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We analyzed 40 coal samples and 45 carbonaceous shale samples of varying thermal maturity (vitrinite reflectance 0.59% to 4.28%) from the Upper Carboniferous coal-bearing strata of the Upper Silesian, Lower Silesian, and Lublin basins, Poland, to evaluate their potential for generation and expulsion of gaseous and liquid hydrocarbons. We evaluated source rock potential based on Rock-Eval pyrolysis yield, elemental composition (atomic H/C and O/C), and solvent extraction yields of bitumen. An attempt was made to relate maceral composition to these source rock parameters and to composition of the organic matter and likely biological precursors. A few carbonaceous shale samples contain sufficient generation potential (pyrolysis assay and elemental composition) to be considered potential source rocks, although the extractable hydrocarbon and bitumen yields are lower than those reported in previous studies for effective Type III source rocks. Most samples analysed contain insufficient capacity for generation of hydrocarbons to reach thresholds required for expulsion (primary migration) to occur. In view of these findings, it is improbable that any of the coals or carbonaceous shales at the sites sampled in our study would be capable of expelling commercial amounts of oil. Inasmuch as a few samples contained sufficient generation capacity to be considered potential source rocks, it is possible that some locations or stratigraphic zones within the coals and shales could have favourable potential, but could not be clearly delimited with the number of samples analysed in our study. Because of their high heteroatomic content and high amount of asphaltenes, the bitumens contained in the coals are less capable of generating hydrocarbons even under optimal thermal conditions than their counterpart bitumens in the shales which have a lower heteroatomic content.

Coalbed gases in the Lower Silesian Coal Basin (LSCB) of Poland are highly variable in both their molecular and stable isotope compositions. Geochemical indices and stable isotope ratios vary within the following ranges: hydrocarbon (CHC) index CHC=CH4/(C2H6+ C3H8) from 1.1 to 5825, wet gas (C2+) index C2+=(C2H6+ C3H8+ C4H10+ C5H12) / (CH4+ C2H6+ C3H8+ C4H10+ C5H12) 100 (%) from 0.0 to 48.3%, CO2–CH4 (CDMI) index CDMI=CO2/(CO2+ CH4) 100 (%) from 0.1 to 99.9%, δ13C(CH4) from −66.1 to −24.6‰, δD(CH4) from −266 to −117‰, δ13C(C2H6) from −27.8 to −22.8‰, and δ13C(CO2) from −26.6 to 16.8‰. Isotopic studies reveal the presence of 3 genetic types of natural gases: thermogenic (CH4, higher gaseous hydrocarbons, and CO2), endogenic CO2, and microbial CH4 and CO2. Thermogenic gases resulted from coalification processes, which were probably completed by Late Carboniferous and Early Permian time. Endogenic CO2 migrated along the deep-seated faults from upper mantle and/or magma chambers. Minor volumes of microbial CH4 and CO2 occur at shallow depths close to the abandoned mine workings. “Late-stage” microbial processes have commenced in the Upper Cretaceous and are probably active at present. However, depth-related isotopic fractionation which has resulted from physical and physicochemical (e.g. diffusion and adsorption/desorption) processes during gas migration cannot be neglected. The strongest rock and gas outbursts occur only in those parts of coal deposits of the LSCB which are dominated by large amounts of endogenic CO2.

The continental shelf on the western margin of the Cretaceous western interior seaway was a muddy surface which bore abundant northwest southeast trending sand bodies as much as 20 m thick and many km long Important examples are the Medicine Hat Sandstone the Mosby Sandstone Member of the Belle Fourche Shale the Shannon and Sussex Sandstone Members of the Cody Shale and the Duffy Mountain sandstone and the Tocito Sandstone Lentil of the Mancos Shale These deposits resemble the storm built and tide built sand ridges reported from the modem Atlantic Continental Shelf or from the Southern Bight of the North Sea However although modern sand ridges may protrude from the Holocene transgressive sand sheet through overlying Holocene mud deposits to be exposed on the present sea floor no modern examples are known where sand ridges are completely encased in mud as the Cretaceous examples seem to have been Hydrodynamicaltheory suggests that special circumstances may allow the formationof sand bodies from a storm flow regime whose transported load consists of sandy mud Under normal circumstances such a transport regime would deposit little clean sand The sea floor is eroded as storm currents accelerate but erosion ceases when theboundary layer becomes loaded with as much sediment as the fluid power expenditure will permit flow reaches capacity Deposition of a graded bed occurs as the storm wanes and a storm sequence is likely to consist of thin clay beds with basal sand laminae However slight topographic irregularities in the shelf floor may result in horizontal velocity gradients so that the flow undergoes acceleration and deceleration in space as well as in time Fluiddynamical theory predicts deceleration of flowacross topographic highs as well as down their lee sides The coarsest fraction of the transported load sand will be deposited in the zone of deceleration and deposition will occur throughout the flow event Relatively thick storm beds 2 to 10 decimeters can acccumulate in this manner Enhancement of initial topographic reliefresults in positive feedback as the bedform becomes larger it extracts more sand from the transported load during each successive storm Individual storm beds may tend to fine upward waning current grading but the sequence as a whole is likely to coarsen upwards reflecting increasing perturbation of flow by the bedform as its amplitude increases Stability theory suggests that theend product of these processes should be a sequence of regularly spaced sand ridges on the shelf surface However sandstone bodies within the Cretaceous shelf deposits are quite localized in stratigraphic position and lateral distribution Upward coarsening sequences are a widespread phenomenon in the western interior Cretaceous system and the sandstone bodies appear to constitute localized sand concentrations within more extensive sandy or silty horizons Es pecially widespread upward coarsening sequences appear to be due to the close coupling between activity in theoverthrust belt to the west and sedimentation in the foreland basin Each thrusting episode increased relief as well as the load on the crust Initially the increased relief as well as the load on the crust Initially the increased relief resulted in a flood of sediment transported to the shelf on the western margin of the basin so that the shelf became shallower As it did so wave scour on the shelf floor increased the amount of bypassing and resulted in the deposition of increasingly coarser sediment As relief in the hinterland waned subsidence overtook sedimentation and the shelf subsided Renewed thursting began the cycle anew In a second mechanism for the formation of upward coarsening sequences tectonic uplift affect portions of the shelf as well The initiation of Sevier or Laramide structural elements beneath the shelf and the remobilization of other older structures created submarine topographic highs which caused slight sand enrichment over broad areas The development of sand enriched areasin the shelf floor by both mechanisms led to the flow substrate feedback behavior that built large scale elongate bodies of clean

