Dudley D. Rice

Generation, Accumulation, and Resource Potential of Biogenic Gas

Biogenic gas is generated at low temperatures by decomposition of organic matter by anaerobic microorganisms. More than 20% of the worlds 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.

Assessment of hydrocarbon source rock potential of Polish bituminous coals and carbonaceous shales

Abstract 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.

Composition and origin of coalbed gases in the Lower Silesian basin, southwest Poland

Abstract 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.

Characterization of coal-derived hydrocarbons and source-rock potential of coal beds, San Juan Basin, New Mexico and Colorado, U.S.A.

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).

Relation of Natural Gas Composition to Thermal Maturity and Source Rock Type in San Juan Basin, Northwestern New Mexico and Southwestern Colorado

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.

Coastal and Deltaic Sedimentation of Upper Cretaceous Eagle Sandstone: Relation to Shallow Gas Accumulations, North-Central Montana

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.

Character, origin and occurrence of natural gases in the Anadarko basin, southwestern Kansas, western Oklahoma and Texas Panhandle, U.S.A.

Abstract 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.

Conventional and low-permeability reservoirs of shallow gas in the northern Great Plains

Significant resources of natural gas occur at shallow depths (<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. 10 refs.

Distinction Between In-Situ Biogenic Gas and Migrated Thermogenic Gas in Ground Water, Denver Basin, Colorado: ABSTRACT

Methane-rich gas commonly occurs in ground water in the Denver basin, southern Weld County, Colorado. The gas generally is in solution in the ground water of the aquifer. However, exsolution resulting from reduction to hydrostatic pressure during water production may create free gas, which can accumulate in wells and buildings and pose an explosion and fire hazard. The ground water is found in siltstones and sandstones that make up the Upper Cretaceous Laramie-Fox Hills aquifer at End_Page 539------------------------------ depths of 500 ft (152 m) or less. The gas-bearing aquifer is underlain by gas-bearing, low-permeability sandstones of Early Cretaceous age that form the Wattenberg field. It contains reserves of natural gas at depths of 7,500 to 8,500 ft (2,285 to 2,590 m) but requires massive hydraulic stimulation to provide economic flow rates. Gases from the water wells are generally dry (C1/C1-5 > 0.99) and enriched in the light isotope 12C (^dgr13C1 values range from -73 to -70 ppt). These gases are interpreted to be of biogenic origin that are being or have been generated in an anoxic, sulfate-free environment within the aquifer system. The probable source of carbon is the organic matter originally deposited with the Upper Cretaceous sediments. In an area north of Milton Lake, coinciding with a region containing higher amounts of dissolved sulfate in ground water, methane is generally not detected in ground water. Water from wells in this region has a putrid odor and probably contains hydrogen sulfide resulting from microbial sulfate reduction. The absence of methane is probably explained by the fact that methanogenesis generally is not concurrent with the process of sulfate reduction and usually begins after dissolved sulfate is removed from ground water. Gases from the Wattenberg field, coming from considerably greater depths than those from the water wells, are distinctly different from most of the water-well gas in both chemical and isotopic composition. They contain significant amounts of heavier hydrocarbons (C1/C1-5 values range from 0.83 to 0.87) and are isotopically heavier (^dgr13C1 values range from -49 to -43 ppt). The chemical and isotopic composition of the gases indicate that they are thermogenic in origin and were generated by thermal cracking processes during intermediate stages of thermal maturity in the deeper part of the Denver basin. This interpretation is consistent with the level of maturation determined by source rock studies. Occasionally, gases from water wells are almost identical in both chemical and isotopic composition to gases produced from the underlying Wattenberg field in the immediate area. These gases are also interpreted to be of thermogenic origin and probably migrated from deeper reservoirs. End_of_Article - Last_Page 540------------

Paleotectonic Controls on Deposition of Niobrara Formation, Eagle Sandstone, and Equivalent Rocks (Upper Cretaceous), Montana and South Dakota: ABSTRACT

The deposition of the Niobrara Formation, Eagle Sandstone, and equivalent Upper Cretaceous rocks was controlled by paleotectonic activity on lineament-bound basement blocks in Montana and South Dakota. Linear features observed on Landsat images provide an interpretation of lineament geometry that is independent of stratigraphic data. Paleotectonism on lineament-bound blocks is documented in three areas that were located in distinctly different depositional environments. In central Montana, coastal and inner-shelf sandstones and nonmarine coastal-plain and wave-dominated delta deposits reflect paleotectonic control by lineaments trending north-south, east-west, northwest, and northeast. In the northern Black Hills, chalks and outer-shelf sandstones End_Page 866------------------------------ reflect control by lineaments trending north-south, northwest, and northeast. In central South Dakota, erosion and deposition of chalk and calcareous shale on a west-sloping carbonate ramp were controlled by lineaments that generally trend northeast and northwest. Paleotectonism on lineament-bound blocks characterized four tectonic zones located in the Late Cretaceous seaway: the western foredeep, the west-median trough, the east-median hinge, and the eastern platform. The regional geometry of all four tectonic zones appears to be related to the geometry of the convergent plate margin on the west. Paleotectonic activity on lineament-bound blocks may have been the result of horizontal forces related to the convergent margin and to vertical forces related to the movement of the North American plate. End_of_Article - Last_Page 867------------