Antrim Shale Research Articles

Abstract: Imaging pre-pleistocene geomorphology via gravity surveying as an aid in the identification of drilling locations in the Antrim Shale, Alcona County, Michigan

Abstract: Imaging pre-pleistocene geomorphology via gravity surveying as an aid in the identification of drilling locations in the Antrim Shale, Alcona County, Michigan

Genetic and temporal relations between formation waters and biogenic methane: Upper Devonian Antrim Shale, Michigan Basin, USA

Controversy remains regarding how well geochemical criteria can distinguish microbial from thermogenic methane. Natural gas in most conventional deposits has migrated from a source rock to a reservoir, rarely remaining associated with the original or cogenetic formation waters. We investigated an unusual gas reservoir, the Late Devonian Antrim Shale, in which large volumes of variably saline water are coproduced with gas. The Antrim Shale is organic-rich, of relatively low thermal maturity, extensively fractured, and is both source and reservoir for methane that is generated dominantly by microbial activity. This hydrogeologic setting permits integration of chemical and isotopic compositions of coproduced water and gas, providing a unique opportunity to characterize methane generating mechanisms. The well-developed fracture network provides a conduit for gas and water mass transport within the Antrim Shale and allows invasion of meteoric water from overlying aquifers in the glacial drift. Steep regional concentration gradients in chemical and isotopic data are observed for formation waters and gases; dilute waters grade into dense brines (300,000 ppm) over lateral distances of less than 30 km. Radiogenic ( 14C and 3H) and stable isotope ( 18O and D) analyses of shallow Antrim Shale formation waters and glacial drift groundwaters indicate recharge times from modern to 20,000 yr bp. Carbon isotope compositions of methane from Antrim Shale wells are typical of the established range for thermogenic or mixed gas (δ 13C = −47 to −56‰). However, the unusually high δ 13C values of CO 2 coproduced with methane (∼+22‰) and dissolved inorganic carbon (DIC) in formation waters (∼+28‰) require bacterial mediation. The δD values of methane and coproduced formation water provide the strongest evidence of bacterial methanogenesis. Methane/[ethane + propane] ratios and δ 13C values for ethane indicate: (1) the presence of a thermogenic gas component that increases basinward and (2) progressive bacterial oxidation of ethane as the Antrim Shale subcrop is approached. Multiple episodes of Pleistocene glaciation over northern Michigan appear critical to the development of these gas deposits. Loading of thick ice sheets may have provided hydraulic head that enhanced dilation of preexisting fractures and influx of meteoric water. The physical erosion cycle of repeated glacial advances and retreats exhumed the Antrim Shale around the northern margin of the Michigan Basin, subjecting it to near-surface physiochemical and biochemical processes. The chemical and hydrologic relations demonstrated in the Antrim Shale reservoir suggest a dynamic connection between Pleistocene glacial history of the midcontinent region and development of recoverable, microbially generated natural gas reserves.

Microbial Production and Modification of Gases in Sedimentary Basins: Constraints from Isotopic Compositions

Unconventional natural gas reservoirs, such as organic-rich shales and coalbeds, are gaining in economic significance worldwide. Many of these fields contain some portion of microbial methane, either enhancing or replacing thermogenic gas. Importantly, these microbes produce isotopic and compositional effects on the various gas components that often obfuscate their origin. An expanding data set for gases produced from Devonian black shales in the Michigan and Illinois basins, USA, has allowed for a detailed examination of the related chemical and isotopic compositional changes in gas-water systems that trace these processes. The Antrim Shale, within the northern margin of the Michigan Basin, has recently been shown to produce economic quantities of methane that is dominantly bacterial in origin, based on integrated chemical and isotopic analyses of formation waters and co-produced gas (Martini et al., 1996). The most compelling evidence for microbial generation is the correlation between deuterium in methane and coproduced water (Fig. 1). Exploration for economic microbial gas deposits has been linked to low thermal maturity of the host rock organic matter, development of an open, permeable fracture network, and hydrologic conditions that permit freshwater recharge. Further expansion in the Michigan and Illinois basins has allowed us to develop this hypothesis in areas with differing geologic histories and hydrologic settings. Expansion along the western and southern margins of the Michigan Basin at shallow depths within the Antrim Shale has yielded results that are very similar to those previously reported for the northern margin. Waters show evidence of meteoric influx (salinities increasing basinward from subcrop) and microbial activity. Gas chemistries suggest the occurrence of bacterial methanogenesis. In contrast, deeper, midbasin Antrim Shale development has proven unsuccessful. Here, waters show no signs of meteoric mixing, having salinities and stable isotope compositions (O and H) typical of basinal brines. The gases produced include significant volumes of ethane and propane. Importantly, the correlation between the deuterium in methane and that in co-produced waters is absent. These results suggest the gas produced is thermogenic. The isotopic effects of microbial activity are also seen in the 6a3C values of ethane. The 513C values for methane and ethane are plotted against the 51So values of co-produced waters in Fig. 2. The 6~80 values represent the influx of dilute waters, with the most negative values being from shallow wells near the subcrop of the shale, and the most positive values being from deeper wells within the basin. The methane values are invariant while those for ethane become increasingly higher as the ~lSo values of