From abstract: This report is about six gas samples that were obtained from the Mississippian Leadville Limestone in the McElmo field, Colorado, and the Lisbon field, Utah. These samples were recorded to contain a high reading of carbon dioxide and the report investigates these results.

The Piceance basin is a hydrocarbon-rich province that has natural gas production from reservoirs ranging in age from Late Jurassic to Eocene and large undeveloped resources of natural gas in coal beds and tight sandstone reservoirs of Cretaceous age. Gases from all producing intervals are of predominantly thermal origin and become isotopically heavier (delta isotope{13}C[1]: -51.3 to -29.1 o/oo) and chemically drier (C[1]/C[1-5]: 0.26 to 1.00) with increasing thermal maturity of reservoirs (R[o]: 0.45 to 2.40%) over a depth range of 1100 to 11,702 ft (335-3567 m). Scatter in trend is attributed to source rock differences and considerable vertical and lateral migration. Based on chemical and isotopic composition, three major types of gases can be distinguished: those generated from mixed type II and III kerogens, those from dispersed type III kerogen, and those from coal. Gases generated from mixed type II and III kerogens are produced from the Upper Jurassic Morrison Formation, the Lower Cretaceous Cedar Mountain Formation, the Upper Cretaceous Dakota Sandstone, the Upper Cretaceous Mancos "B" producing interval, and marginal marine sandstones of the Upper Cretaceous Iles producing interval. These gases are associated with minor amounts of oil and probably were generated from kerogen in the marine Mancos Shale. Gases generated from dispersed type III kerogen are produced from nonmarine sandstones of the Upper Cretaceous Williams Fork producing inter al and from thermally immature reservoirs in the overlying Paleocene and Eocene Fort Union and Wasatch Formations. These nonassociated gases contain large amounts of CO[2] and probably were generated from carbonaceous shales in the Williams Fork producing interval. Their presence in immature Fort Union and Wasatch reservoirs implies considerable vertical migration. The third type of gas is methane rich, is produced by devolatilization of humic coal, and is generally in coal beds of the Cameo-Fairfield zone of the Williams Fork producing interval. These gases are not the major source for adjacent sandstone reservoirs. A fourth, distinct type of isotopically light thermogenic gas occurs in immature reservoirs of the Eocene Green River Formation. This gas is inferred to have migrated from u identified deeper, more mature source rocks.

Natural gas production in the Anadarko basin comes from three geographically separated areas that can be differentiated by age of reservoir and by inferred nature of organic, thermal origin of the gases. In the central basin, non-associated gases are produced mainly from Upper Mississippian and Pennsylvanian sandstones. Gas samples are from reservoirs as much as 6588 m deep. Gases become isotopically heavier ( δ 13 C 1 -values range from −49.8 to −33.2‰) and chemically drier (C 2+ -values range from 1–33%) with increasing level of thermal maturity. Gases were generated mainly from interbedded shales with type-III kerogen during the mature and post-mature stages of hydrocarbon generation. Deviations from the trend are due to vertical migration and mixing of gases generated at different levels of thermal maturity over the past 250 Myr. In the giant Panhandle-Hugoton field, non-associated gases are generally produced from Permian carbonates at depths of δ 13 C 1 -value is −43.2‰, mean C 2+ -value is 14%). Because organic-rich, mature source rocks are not present in the area, gases probably were generated in the central basin from Pennsylvanian or older source rocks during the mature stage of hydrocarbon generation. This interpretation implies migration over distances as much as several hundred kilometers. In the Sooner Trend, associated gases are produced from Silurian, Devonian and Mississippian carbonates at depths as great as 2950 m and were generated from type-II kerogen during the mature stage of hydrocarbon generation. Associated oil usually correlates with extracts of the Upper Devonian and Lower Mississippian Woodford Shale. Gases are isotopically lighter (mean δ 1 3 C 1 -value is −43.9‰) and chemically wetter (mean C 2+ value is 14%) than those derived from type-III kerogen at an equivalent level of thermal maturity.

