddy) Sandstone (delta front) reservoir over an area of 600,000 acres at depths of 7,600 to 8,400 ft (2,310 to 2,560 m). Net pay thickness varies from 10 to 50 ft (3 to 15 m), porosity ranges from 8 to 12%, and permeability varies from 0.05 to 0.005 millidarcys (md) (Matuszczak, 1973, 1976). Drilling for J gas has resulted in multiple pays in overlying strata. The Spindle field, situated in the southwest portion of the Wattenberg field, produces from two marine-bar complexes (Hygiene and Terry) in the middle portion of the Pierre Shale. In 1981 and 1982, the Cod ell Sandstone, approximately 500 ft (152 m) stratigraphically above the J, was developed as a new producing horizon of oil and gas. More than 100 discoveries have been made within and marginal to the outlined Wattenberg field area. The Codell is a tight bioturbated marine-shelf sandstone generally without a central-bar fades. Net pay thickness ranges from 3 to 2 5 ft (0.9 to 7.6 m). Porosities determined from logs range from 8 to 24%, but the average core porosity is from 10 to 12 % and permeabilities are less than 0.5 md. Because of rapid decline in production and economic uncertainties, potential reserves from the Codell are unknown. All petroleum accumulations in the Wattenberg area are regarded as stratigraphic traps, although unconformities and paleostructure have played a subtle but detectable role. Variation in thickness and reservoir quality is related to original environmental facies and paleostructure that locallyinfluenced unconformities, fracturing, and diagenesis.

Abstract The reconstructed structural and thermal history of the Piceance Creek basin of western Colorado defines the geologic and geochemical conditions for the occurrence of gas in the Upper Cretaceous Mesaverde Group. In general the Mesaverde consists of two parts: a lower marginal marine section with mostly blanket reservoirs and an upper nonmarine part with mostly lenticular reservoirs. Most of the gas produced has been from reservoirs in the marginal marine section; however, because of its great thickness and abundance of gas shows, the nonmarine section is thought to contain more gas in place. Reservoirs in the nonmarine rocks usually have low permeability and are unconventional. Attempts to explain coal ranks using recent coal metamorphism models were unsuccessful, primarily because of the margin of uncertainty in present–day formation temperature readings in the basin. Coals around the basin margins were uplifted to their present high stratigraphic position in the basin during the final stages of the Laramide orogeny during the late Eocene and appear to be frozen at roughly pre–uplift coal ranks. The relatively high rank of some of these coals suggests that coal ranks throughout the basin attained close to their present–day rank from burial heating prior to the end of the Eocene. The effects of later thermal events on coal rank, such as Oligocene–age plutonism in the southern part of the basin, appear to have been minimal. If this is correct, then peak hydrocarbon generation in the basin peaked during the Eocene. Closed anticlines, which have produced much of the gas in the basin, appear to be Laramide growth structures; hence, peak gas generation occurred while the anticlines were growing.

Abstract The Corcoran, Cozzette, and Rollins sandstones of Late Cretaceous Campanian age were deposited in a shoreline and shelf environment. Subsequent diagenesis caused quartz overgrowths and calcite cementation and abundant amounts of pore–filling authigenic clays. Today the original conventional, intergranular porosity has been reduced to primarily microporosity with extremely low permeability; hence, the Corcoran, Cozzette, and Rollins are classified as tight gas sands. Structural trapping of gas accounts for most of the discovered reserves to date. However, the future production from the Corcoran, Cozzette, and Rollins sandstones in the southern Piceance basin will be found in tight gas–bearing sandstones present in the nearshore and offshore strandline facies. Data support the presence of a basin–centered gas trap with a dynamic updip flow of gas out of the basin. Pressure equilibrium of water upstructure toward the outcrop, very small capillaries, and continuous gas generation and migration provide the setting for dynamic capillary–pressure trapping (diagenetic trapping). Development of this type of trapping model requires the existence of a thermally mature basin with sufficient gas source beds adjacent to blanket reservoir beds. Primary gas flow occurs along the path of least resistance (the shoreline trend), but this migration route is also controlled by diagenetic degradation of the reservoir. In the gas leg of the accumulation, the blanket sandstone is perceived to be a system of gas–filled pores with interconnecting, water–filled capillaries. The most significant implication of this trapping model is that major amounts of additional gas resources are found in the basin. These undeveloped resources would lie downdip of the Plateau and Shire Gulch fields, toward the center of the basin, and along the trends of better sand reservoirs.

Abstract Gas production in the lower Tertiary Wasatch Formation and Upper Cretaceous Mesaverde Group in the Piceance basin, Colorado, is controlled principally by a network of open and partly mineralized natural fractures. The Piceance Creek field, situated on the Piceance Creek anticline, and the Rulison and Divide Creek fields all have extensive fractures. These fractures formed in response to high pore-fluid pressures that developed during hydrocarbon generation and to widespread tectonic stress associated with periods of uplift and erosion that occurred during the late Tertiary. Sandstone beds commonly contain vertical extension fractures that are cemented with fine- to coarse-crystalline calcite and locally with quartz, barite, and dickite. These fracture-fill minerals cut detrital grains, and authigenic mineral cements indicating that fracture development and mineralization occurred during the later stages of diagenesis. The δ I3 C compositions for calcite vary over a wide range (from — 5.0 to — 11.6‰ for the Wasatch and from — 0.7 to — 10.4‰ for the Mesaverde) and may reflect the original isotopic composition of matrix carbonate that was present in nearby sandstone beds. δ I8 O values for fracture-fill calcite generally are light, ranging from — 9.5 to — 14.9‰ for the Wasatch and from — 13.3 to — 17.7‰ for the Mesaverde. Most gas encountered in Tertiary and Cretaceous rocks was generated in situ from interbedded carbonaceous and coaly shales and tongues of organic-rich lacustrine rock. In areas that are extensively fractured, gas may comprise a mixture from different sources due to migration along open faults and fractures.

