Changes

===Miocene Monterey Shale, Santa Maria Basin, California: Fractured Shale-oil Production===

===Miocene Monterey Shale, Santa Maria Basin, California: Fractured Shale-oil Production===

[[File:M97Ch1.2FG3.jpg|thumb|500px|{{figure number|3}}Union Oil Jesus Maria A82-19 Monterey Shale geochemical log, Santa Maria Basin, California. The oil saturation index (OSI) values exceed 100 mg oil/g TOC in the uppermost section of this Monterey Shale section, whereas the lowermost section shows a much thinner interval of crossover. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG4.jpg|thumb|500px|{{figure number|4}}Coastal Oil amp Gas (OampG) Corp. 3-Hunter-Careaga well, Monterey Shale geochemical log, Santa Maria Basin, California. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

M97Ch1.2FG3.jpg|{{figure number|3}}Union Oil Jesus Maria A82-19 Monterey Shale geochemical log, Santa Maria Basin, California. The oil saturation index (OSI) values exceed 100 mg oil/g TOC in the uppermost section of this Monterey Shale section, whereas the lowermost section shows a much thinner interval of crossover. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.

M97Ch1.2FG4.jpg|{{figure number|4}}Coastal Oil amp Gas (OampG) Corp. 3-Hunter-Careaga well, Monterey Shale geochemical log, Santa Maria Basin, California. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.

The first example of producible shale oil is taken from the Miocene Monterey Shale, Santa Maria Basin, California (see Appendix immediately following this chapter, location 49 on North American resource map). The Monterey Shale has been the source of substantial amounts of oil in various conventional reservoirs in this basin, but also produces from fractured Monterey Shale itself. In fact, the shale itself has yielded approximately 1 billion bbl of oil since 1900 (Williams, 2010).

The first example of producible shale oil is taken from the Miocene Monterey Shale, Santa Maria Basin, California (see Appendix immediately following this chapter, location 49 on North American resource map). The Monterey Shale has been the source of substantial amounts of oil in various conventional reservoirs in this basin, but also produces from fractured Monterey Shale itself. In fact, the shale itself has yielded approximately 1 billion bbl of oil since 1900 (Williams, 2010).

===Miocene Antelope Shale, San Joaquin Basin, California===

===Miocene Antelope Shale, San Joaquin Basin, California===

[[File:M97Ch1.2FG5.jpg|thumb|300px|{{figure number|5}}Arco Oil amp Gas 1-Bear Valley well, Antelope Shale geochemical log, Asphalto field, San Joaquin Basin, California. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG5.jpg|thumb|500px|{{figure number|5}}Arco Oil amp Gas 1-Bear Valley well, Antelope Shale geochemical log, Asphalto field, San Joaquin Basin, California. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

Elsewhere in California, organic-rich source rocks are also found in the San Joaquin Basin. These shales, age equivalent to the Monterey Shale, are the Miocene Antelope and McLure shales that are also oil productive. An example is provided by the Arco Oil amp Gas 1-Bear Valley well, Asphalto field in Kern County, California. In the early 1990s, Arco's Research Center and Humble Geochemical Services completed analyses of this well as a joint research project prompting completion of the well in the Antelope Shale. The geochemical results were later presented, showing the production of about 250 bbl of oil/day from the Antelope Shale (Jarvie et al., 1995). Before completing the well, the prediction of API gravity was also completed using pyrolysis and geochemical fingerprinting techniques with the assessment of about a 30 to 35deg API oil based on correlation of rock data to produced oils with measured API gravities. The vertical well flowed approximately 38.95 m3/day (245 bbl/day) of 32deg API oil. The scout ticket for this well reports the completion interval as being 1621.5 to 1987.9 m (5320–6522 ft). The scout ticket also reports log-derived porosities in the 10 to 15% range.