Coal beds are considered to be a major source of nonassociated gas in the Rocky Mountain basins of the United States. In the San Juan basin of northwestern New Mexico and southwestern Colorado, significant quantities of natural gas are being produced from coal beds of the Upper Cretaceous Fruitland Formation and from adjacent sandstone reservoirs. Analysis of gas samples from the various gas-producing intervals provided a means of determining their origin and of evaluating coal beds as source rocks. The rank of coal beds in the Fruitland Formation in the central part of the San Juan basin, where major gas production occurs, increases to the northeast and ranges from high-volatile B bituminous coal to medium-volatile bituminous coal (Rm values range from 0.70 to 1.45%). On the basis of chemical, isotopic and coal-rank data, the gases are interpreted to be thermogenic. Gases from the coal beds show little isotopic variation (δ13C1 values range −43.6 to −40.5 ppt), are chemically dry (C1/C1–5 values are > 0.99), and contain significant amounts of CO2 (as much as 6%). These gases are interpreted to have resulted from devolatilization of the humic-type bituminous coal that is composed mainly of vitrinite. The primary products of this process are CH4, CO2 and H2O. The coal-generated, methane-rich gas is usually contained in the coal beds of the Fruitland Formation, and has not been expelled and has not migrated into the adjacent sandstone reservoirs. In addition, the coal-bed reservoirs produce a distinctive bicarbonate-type connate water and have higher reservoir pressures than adjacent sandstones. The combination of these factors indicates that coal beds are a closed reservoir system created by the gases, waters, and associated pressures in the micropore coal structure. In contrast, gases produced from overlying sandstones in the Fruitland Formation and underlying Pictured Cliffs Sandstone have a wider range of isotopic values (δ13C1 values range from −43.5 to −38.5 ppt), are chemically wetter (C1/C1–5 values range from 0.85 to 0.95), and contain less CO2 (< 2%). These gases are interpreted to have been derived from type III kerogen dispersed in marine shales of the underlying Lewis Shale and nonmarine shales of the Fruitland Formation. In the underlying Upper Cretaceous Dakota Sandstone and Tocito Sandstone Lentil of the Mancos Shale, another gas type is produced. This gas is associated with oil at intermediate stages of thermal maturity and is isotopically lighter and chemically wetter at the intermediate stage of thermal maturity as compared with gases derived from dispersed type III kerogen and coal; this gas type is interpreted to have been generated from type II kerogen. Organic matter contained in coal beds and carbonaceous shales of the Fruitland Formation has hydrogen indexes from Rock-Eval pyrolysis between 100 and 350, and atomic H:C ratios between 0.8 and 1.2. Oxygen indexes and atomic O:C values are less than 24 and 0.3, respectively. Extractable hydrocarbon yields are as high as 7,000 ppm. These values indicate that the coal beds and carbonaceous shales have good potential for the generation of liquid hydrocarbons. Voids in the coal filled with a fluorescent material that is probably bitumen is evidence that liquid hydrocarbon generation has taken place. Preliminary oil-source rock correlations based on gas chromatography and stable carbon isotope ratios of C15+ hydrocarbons indicate that the coals and (or) carbonaceous shales in the Fruitland Formation may be the source of minor amounts of condensate produced from the coal beds at relatively low levelsof thermal maturity (Rm=0.7).

Summary Significant resources of natural gas occur at shallow depths [less than 4,000 ft (1200 m)] within a large area of the northern Great Plains. Reservoir properties are controlled mainly by the depositional environments in which source and reservoir rocks accumulated. Exploration and development of potential gas resources depends on successful prediction of the physical characteristics and distribution of gas-bearing rocks. Introduction Major resources of natural gas trapped in low-permeability, low-pressure reservoirs underlie large areas of the northern Great Plains at depths of less than 4,000 ft (1200 m). Rising gas prices and accelerated drilling suggest that the area may be of considerable economic importance in the near future. Effective exploration for low-permeability (unconventional) reservoirs depends on successful prediction of the distribution and physical characteristics of the gas-bearing rocks and on carefully managed completion and development techniques. The purpose of this paper is to compare. describe, and contrast conventional and low-permeability shallow gas reservoirs to provide geologic information useful to exploration and development of these resources. Potential unconventional reservoirs in the northern Great Plains occur within strata from the base of the Mowry Shale (Upper Cretaceous) to the top of the Judith River Formation (Upper Cretaceous). These reservoirs are thin. discontinuous siltstone and sandstone laminae enclosed in thick sequences of offshore marine shale. Gas occurs in a sedimentary section that is immature with respect to thermal oil and gas generation. The gas in both conventional and unconventional reservoirs was generated during the breakdown of organic matter by anaerobie microorganisms at shallow depths in accumulating sediments and is referred to as biogenic gas. The biogenic gas is composed predominantly of methane (C1/C1 through 5 greater than 0.99 enriched in the light isotope 12 C ( 13 C1 = -60 to -70 ppt). The occurrence of natural gas and the physical properties of the gas-bearing reservoirs are controlled chiefly by the depositional environments in which source and reservoir rocks accumulated. Examples for comparison have been selected from the Eagle Sandstone/Telegraph Creek Formation stratigraphic interval because equivalent rocks produce economic quantities of gas from three major reservoir types:conventional reservoirs in coastal deposits are illustrated with an example from the Eagle Sandstone in Tiger Ridge field. Bearpaw Mountains area, north-central Montana (Fig. 1 );shelf sandstone reservoirs of intermediate quality are exemplified by a coarsening-upward sequence in the Shannon Sandstone Member of the Gammon Shale from Bowdoin Dome, north central Montana (Fig. 1);a productive siltstone/shale reservoir in the Gammon Shale at Little Missouri field in southwestern North Dakota (Fig. 1) provides an example of a low-permeability shallow gas reservoir. Comparable data for each reservoir type are listed in Table Conventional Reservoirs in Coastal Sandstones Conventional reservoirs in the Eagle/Telegraph Creek stratigraphic interval are confined to coastal sandstones of the Eagle Sandstone that occur in a north-south-trending zone through central Montana (Fig. 1). This zone approximates the position of the fluctuating shoreline during a major marine regression. Sandstones in this zone are widespread (blanketlike) bodies, more than 40 ft (12 m) thick, deposited under relatively high-energy conditions along the shoreline. The dominant transporting force was wave action that generated longshore and tip currents.