Abstract Tertiary and Cretaceous nonmarine sandstones are reservoirs for large amounts of natural gas at Natural Buttes field in the eastern part of the Uinta basin, Utah. A cored interval in the Upper Cretaceous Tuscher Formation dominantly comprises fine- to medium-grained, moderately to well-sorted sandstones and less abundant carbonaceous and coaly shale beds. These rocks represent sedimentation on the lower part of an alluvial braidplain. The Paleocene and Eocene Wasatch Formation unconformably overlies Cretaceous rocks and intertongues with marginal lacustrine strata of the Green River Formation. The cored interval in the upper part of the Wasatch consists of fine-grained lenticular sandstones with small-scale cross-bedding, argillaceous siltstones, and variegated mudstones, all of which were deposited in lower delta plain settings along the margin of Lake Uinta. Cored sandstones in the Tuscher and Wasatch formations have been extensively modified by minor quartz overgrowths; by the precipitation and subsequent dissolution of a carbonate mineral assemblage comprising iron-free calcite, ferroan calcite, dolomite, and ankerite; by local occurrences of anhydrite and barite; and by the formation of authigenic illite, mixed- layer illite-smectite, kaolinite, chlorite, and corrensite. Most authigenic carbonate formed during early burial before significant compaction. During later stages of diagenesis, anhydrite and barite precipitated locally, replacing detrital grains and mineral cements such as carbonate. Porosity and permeability have been significantly reduced in the sandstones owing to clay mineral development and the formation of carbonate cement. Large amounts of natural gas are stratigraphically trapped in these lenticular, diagenetically modified low-permeability sandstones. Potential source rocks in the Tuscher Formation may have generated thermogenic gas even though they are only moderately mature with respect to liquid hydrocarbon generation.

Abstract Large gas resources occur in low-permeability Upper Cretaceous and lower Tertiary reservoirs in the Greater Green River basin of Wyoming, Colorado, and Utah. Most of the gas- bearing reservoirs are overpressured, beginning at depths of 8,000 to 11,500 ft (2,440 to 3,500 m). The reservoirs are typically lenticular nonmarine and marginal marine sandstones. In situ permeabilities to gas are generally less than 0.1 millidarcy (md) and porosity ranges from 3 to 12%. Secondary porosity, after dissolution of framework grains and cements, is the dominant type of porosity. Gas accumulations are characterized by the presence of updip water-bearing reservoirs and downdip gas-bearing reservoirs. The top of these overpressured gas-bearing reservoirs cuts across structural and stratigraphic boundaries and is not associated with any particular lithologic unit. These overpressured accumulations are the result of gas accumulating at rates greater than it is depleted. Data from reference wells indicate that in the deeper parts of the basin the relatively closed nature of this system imposes severe restrictions on the ability of gas to migrate appreciable distances from the inter bedded source rocks. Consequently, the temporal relationships of hydrocarbon generation and migration with respect to the development of structural and stratigraphic traps is not as important in these unconventional reservoirs as in more conventional reservoirs. The more important factors related to gas generation and occurrence are source rock (quantity and quality), organic maturation, thermal history, formation pressure, and porosity and permeability variations.

Abstract The lower Frontier Formation in the Moxa arch area of southwestern Wyoming is one of the most prolific gas–producing formations in the Rocky Mountain region. In this study, sedimentologic and stratigraphic analyses were conducted on cores and logs of Frontier wells from the Whiskey Butte and Moxa fields. Lower Frontier sediments were deposited as strandplains and coalescing wave–dominated deltas that prograded into the western margin of the Cretaceous interior seaway during Cenomanian time. Twelve sedimentary facies have been identified. The most common sequence consists of burrowed to cross–bedded nearshore marine (delta front, shore–face and inner–shelf) sandstones disconformably overlain by cross–bedded (active) to soft–sediment deformed (abandoned) distributary–channel sandstones and conglomerates. The sequence is generally capped by delta plain mudstones and silty sandstones. Low permeability sandstone reservoir facies are nonhomoge– neous and include crevasse splay, abandoned and active distributary channel, shoreface, foreshore, and inner shelf sandstones. Distributary–channel facies form 80% of perforated intervals in wells in the southern part of the Moxa area but only 50% to the north. Channel sandstone bodies occur on the same stratigraphic horizon, are laterally discontinuous with numerous permeability barriers, and are occasionally stacked. Upper shoreface and foreshore sandstones thicken to the north and east and are more laterally continuous than channel facies. The percentage of perforated intervals in upper shoreface and foreshore facies increases from 20% in the south to 50% in the north. The lower Frontier sandstones contain strike–oriented shoreface (delta front) and dip–oriented distributary channel sand bodies in approximately equivalent amounts. Delta–plain mudstones thin to the north and east and are an important stratigraphic seal. Highest gas production rates are from distributary channel sandstones closer to the axis of the Moxa arch. However, there appears to be little correlation between the thickness of any reservior facies and net production.