Elsewhere in California, organic-rich source rocks are also found in the San Joaquin Basin. These shales, age equivalent to the Monterey Shale, are the Miocene Antelope and McLure shales that are also oil productive. An example is provided by the Arco Oil amp Gas 1-Bear Valley well, Asphalto field in Kern County, California. In the early 1990s, Arco's Research Center and Humble Geochemical Services completed analyses of this well as a joint research project prompting completion of the well in the Antelope Shale. The geochemical results were later presented, showing the production of about 250 bbl of oil/day from the Antelope Shale (Jarvie et al., 1995). Before completing the well, the prediction of API gravity was also completed using pyrolysis and geochemical fingerprinting techniques with the assessment of about a 30 to 35deg API oil based on correlation of rock data to produced oils with measured API gravities. The vertical well flowed approximately 38.95 m3/day (245 bbl/day) of 32deg API oil. The scout ticket for this well reports the completion interval as being 1621.5 to 1987.9 m (5320–6522 ft). The scout ticket also reports log-derived porosities in the 10 to 15% range.

===Devonian Bakken Formation, Williston Basin===

===Devonian Bakken Formation, Williston Basin===

[[File:M97Ch1.2FG6.jpg|thumb|300px|{{figure number|6}}(A, B) Geochemical database of total organic carbon (TOC) and Rock-Eval analyses from the North Dakota Geological Survey (2008). A plot of free oil contents versus TOC illustrates the oil crossover effect of the upper Bakken Shale, Middle Member of the Bakken Formation, lower Bakken Shale, and Three Forks: (A) all data with up to 30% TOC, and (B) reduced scale emphasizing the Middle Member of the Bakken Formation and Three Forks data. S1 = Rock-Eval measured oil contents.]]

[[File:M97Ch1.2FG7.jpg|thumb|300px|{{figure number|7}}EOG Resources Inc. 1-05H-NampD geochemical log showing the geochemical results for the Scallion and Bakken formations. This log illustrates the oil crossover effect (S1/total organic carbon [TOC]) for the carbonate-rich Scallion and Middle Member. The upper and lower Bakken Shales are organic rich and carbonate lean but have high oil contents for the level of thermal maturity (sim0.60% Roe). The high oil contents in the Bakken shales are offset by the high retention of oil. S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

M97Ch1.2FG6.jpg|{{figure number|6}}(A, B) Geochemical database of total organic carbon (TOC) and Rock-Eval analyses from the North Dakota Geological Survey (2008). A plot of free oil contents versus TOC illustrates the oil crossover effect of the upper Bakken Shale, Middle Member of the Bakken Formation, lower Bakken Shale, and Three Forks: (A) all data with up to 30% TOC, and (B) reduced scale emphasizing the Middle Member of the Bakken Formation and Three Forks data. S1 = Rock-Eval measured oil contents.

M97Ch1.2FG7.jpg|{{figure number|7}}EOG Resources Inc. 1-05H-NampD geochemical log showing the geochemical results for the Scallion and Bakken formations. This log illustrates the oil crossover effect (S1/total organic carbon [TOC]) for the carbonate-rich Scallion and Middle Member. The upper and lower Bakken Shales are organic rich and carbonate lean but have high oil contents for the level of thermal maturity (sim0.60% Roe). The high oil contents in the Bakken shales are offset by the high retention of oil. S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.

Production from fractured upper Bakken Shale has been ongoing since the 1980s from several fields in North Dakota including fields such as Bicentennial, Elkhorn Ranch, Buckhorn, Rough Rider, Demores, and Pierre Creek. Production reported by the North Dakota Geological Survey (2010) for fractured upper Bakken Shale is approximately 3,714,699 m3 (23 million bbl), with an average GOR from all upper Bakken Shale production of about 426 m3/m3 (2395 scf/bbl).

Production from fractured upper Bakken Shale has been ongoing since the 1980s from several fields in North Dakota including fields such as Bicentennial, Elkhorn Ranch, Buckhorn, Rough Rider, Demores, and Pierre Creek. Production reported by the North Dakota Geological Survey (2010) for fractured upper Bakken Shale is approximately 3,714,699 m3 (23 million bbl), with an average GOR from all upper Bakken Shale production of about 426 m3/m3 (2395 scf/bbl).