Natural gas is being developed and produced in the Bowdoin Dome area from shallow, low-pressure, low-permeability reservoirs that were previously noncommercial. Reservoirs are dominantly thin, discontinuous, shaly siltstone and sandstone laminae and beds which cannot be distinguished on conventional logs. They require stimulation to provide commercial flow rates and necessitate more sophisticated evaluation methods than do conventional reservoirs. Introduction This paper reviews the geologic, technological, and economic parameters that have contributed to the development of natural gas reserves in the recently expanded portions of the Bowdoin Dome area. The technology and methods discussed are those used by Midlands Gas Corp., a subsidiary of Kansas-Nebraska Natural Gas Co. Inc, and may differ from those of other operators in the area. The Bowdoin Dome is a very large structural uplift located in eastern Phillips and western Valley counties in north-central Montana (Fig. 1). Natural gas was first discovered on the structure in 1913 in a shallow well drilled for water. The central part of the structure was developed through the 1950's with natural openhole completions in wells drilled where the pay zones are shallower. With the advent of improved completion techniques and increased gas prices in the 1970's, the field was expanded in size to more than 600 sq miles (1550 km2). Natural gas is being produced from low-permeability, low-pressure reservoirs at depths less than 2,000 ft (610 m). The pay zones consist of thin, discontinuous laminae and beds of siltstone and sandstone, and a more persistent limestone bed. These beds are enclosed in a thick sequence of offshore marine shale of late Cretaceous age. The gas is of biogenic origin and was generated in the surrounding marine shales. One major problem existed with the most recent expansion. The development program was designed to be run concurrently with the construction of a large gathering facility. The purpose was to increase economic viability and to develop a more efficient optimization of stimulation techniques and spacing criteria. However, delays in the approval of the pipeline facility forced the operators to use technology evolved in other areas. Specifically, the development of similar shallow gas accumulations in southeastern Alberta was used as an analog for the original treatment designs and 640-acre (2.6 x 10(6) m2) spacing. Most of the development in the Bowdoin Dome area was completed before the final construction of a gathering facility. Therefore, information on the adequacy of the initial development design has become available only recently. Structure The Bowdoin Dome is a very large, nearly oval arch which has structural closure of about 700 ft (200 m) on top of the Upper Cretaceous Greenhorn lime. Most of the new development concentrates on a north/northwest-trending nose that extends across the Canadian border.

Major resources of natural gas are entrapped in low-permeability, low-pressure reservoirs at depths less than 4,000 ft (1,200 m) in the northern Great Plains. This shallow gas is the product of the immature stage of hydrocarbon generation and is referred to as biogenic gas. Prospective low-permeability, gas-bearing reservoirs range in age from late Early to Late Cretaceous and include most of the section from the base of the Mowry Shale to the top of the Judith River Formation. For detailed examination, the potential reservoir section was divided into five intervals represented by one or more formations and their correlatives. The intervals selected correspond to (1) Mowry Shale, (2) Belle Fourche Shale and Greenhorn Formation, (3) Carlile Shale, (4) Niobrara and Telegrap Creek Formations and Eagle Sandstone, and (5) Claggett Shale and Judith River Formation and their equivalents. Within each interval, several different facies are developed. The following facies were identified and mapped for each interval: nonmarine rocks, coastal sandstones, shelf sandstones, siltstones, shales, and chalks. Two types of shelf sandstone were differentiated but generally not mapped separately because of lack of well log control. The "sand ridge" type has reservoir properties comparable to coastal sandstones and occurs as isolated tongues as much as 75 ft (23 m) thick. The second type of shelf sandstone is in beds commonly less than 1 in. (3 cm) thick which are interbedded with shale and contain a high content of allogenic silt- and clay-size material. It is impossible to differentiate these individual beds on conventional well logs. The siltstone and shale facies are grouped to ether because conventional logs cannot distinguish between these two rock types, particularly when they are interbedded. For future evaluation of natural gas resources from low-permeability reservoirs, it will be necessary to differentiate between the siltstone and shale facies and to identify individual beds, particularly very thin ones, within the shelf sandstone facies. Each facies contains distinct reservoir types, some of which are low in permeability. The most promising low-permeability reservoirs are developed in the shelf sandstone, siltstone, and chalk facies. Reservoirs within these facies are particularly attractive because they are enveloped by thick sequences of shale which serve as both a source and a seal for the gas. When naturally fractured, these shales also may be low-productivity gas reservoirs similar to the Devonian shales of the Appalachian basin. In addition, facies with low-permeability reservoirs are present over most of the study area when maps for all of the intervals are combined. Natural gas is produced from low-permeability reservoirs in the northern Great Plains in the southern part of western Canada. Established production covers an area of approximately 8,000 sq mi (20,700 sq km) where reported recoverable reserves average as much as 2 Bcf sq mi. Using these reserve data as an analog, the United States portion may contain resources of natural gas in excess of 100 Tcf. The volume of recoverable gas in the United States will depend on the development of improved recovery technology and higher gas prices relative to costs.