Abstract: Antrim Shale Resource and Reservoir Characterization as an Analog for Diffusion Controlled Gas Production from the Monterey Formation 

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Microbial generation of economic accumulations of methane within a shallow organic-rich shale

ALTHOUGH methane of bacterial origin is ubiquitous in marine and freshwater sediments, economic accumulations of bacterial gases occur mainly at depths of several kilometres in Tertiary basins that had high sedimentation rates1,2. Here we present an integration of geochemical and isotopic data from gas and water extracted from the Upper Devonian Antrim shale, along the northern margin of the Michigan basin, which demonstrates that significant volumes of bacterial gas have been generated in organic-rich shales at depths of less than 600 metres. The Antrim shale is mainly a self-sourced reservoir, in contrast to conventional gas deposits that have migrated from a source to a reservoir, and has become one of the most actively exploited gas reservoirs3 in the United States. The gas-forming processes operating at shallow depths in the Antrim shale are not unique4, and an understanding of these processes should lead to the identification and development of other economic, non-conventional gas deposits around the world.

Geochemical Constraints on Microbial Methanogenesis in an Unconventional Gas Reservoir: Devonian Antrim Shale, MI: ABSTRACT

The Upper Devonian Antrim Shale is a self-sourced, highly fractured gas reservoir. It subcrops around the margin of the Michigan Basin below Pleistocene glacial drift, which has served as a source of meteoric recharge to the unit. The Antrim Shale is organic-rich (>10% total organic carbon), hydrogen-rich (Type I kerogen) and thermally immature (R[sub o] = 0.4 to 0.6). Reserve estimates range from 4-8 Tcf, based on assumptions of a thermogenic gas play. Chemical and isotopic properties measured in the formation waters show significant regional variations and probably delineate zones of increased fluid flow controlled by the fracture network. [sup 14]C determinations on dissolved inorganic carbon indicate that freshwater recharge occurred during the period between the last glacial advance and the present. The isotopic composition of Antrim methane ([delta][sup 13]C = -49 to -59[per thousand]) has been used to suggest that the gas is of early thermogenic origin. However, the highly positive carbon of co-produced CO[sub 2] gas ([delta][sup 13]C [approximately] +22[per thousand]) and DIC in associated Antrim brines ([delta][sup 13]C = +19 to +31[per thousand]) are consistent with bacterially mediated fractionation. The correlation of deuterium in methane ([delta]D = -200 to -260[per thousand]) with that of the co-produced watersmore » (SD = -20 to -90176) suggests that the major source of this microbial gas is via the CO[sub 2] reduction pathway within the reservoir. Chemical and isotopic results also demonstrate a significant (up to 25%) component of thermogenic gas as the production interval depth increases. The connection between the timing of groundwater recharge, hydrogeochemistry and gas production within the Antrim Shale, Michigan Basin, is likely not unique and may find application to similar resources elsewhere.« less

The Antrim Shale, Fractured Gas Reservoirs with Immense Potential: ABSTRACT

The Antrim Shale, Fractured Gas Reservoirs with Immense Potential: ABSTRACT

Antrim Shale Fractured Reservoirs: Their Potential Throughout the Michigan Basin: ABSTRACT

Antrim Shale Fractured Reservoirs: Their Potential Throughout the Michigan Basin: ABSTRACT

Additional Potential for Older, Antrim Shale Wells: ABSTRACT

Additional Potential for Older, Antrim Shale Wells: ABSTRACT

Fracture Analysis of the Upper Devonian Antrim Shale, Michigan Basin: ABSTRACT

Fracture Analysis of the Upper Devonian Antrim Shale, Michigan Basin: ABSTRACT

Hydrogeochemistry of the Upper Devonian Antrim Shale, Michigan Basin: An Unconventional Gas Reservoir, A Complex Aquifer

Hydrogeochemistry of the Upper Devonian Antrim Shale, Michigan Basin: An Unconventional Gas Reservoir, A Complex Aquifer