===Lower Cretaceous Niobrara Shale-oil System, Denver Basin===

===Lower Cretaceous Niobrara Shale-oil System, Denver Basin===

[[File:M97Ch1.2FG8.jpg|thumb|300px|{{figure number|8}}Geochemical log of Golden Buckeye Petroleum 2-Gill Land Associates well, Weld County, Colorado, Denver-Julesberg Basin, showing the oil crossover in the Niobrara B carbonate. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG8.jpg|thumb|500px|{{figure number|8}}Geochemical log of Golden Buckeye Petroleum 2-Gill Land Associates well, Weld County, Colorado, Denver-Julesberg Basin, showing the oil crossover in the Niobrara B carbonate. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

A shale-oil resource system with characteristics similar to the Bakken shale-oil resource system is the Lower Cretaceous Niobrara Formation of the Denver-Julesberg Basin, often referred to simply as the Denver Basin. A key difference between the two systems is an average TOCo of approximately 2.69% for the source rock intervals in the Niobrara Shale versus about 14.7% for the upper Bakken Shale at Parshall field. The relative hydrogen contents are quite different also, with HIo values about 345 mg HC/g TOC for the Niobrara Shale and more than 700 mg HC/g TOC for the upper and lower Bakken Shale in the Parshall field area.

A shale-oil resource system with characteristics similar to the Bakken shale-oil resource system is the Lower Cretaceous Niobrara Formation of the Denver-Julesberg Basin, often referred to simply as the Denver Basin. A key difference between the two systems is an average TOCo of approximately 2.69% for the source rock intervals in the Niobrara Shale versus about 14.7% for the upper Bakken Shale at Parshall field. The relative hydrogen contents are quite different also, with HIo values about 345 mg HC/g TOC for the Niobrara Shale and more than 700 mg HC/g TOC for the upper and lower Bakken Shale in the Parshall field area.

===Mississippian Barnett Shale-oil System, Fort Worth Basin===

===Mississippian Barnett Shale-oil System, Fort Worth Basin===

[[File:M97Ch1.2FG9.jpg|thumb|300px|{{figure number|9}}Geochemical log of Four Sevens 1-Scaling Ranch A, Clay County, Texas, Fort Worth Basin showing the oil crossover in the lower Barnett Shale with its lean carbonate content. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG9.jpg|thumb|500px|{{figure number|9}}Geochemical log of Four Sevens 1-Scaling Ranch A, Clay County, Texas, Fort Worth Basin showing the oil crossover in the lower Barnett Shale with its lean carbonate content. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

The Barnett Shale has produced limited amounts of oil since the 1980s. Certainly much conventional production in the Fort Worth Basin has been sourced by the Barnett Shale, as substantiated by Hill et al. (2007).

The Barnett Shale has produced limited amounts of oil since the 1980s. Certainly much conventional production in the Fort Worth Basin has been sourced by the Barnett Shale, as substantiated by Hill et al. (2007).

===Eagle Ford Shale, Austin Chalk Trend, Texas===

===Eagle Ford Shale, Austin Chalk Trend, Texas===

[[File:M97Ch1.2FG10.jpg|thumb|300px|{{figure number|10}}Geochemical database of Eagle Ford Shale showing the oil crossover effect.]]

[[File:M97Ch1.2FG11.jpg|thumb|300px|{{figure number|11}}Champlin Petroleum Co. 1-Mixon well geochemical log showing the oil crossover in the 13,570 to 13,630 ft (4136 to 4154 m) interval, with intermittent crossover in deeper intervals. Note the extremely high carbonate content of the Eagle Ford Shale. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields; H = hydrogen index.]]

M97Ch1.2FG10.jpg|{{figure number|10}}Geochemical database of Eagle Ford Shale showing the oil crossover effect.

[[File:M97Ch1.2FG12.jpg|thumb|300px|{{figure number|12}}Organic and carbonate carbon comparison in the Barnett and Eagle Ford shales. As total organic carbon (TOC) increases in the Barnett Shale, carbonate content decreases. In the Eagle Ford Shale, the organic-rich intervals typically have 30 to 70% carbonate contents.]]

M97Ch1.2FG11.jpg|{{figure number|11}}Champlin Petroleum Co. 1-Mixon well geochemical log showing the oil crossover in the 13,570 to 13,630 ft (4136 to 4154 m) interval, with intermittent crossover in deeper intervals. Note the extremely high carbonate content of the Eagle Ford Shale. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields; H = hydrogen index.