San Juan basin is a roughly circular, asymmetric structural depression located in northwestern New Mexico and southwestern Colorado. Ultimate recoverable reserves of predominantly nonassociated gas (23 tcf, 0.65 × 1012 m3) are present in the structurally low part of the central basin. The major producing intervals are low-permeability sandstone reservoirs in the Upper Cretaceous Dakota Sandstone, Mesaverde Group, and Pictured Cliffs Sandstone. Lesser amounts of oil and/or gas are produced from Pennsylvanian, Jurassic, and Cretaceous rocks along the southern and western flanks of the basin. The gases display a trend of becoming isotopically heavier (^dgr13C1 values range from -48.7 to -31.4^pmil and chemically drier (C1/C1-5 values range from 0.75 to 0.99) with increasing depth. These changes are assumed to be the result of thermal cracking processes, and the gases are interpreted to have been generated during the mature and post-mature stages of hydrocarbon generation. However, there is considerable scatter in the data which is interpreted to result from a difference in source rock type. Gases generated from nonmarine (humic) source rocks are isotopically heavier and chemically drier than those generated from marine (sapropelic) source rocks at equivalent levels of maturity. The gases also become isotopically heavier and chemically drier to the northeast, following the trend of increasing maturity of all units in that direction. The increase in maturity is attributed to a combination of greater burial depth and a higher geothermal gradient resulting from batholiths to the north in the San Juan Mountains area. Maximum burial and heat flow occurred during the Oligocene, which probably coincided with peak hydrocarbon generation. Lack of oil in the central basin is believed to be the result of two factors. First, gas in reservoirs such as the Dakota Sandstone may have resulted from thermal cracking of oil generated from marine source rocks during late mature (wet gas-condensate) and post-mature (dry gas) stages of hydrocarbon generation. Second, gas in reservoirs such as Mesaverde Group and Pictured Cliffs Sandstone is nonassociated and probably was generated from nonmarine (coaly) organic matter during the mature and post-mature stages. Minor amounts of condensate, instead of oil, may have been generated from nonmarine source rocks during the mature stage.

The newly established Mount Pablo Formation includes strata that crop out in the Sawtooth Range that are equivalent to the lower part of the Kootenai Formation in and west of the Sweetgrass Arch. Palynomorphs indicate an age of early Albian to possibly late Aptian. The Mount Pablo Formation unconformably overlies Jurassic rocks and is overlain unconformably by the Lower Cretaceous Kootenai Formation. Lateral equivalents of the Mount Pablo belonging to the Kootenai are widespread in the subsurface west of the crest of the Kevin-Sunburst dome. The Mount Pablo consists of nonmarine sandstone and conglomerate in the lower part, variegated mudstone interbedded with some sandstone in the middle part, and limestone interbedded with and overlain by mudstone in the upper part. The lower sandstone and conglomerate is the Cut Bank Sandstone Member, a previously established unit assigned as the basal member of the Kootenai Formation in the subsurface in the Cut Bank area that is extended to the Sawtooth Range and assigned to the Mount Pablo. This member ranges in thickness from 9 to 30 m (meters), whereas the formation ranges from 34 to 90 m. The Mount Pablo Formation is correlative with the Cut Bank Sandstone Member, Lander Member as described in 1966 by M. H. Oakes, and the basal "brown lime" unit of the Moulton Member, all of which are included in the lower part of the Kootenai Formation in the Cut Bank area. Lateral equivalents of the Mount Pablo pinch out eastward onto the Kevin-Sunburst dome, where the Sunburst Sandstone Member forms the basal unit of the Kootenai Formation and is correlative with the upper part of the Moulton Member. In the Canadian Foothills, the Cadomin Formation, which is a prominent conglomerate, correlates with the Cut Bank Sandstone Member of the Mount Pablo Formation or of the Kootenai Formation. The upper part of the Mount Pablo is equivalent to the Gladstone Formation in the southern foothills, to the Gething Formation in the northern foothills, and to the McMurray Formation in the central plains of Alberta. The palynological assemblage in the Mount Pablo is similar to that found in other Lower Cretaceous formations in the Western Interior and is somewhat similar to assemblages in the early to early middle Albian McMurray Formation of Alberta.