Geologic and Production Comparisons of the New Albany Shale of the Illinois Basin With the Michigan Basin's Antrim Shale and the Appalachian Basin's Ohio Shale

Geologic and Production Comparisons of the New Albany Shale of the Illinois Basin With the Michigan Basin's Antrim Shale and the Appalachian Basin's Ohio Shale

The Antrim Shale: Structural and Stratigraphic Influences on Gas Production

The Antrim Shale of the Michigan basin is one of the most actively drilled gas plays in the United States. Core analysis, geologic mapping, and core to log correlations of a 9 mi{sup 2} study area in the middle of the present play have defined geologic influences on the location and productivity of Antrim reservoirs. Application of these factors in the design of exploration and development strategies could improve gas recovery from the Antrim Shale. The lower section of the Antrim Shale, containing the present producing horizons, is composed of four lithologies that subdivide the Antrim into facies and parasequences based upon their mineralogy and textural characteristics. The black shales of the producing horizons are characterized by high but variable quartz contents and an extremely fine-grained matrix of muscovite and clays. The black shales are surrounded by two types of gray shale, differentiated by amount and form of carbonates, and a green shale. The type of shale bounding the productive, organic-rich black shales may affect stimulation strategies and their effectiveness. These black shales average 10% but can be as high as 20% TOC by weight. The organic contents impart a distinctive signature to gamma ray logs that enabled isopach, lithofacies,more » and structural mapping of the Antrim. Correlated with available production data, the maps reveal distinct trends suggesting that well performance is influenced by both structural and stratigraphic controls.« less

Geological Controls on Natural Gas Production in the Antrim Shale of the Michigan Basin: ABSTRACT

The Antrim Shale (Devonian-Mississippian) is a prolific natural gas reservoir with distinctive source rock and reservoir characteristics. The Antrim is composed of two distinctive lithofacies: a black shale lithofacies having total organic carbon (TOC) values as high as 12% and a gray-green shale lithofacies having TOC values generally below 0.5 %. The black shale facies is the primary source bed and reservoir for natural gas. Based on Rock-Eval data the kerogen in the Antrim Shale is only marginally mature with respect to generation of liquid hydrocarbons. This in the range of 435{degree}C, vitrinite reflectance values are 0.41, and thermal alteration index (TAI) is 2. These data indicate a maximum burial temperature of approximately 60{degree}C in Otsego County, Michigan, the main play area. Although the thermal maturation level in this area is very low, the gas produced from the Antrim is internally sourced and thermogenic; this interpretation is based on the presence of trace amounts of high-gravity oil and a thermogenic isotopic signature of produced gas samples. The black shale facies in the Antrim contains significant authigenic silica and is more susceptible to fracturing compared to the carbonate-cemented gray-green shales facies. Extremely low gas permeability values (0.1 md) indicates that fracturesmore » serve as conduits for delivery of gas to the borehole. Most of the gas must be stored in the shale matrix porosity because total gas volume produced far exceeds fracture reservoir volume.« less

Oil and Gas Developments in Michigan in 1989

In 1989, drilling for Devonian Antrim Shale targets dominated Michigan's drilling scene with 66% of the wells drilled having Antrim Shale objectives. The remaining drilling activity was spread among rocks ranging from the Mississippian through the Precambrian throughout the Michigan basin. Exploration resulted in 37 discoveries, 49% of which were Niagaran reef reservoirs. Another 38% of the discoveries was in the still-emerging Lower Ordovician deep play. Drilled footage amounted to 745,160 ft exploratory and 1,322,951 ft development, compared with 1,023,471 ft exploratory and 1,080,978 ft development in 1988. An additional 66,575 ft was drilled in facility or service wells. Gas sales increased in 1989, whereas oil production declined. Preliminary figures show that Michigan produced 21,754,847 bbl of oil and 162,826 mmcf of gas in 1989.

Antrim Shale Depositional Environments, Diagenesis, and Source Rock Potential in Michigan Basin: ABSTRACT