M97Ch1.2FG12.jpg|{{figure number|12}}Organic and carbonate carbon comparison in the Barnett and Eagle Ford shales. As total organic carbon (TOC) increases in the Barnett Shale, carbonate content decreases. In the Eagle Ford Shale, the organic-rich intervals typically have 30 to 70% carbonate contents.

The Upper Cretaceous Eagle Ford Shale is the source of Austin Chalk-produced oils (Grabowski, 1995) along a trend running from central northeastern Texas to south Texas counties bordering Mexico (no. 24 in Appendix immediately following this chapter, Figure 1, shale resource systems in North America). The Eagle Ford Shale averages about 3.7 to 4.5% TOC, with an original HI of about 414 mg HC/g TOC (Grabowski, 1995), although immature roadcuts in Val Verde County, Texas, have HI values more than 600 mg/g (D. M. Jarvie, unpublished data). Grabowski (1995) also estimates oil yields to be about 0.0515 m3/m3 (400 bbl/ac-ft), with values as high as 0.1547 m3/m3 (1200 bbl/ac-ft). EOG Resources currently estimates the Eagle Ford Shale play as having 1.43 times 108 m3 (900 million BOE) in their lease areas alone (EOG Resources, 2010).

The Upper Cretaceous Eagle Ford Shale is the source of Austin Chalk-produced oils (Grabowski, 1995) along a trend running from central northeastern Texas to south Texas counties bordering Mexico (no. 24 in Appendix immediately following this chapter, Figure 1, shale resource systems in North America). The Eagle Ford Shale averages about 3.7 to 4.5% TOC, with an original HI of about 414 mg HC/g TOC (Grabowski, 1995), although immature roadcuts in Val Verde County, Texas, have HI values more than 600 mg/g (D. M. Jarvie, unpublished data). Grabowski (1995) also estimates oil yields to be about 0.0515 m3/m3 (400 bbl/ac-ft), with values as high as 0.1547 m3/m3 (1200 bbl/ac-ft). EOG Resources currently estimates the Eagle Ford Shale play as having 1.43 times 108 m3 (900 million BOE) in their lease areas alone (EOG Resources, 2010).

===Other United States Shale-oil Resource Plays===

===Other United States Shale-oil Resource Plays===

[[File:M97Ch1.2FG13.jpg|thumb|300px|{{figure number|13}}Home Petroleum Corp. 2-Phoenix Unit geochemical log in the Powder River Basin showing the oil crossover in the Mowry Shale. Skull Crk = Skull Creek; TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG13.jpg|thumb|500px|{{figure number|13}}Home Petroleum Corp. 2-Phoenix Unit geochemical log in the Powder River Basin showing the oil crossover in the Mowry Shale. Skull Crk = Skull Creek; TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

====Mowry Shale, Powder River Basin====

====Mowry Shale, Powder River Basin====

====Cody and Mowry Shales, Bighorn Basin====

====Cody and Mowry Shales, Bighorn Basin====

[[File:M97Ch1.2FG14.jpg|thumb|300px|{{figure number|14}}Geochemical log of the Gulf Exploration Corp. 1-31-3D-Predicament well, Bighorn Basin. The Cody and Mowry shales show the oil crossover as do the Eagle and Muddy sands. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG14.jpg|thumb|500px|{{figure number|14}}Geochemical log of the Gulf Exploration Corp. 1-31-3D-Predicament well, Bighorn Basin. The Cody and Mowry shales show the oil crossover as do the Eagle and Muddy sands. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

There is no announced discovery of a shale-oil resource system in the Mowry Shale of the Bighorn basin, although it is speculated to be a potential shale-oil resource system much as in the Powder River Basin. An example for potential production is given by the Gulf Exploration Corp. 1-31-3D-Predicament well in Big Horn County, Wyoming. A geochemical log demonstrates oil crossover in the Cody and Mowry shales, with high amounts of oil particularly in the Cody Shale (Figure 14). The Cody Shale shows more than 580 m (1900 ft) of oil crossover suggestive of more than 3.56 times 106 m3/km2 (106 million bbl/mi2) of oil (uncorrected for evaporative losses). At this depth with the high OSI values, it is anticipated that this is open-fractured Cody Shale. Oil also exists in the overlying Eagle Formation sands. Calculated TOCo values range from 2.05 to 4.31%, with HIo values ranging from 78 to 642 mg HC/g TOC. The highest value is a bit anomalous compared with the other five samples of the Cody Shale that only range from 1.94 to 2.65% TOCo and 78 to 284 mg HC/g TOC for HIo.