The Mosby Sandstone Member of the Greenhorn Formation is composed of thin (less than 6 ft or 1.8 m), very fine-grained to fine-grained sandstone cycles separated by shale. The sandstones occur either as individual beds, generally less than 1 ft (9.3 m) thick and separated by interbeds of shale, or as amalgamated beds. The base of each cycle is a planar to undulating erosional End_Page 772------------------------------ surface, and the top is gradational with the overlying shale. The dominant sedimentary structures are parallel lamination and low-angle cross-lamination filling broad, shallow troughs. Wave-ripple cross-lamination and wave ripples are commonly developed in the upper parts of the cycles. Trace fossils are generally restricted to the rippled surfaces and consist of horizontal Ophiomorpha and Thalassinoides, Diplocraterion, and Chondrites. Shells, including gastropods, bivalves, and ammonites, occur as lenses near the base of the cycles and as concretions laterally where the sandstones are not developed. The thin sandstone cycles occur as elongate bodies that are a few tens of miles across and several tens of miles long. The bodies collectively occur in a southward-projecting lobe that covers an area of 40,000 sq mi (64,372 sq km) in central Montana. The sediments were transported as much as 700 mi (1,127 km) in a south-eastward direction from the Dunvegan delta in north-western Alberta. The sandstone cycles are interpreted to have been deposited by storm events on a broad shallow shelf. The sand was probably transported by intense wave action and storm-generated currents and deposited after erosion during the waning stages of the storm. End_of_Article - Last_Page 773

The Upper Cretaceous Eagle Sandstone of central Montana was deposited during a general eastward progradation of the western shoreline of the narrow, north-south-trending Western Interior epicontinental seaway. Cordilleran highlands to the west were episodically uplifted, and provided the main source for sediments deposited in the seaway. On the Central Montana uplift, the lower member of the Eagle consists predominantly of very fine-grained sandstone, which is exposed as a thick (average 100 ft, 30 m), continuous topographic rim. This sandstone gradationally overlies shales of the Telegraph Creek Formation. Within the rim, resistant beds and concretions of calcite-cemented sandstone define several smaller units, which can be traced laterally over distances of several miles. These units maintain fairly uniform thicknesses from north to south. However, in an east-west direction, the units thin, are imbricated, and become younger to the west. Excellent exposures of these imbricated lenses occur along a rim that extends 12 mi (19 km) southwest from the town of Winnett. Although the sandstone of the lower member is very fine-grained throughout the rim, systematic changes occur within a single lens. These changes include: (1) thinning and grading into shale and siltstone to the southwest: (2) bioturbation decreasing upward and to the northeast; (3) oblique Asterosoma burrows predominating in the lower part of each lens and to the southwest, with horizontal Ophiomorpha burrows being more common in the middle part of each lens and to the northeast; (4) parallel bedding and hummocky cross-stratification successively occurring in the upper part of each lens and to the northeast; and (5) relatively straight-crested symmetrical ripples generally capping each lens. The sedimentary structures within each lens indicate increasing energy and shoaling upward, bu do not indicate subaerial exposure. The lenses in the lower member are interpreted as landward-prograding (westward) sand ridges that were deposited on the inner shelf at distances of tens of miles from the shoreline. Laterally equivalent coastal sandstones of the Virgelle Sandstone Member prograded seaward (eastward) at this same time. The lenses are elongated in a north-south direction, generally parallel to the coast. However, the exact geometry of individual ridges is unknown. After bypassing the shoreface zone, the sand probably was transported parallel to the shoreline by geostrophic currents driven by wind-forcing. Storm waves reworked the upper, seaward-facing slopes of the ridges, whereas landward-facing parts of the ridges were more protected and subjected to bioturbation. Ridges that occur on the Central Montana uplift are comparable in many aspects to sand ridges on the modern Atlantic inner shelf. However, the modern sand ridges differ from those of the Eagle in two ways: (1) they occur at angles oblique to the shoreline, and (2) they resulted from "shoreface detachment" during the Holocene transgression. End_of_Article - Last_Page 1352

Late Cretaceous marine deposition in the western interior of the United States occurred in an epicontinental seaway elongate in a north-south direction. In central Montana, the western side of the seaway was characterized by a broad, tectonically active shelf. In eastern Montana and the western Dakotas, an actively subsiding basin was located in the central part of the seaway. In western and central South Dakota, the eastern side of the seaway was a more stable west-sloping ramp. Distinctive facies belts in the Eagle Sandstone and equivalent rocks are found in each of these tectonic settings, and some specific tectonic features have expression in the facies patterns. However, paleotectonism was even more important than suggested by these regional patterns. Selected study reas End_Page 1355------------------------------ show that subtle tectonic features have influenced deposition within each of the regional facies belts. On the western shelf, coastal sandstones of the Eagle-Sandstone near the Bearpaw Mountains show facies and isopach variations which are controlled by linear features visible on satellite images; the linear features generally trend north-south and east-west. Inner shelf sandstones of the Eagle thin and pass laterally northeastward into marine siltstones and shales across the Cat Creek fault zone near Winnett, Montana. Sandstone lenses in the lower Eagle, which are interpreted to be sand ridges, prograde south and west at approximately right angles to the fault zone. Farther east on the outer margin of the western shelf, areas of sand ridge fields in the Shannon Sandstone Member of the Gammon Shale are delimited by northeast and northwest linear features observed on satellite images nea the northern Black Hills. Within the basin, thick areas of Gammon Shale are delimited by northeast and northwest lineaments interpreted from Landsat linear features. On the eastern ramp, noncalcareous shales of the Gammon Member of the Pierre Shale thin and intertongue eastward with chalks in the upper part of the Niobrara Formation. This facies change occurs across linear features visible on Landsat images in western South Dakota. To the east at the inner margin of the ramp, the degree of erosion on the unconformity between the Niobrara Formation and the overlying Pierre Shale changes systematically across northeast-trending Landsat linear features observed near the Missouri River in central South Dakota. Based on these studies, we interpret the stratigraphic variations to be the expression of paleotectonism on discrete basement blocks bounded by fault zones which are observed on Landsat images as linear features. On the western shelf, elevated blocks controlled the sites of the winnowing and deposition of sandstones. Within the basins, subsiding basement blocks were filled by deposition of shales. These basin blocks acted as sediment sinks which inhibited the eastward dispersal of terrigenous materials from the west. On the eastern ramp, chalks were deposited and locally eroded on slightly elevated blocks which were relatively free of terrigenous material. Paleotectonism, therefore, influenced deposition not only on the active western shelf and in the basin, but also on the more stabl eastern ramp. End_of_Article - Last_Page 1356