The Antrim Shale in the Michigan basin is a significant reservoir of in-situ natural gas. Presently it is being drilled in only a few northern counties of Michigan, but may be producible basin-wide. Several authors have suggested that the reservoir resulted from fracturing. Two processes may have caused these fractures: (1) framework collapse due to volume reduction associated with the conversion of organic matter to gas, and (2) the loss of interstitial water resulting from the conversion of smectite to illite. It has been suggested that the sediments are thermally immature and that the natural gas is biogenic in origin. The Antrim Shale is a facies equivalent of other Mid-Continent Black Shales that are documented to have been deposited in an oxygen-stratified basin, with three zones, aerobic, dysaerobic, and anaerobic. Water depth and wave energy apparently controlled the amount of oxygen in the depositional environment and thus the preservation of organic matter in the sediments. If anaerobic conditions existed then bioturbation of the sediments was low and the preservability of organic matter was high. The organic content of the shales, and the potential production of natural gas, is related to environment of deposition. By understanding the facies relationships, the environmentmore » of deposition, and the vertical and areal distribution of these facies, nature of the fracture systems, and the maturation level of the hydrocarbons, a better exploration program can be developed for the exploitation of the Antrim Shale gas reservoirs.« less

Oil and Gas Developments in Michigan in 1988

Drilling for Devonian Antrim Shale targets surpassed the search for Middle Silurian Niagaran reefs, which had dominated Michigan's drilling scene for the past 19 years. In 1988, 36% of the wells drilled in Michigan had Antrim Shale objectives. Remaining drilling activity was spread among rocks ranging from the Mississippian through the Precambrian throughout the Michigan basin. Exploration resulted in 40 discoveries, 58% of which were Niagaran reef reservoirs. Another 25% of the discoveries was in the still emerging Lower Ordovician deep play; an additional 13% of the discoveries was attributed to the shallow gas play in the Antrim Shale. Drilled footage amounted to 1,023,471 ft exploratory and 1,080,978 ft development, compared with 1,218,472 ft exploratory and 898,575 ft development in 1987. An additional 60,902 ft was drilled in facility or service wells. Gas sales increased slightly in 1988, but oil production declined. Preliminary figures show that Michigan produced 23,713,160 bbl of oil and 151,809 mmcf of gas in 1988.

Oil and Gas Developments in Michigan in 1987

The exploration for and development of Middle Silurian Niagaran reefs dominated Michigan's oil and gas industry activity for the 19th year in a row. In 1987, 48% of the wells drilled had Niagaran objectives. Remaining drilling activity was spread among rocks from the Mississippian to the Precambrian throughout the Michigan basin. Exploration resulted in 48 new discoveries, 52% of which were Niagaran reef reservoirs. Another 21% of the discoveries was in the still-growing Lower Ordovician deep gas play; an additional 13% of the discoveries was attributed to a rapidly expanding shallow gas play in the Devonian Antrim Shale. Exploration and development drilled footage was 1,218,472 ft exploratory and 898,575 ft development, compared with 1,496,033 ft exploratory and 1,220,013 ft development in 1986. An additional 38,215 ft was drilled in facility or service wells. Gas sales declined in 1987, whereas oil production rose slightly. Preliminary figures show that Michigan produced 25,937,363 bbl of oil and 150,308 mmcf of gas in 1987.

Oil and Gas Developments in Michigan in 1986

For the 18th consecutive year, exploratory and development drilling for Middle Silurian Niagaran reefs dominated Michigan's oil and gas drilling activity. In 1986, 53% of the wells drilled had Niagaran objectives. The remaining drilling activity was spread among rocks from the Mississippian to the Precambrian throughout the Michigan basin. Exploration resulted in 63 new discoveries, 73% of which were Niagaran reef reservoirs. While much attention was deservedly focused on the success of the deep Lower Ordovician gas play, many independent operators and a few major companies continued to make important new discoveries to extend the geographic limits and lifetime of the prolific northern and southern Niagaran reef trends. The short-term outlook is for continued exploration and development in these plays and in the shallow Devonian Antrim Shale gas of Otsego County, with drilling to other zones again severely curtailed. Exploration and development footage was 1,496,033 ft exploratory and 1,220,013 ft development, compared with 2,346,021 ft exploratory and 1,676,686 ft development in 1985. An additional 71,916 ft was drilled in facility or service wells. Gas sales rose again in 1986, whereas oil production declined. Preliminary figures show that Michigan produced 25,704,963 bbl of oil and 159,632 mmcf of gas in 1986.

Reaction kinetics of the gasification of Michigan Antrim oil shale char

Both CO 2 and steam gasification kinetics were determined for Michigan Antrim shale char using TGA techniques in combination with on-line gas chromatography. While the reaction kinetic expressions were similar to those previously derived for Green River Formation (western USA) and Swedish Ranstad shale chars, the gasification rates were found to be on the same order as those of Ranstad char but significantly lower than those of western shale char. In addition, the gas produced from steam gasification was found to be significantly higher in CO than the corresponding gas from western shale char. This and the presence of significant quantities of CO 2 lower the attractiveness of Antrim char as a source of synthesis gas or hydrogen.