Biogenic gas is generated at low temperatures by decomposition of organic matter by anaerobic microorganisms. More than 20% of the world's discovered gas reserves are of biogenic origin. A higher percentage of gases of predominantly biogenic origin will be discovered in the future. Biogenic gas is an important target for exploration because it occurs in geologically predictable circumstances and in areally widespread, large quantities at shallow depths. In rapidly accumulating marine sediments, a succession of microbial ecosystems leads to the generation of biogenic gas. After oxygen is consumed by aerobic respiration, sulfate reduction becomes the dominant form of respiration. Methane generation and accumulation become dominant only after sulfate in sediment pore water is depleted. The most important mechanism of methane generation in marine sediments is the reduction of CO2 by hydrogen (electrons) produced by the anaerobic oxidation of organic matter. CO2 is the product of either metabolic decarboxylation or chemical decarboxylation at slightly higher temperatures. The factors that control the level of methane production after sediment burial are anoxic environment, sulfate-deficient environment, low temperatu e, availability of organic matter, and sufficient space. The timing of these factors is such that most biogenic gas is generated prior to burial depths of 1,000 m. In marine sediments, most of the biogenic gas formed can be retained in solution in the interstitial (pore) waters because of higher methane solubility at the higher hydrostatic pressures due to the weight of the overlying water column. Under certain conditions of high pressures and (or) low temperatures, biogenic methane combines with water to form gas hydrates. Biogenic gas usually can be distinguished from thermogenic gas by chemical and isotopic analyses. The hydrocarbon fraction of biogenic gas consists predominantly of methane. The presence of as much as 2% of heavier hydrocarbons can be attributed to admixture of minor thermogenic gas due to low-temperature degradation of organic matter. The amounts of hydrocarbon components other than methane generally are proportional to temperature, age, and organic-matter content of the sediments. Biogenic methane is enriched in the light isotope 12C (^dgr13C1 lighter than -55 ppt) owing to kinetic isotope fractionation by methanogens. The variations in isotopic composition of biogenic methane are controlled primarily by ^dgr13C of the original CO2 substrate, which reflects the net isotopic effect of both addition and removal of CO2. The methane isotopic composition also can be affected by mixing of isotopically heavier thermogenic gas. The possible complicating factors require that geologic, chemical, and isotopic evidence be considered in attempts to interpret the origin of gas accumulations. Accumulations of biogenic gas have been discovered in Canada, Germany, Italy, Japan, Trinidad, the United States, and USSR in Cretaceous and younger rocks, at less than 3,350 m of burial, and in marine and nonmarine rocks. Other gas accumulations of biogenic origin have undoubtedly been discovered; however, data that permit their recognition are not available.

Prior to 1970, shallow gas production was established in "sweet spots" where the reservoirs are best developed in the northern Great Plains. Recent advances in completion technology coupled with higher gas prices have led to the expansion of these areas through the development of submarginal, low-permeability reservoirs. The development is concentrated in two main areas which cover more than 22,000 sq km. The gas occurs at depths less than 600 m, and recoverable reserves average 2 Bcf of gas per section. The reservoirs are of Late Cretaceous age and generally consist of siltstone and sandstone laminae, a few millimeters or less in thickness, enclosed in organic-rich silty shale that serves as a seal and was the source for the biogenic gas. The laminae are discontinuous because of depositional processes and/or biologic activity. Coarsening-upward sandstone cycles are locally developed. Although these cycles display the best reservoir properties, they are volumetrically minor. Porosity is confined to small passageways within the laminae, among randomly oriented allogenic clay platelets, and to well-sorted sandstone near the top of coarsening-upward cycles. Diagenesis has reduced permeability and resulted in the formation of fluid-sensitive clays and carbonate cement. However, dissolutio has enhanced porosity and permeability in well-sorted lithologies. The reservoirs are stimulated with sand proppant, carbon dioxide, and water to provide economic flow rates. Typical wells have initial potentials of 300 Mcf of gas per day. Production declines rapidly the first year, but levels off to about 100 Mcf of gas per day. Wells are difficult to evaluate because conventional logs cannot distinguish pay zones in sequences of thin, discontinuous, low-permeability reservoirs. End_of_Article - Last_Page 773

Hydrocarbons are being produced at depths ranging from 4,000 to 8,500 ft along the axis of the Denver basin. On the basis of chemical and isotopic composition, gases from the three main reservoirs of Cretaceous age are interpreted to be of thermogenic origin. Gases from the Terry and Hygiene Sandstone Members of the Pierre Shale, the youngest reservoir, are the isotopically lightest (^dgr13C1 values range from -55.7 to -49.2 ^pmil) and chemically wettest (C1/C1-5 values range from 0.67 to 0.83), and are associated. Gases from the Codell Sandstone Member of the Carlile Shale generally become isotopically heavier (^dgr13C1 values range from -47.8 to -43.9^pmil) as they become chemically drier (C1/C SUB>1-5 values range from 0.76 to 0.8). During the main part of mature stage, oil and associated gas (isotopically lightest and chemically wettest) were generated from type II kerogen. During the hotter, later part of the stage, wet gas (isotopically heaviest and chemically driest) and condensate were generated from residual kerogen and from heavier hydrocarbons previously generated. Variations in character of the gases from the "J" sandstone, the oldest reservoir, are similar to those of the Codell; they become isotopically heavier (^dgr13C1 values range from -47.9 to -43.1^pmil) as they become chemically drier (C1/C1-5 values range from 0.84 to 0.87). Gases from "J" are interpreted to have been generated at similar levels of maturity as those of the Codell, but from type III kerogen. These gases are nonassociated and are isotopically heavier and chemically drier at similar levels of maturity than are those generated from type II kerogen. End_of_Article - Last_Page 301

Natural gas is produced at shallow depths from chalk beds of the Upper Cretaceous Niobrara Formation in northeastern Colorado and northwestern Kansas. The depth of gas-productive trend increases to the northwest from 250 to 850 m (820-2,790 ft). The chalks are fine-grained limestone, consisting mainly of calcareous nannofossils and other microfossils, that are characterized by high porosity (30-45%) and low permeability (about 1 md). Core samples from the productive area average 30% acid-insoluble residue. Most of the insoluble residue, which consists of clay minerals and organic matter, is concentrated in alternating laminations. The gases are methane-rich (C1/C1-5 > 0.98), are enriched in the light isotope 12C (13C1 values range from -65 to -55 ppt), and become isotopically heavier with increasing depth across the trend. The shallow gas in the Niobrara is interpreted to be of biogenic rather than thermogenic origin because of its chemical and isotopic composition and of source-rock studies indicating that Upper Cretaceous rocks in this region are immature with respect to thermogenic hydrocarbon generation. To the northwest, however, these rocks are mature and were capable of generating oil at the time of maximum burial and/or heat flow. The biogenic gas was generated early in the burial history of the chalks by microbial degradation of organic matter in an anaerobic, presumably sulfate-free environment. In-situ gas generation is indicated, because low permeability inhibited long-range migration and because organic-rich laminae provided an adequate source for the gas. Organic-carbon values average 3.2%, and the organic matter consists primarily of hydrogen-rich sapropelic kerogen (type II), typical of an open-marine environment. The chalks are overlain by a thick section of shale containing many bentonite beds in the lower part that served as a seal for gas after the reservoirs were naturally fractured later in the burial history.

Depositional environments of the Upper Cretaceous Eagle Sandstone were studied at outcrops along the Missouri River and its southern tributaries from the town of Virgelle southeastward to the mouth of the Judith River in north-central Montana. In this area, the Eagle is divided into three members--the Virgelle Sandstone Member, 80 to 130 ft (24 to 40 m) thick, and the middle and upper members, which together are as much as 220 ft (67 m) thick. The Eagle Sandstone is underlain by the Telegraph Creek Formation and overlain by the Claggett Shale, both of Late Cretaceous age. The Telegraph Creek accumulated in an offshore-shoreface transition environment and grades upward into the shoreface and foreshore sandstones of the Virgelle Sandstone Member. The basal Virgelle was depo ited along an eastwardly prograding coastal-interdeltaic mainland shoreline. The middle member of the Eagle represents coastal-plain deposition. In the eastern part of the area, the upper part of this member comprises a sheetlike, delta-front sandstone capped by a thin coastal-plain unit. The delta-front sandstone was deposited along a wave-dominated shoreline that prograded over a coastal plain following an overall marine transgression. The upper member lies disconformably on the middle member and is represented by rock types which were deposited in two distinct depositional settings. Interbedded sandstone, siltstone, and shale that exhibit variable bedding types in the northern outcrops probably accumulated in a tidal-flat environment. Progradational cycles of shoreface sandstones are haracteristic of the upper member in the southern outcrop. Chert gravel in the upper member and in the basal part of the Claggett Shale forms a persistent time interval in the northern Rockies and probably represents a lag deposit laid down by the transgressing sea. Natural gas from shallow accumulations in the Eagle Sandstone of the Bearpaw Mountains area is of biogenic origin and was probably generated in the surrounding shales during Late Cretaceous time. Although gravity-induced faults formed after the gas generation provide the final trapping mechanism, the initial control for entrapment was stratigraphic. Most of the early generated gas has remigrated into separate, discrete structural traps where porous reservoirs are developed; some of the gas may have been selectively sealed in original stratigraphic traps. The outcropping depositional units, in particular the reservoir sandstones, can be traced into the subsurface and identified in nearby wells. Thus, an understanding of depositional environments is an important exploration tool for sha low gas accumulations.