There is no announced discovery of a shale-oil resource system in the Mowry Shale of the Bighorn basin, although it is speculated to be a potential shale-oil resource system much as in the Powder River Basin. An example for potential production is given by the Gulf Exploration Corp. 1-31-3D-Predicament well in Big Horn County, Wyoming. A geochemical log demonstrates oil crossover in the Cody and Mowry shales, with high amounts of oil particularly in the Cody Shale (Figure 14). The Cody Shale shows more than 580 m (1900 ft) of oil crossover suggestive of more than 3.56 times 106 m3/km2 (106 million bbl/mi2) of oil (uncorrected for evaporative losses). At this depth with the high OSI values, it is anticipated that this is open-fractured Cody Shale. Oil also exists in the overlying Eagle Formation sands. Calculated TOCo values range from 2.05 to 4.31%, with HIo values ranging from 78 to 642 mg HC/g TOC. The highest value is a bit anomalous compared with the other five samples of the Cody Shale that only range from 1.94 to 2.65% TOCo and 78 to 284 mg HC/g TOC for HIo.

====Paradox Basin====

====Paradox Basin====

[[File:M97Ch1.2FG15.jpg|thumb|300px|{{figure number|15}}Mobil Oil Corp. 12-3-Jakeys Ridge geochemical log, Paradox Basin, showing the oil crossover in the uppermost Cane Creek Shale. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG15.jpg|thumb|500px|{{figure number|15}}Mobil Oil Corp. 12-3-Jakeys Ridge geochemical log, Paradox Basin, showing the oil crossover in the uppermost Cane Creek Shale. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

Various shales in the Paradox Basin have been completed for shale gas, but as in many basins, an oil window play is also available for a shale-oil resource system(s) play. In fact, the Pennsylvanian Cane Creek Shale of the Paradox Basin first produced 6264 m3 (39,393 bbl) of oil from the 5-Big Flat vertical well in 1961 in what became the Bartlett Flat field (Chidsey et al., 2004). The only true commercial success from a vertical well came with the 1-Long Canyon that is estimated to have produced 159,000 m3 (1 million bbl) of oil and 3 times 107 m3 (1 billion ft3) of gas (Chidsey et al., 2004).

Various shales in the Paradox Basin have been completed for shale gas, but as in many basins, an oil window play is also available for a shale-oil resource system(s) play. In fact, the Pennsylvanian Cane Creek Shale of the Paradox Basin first produced 6264 m3 (39,393 bbl) of oil from the 5-Big Flat vertical well in 1961 in what became the Bartlett Flat field (Chidsey et al., 2004). The only true commercial success from a vertical well came with the 1-Long Canyon that is estimated to have produced 159,000 m3 (1 million bbl) of oil and 3 times 107 m3 (1 billion ft3) of gas (Chidsey et al., 2004).

====Cretaceous Tuscaloosa Marine Shale, Louisiana====

====Cretaceous Tuscaloosa Marine Shale, Louisiana====

[[File:M97Ch1.2FG16.jpg|thumb|300px|{{figure number|16}}Geochemical log of the Sun Oil Co. 1-Spinks well in Pike County, Mississippi, Mid-Gulf Coast Basin through the Tuscaloosa Shale. The Tuscaloosa Shale has poor to good total organic carbon (TOC) values with no crossover effect in this well. Note the extremely low carbonate content (lt2%) and sulfur content of as much as 3%. S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG16.jpg|thumb|500px|{{figure number|16}}Geochemical log of the Sun Oil Co. 1-Spinks well in Pike County, Mississippi, Mid-Gulf Coast Basin through the Tuscaloosa Shale. The Tuscaloosa Shale has poor to good total organic carbon (TOC) values with no crossover effect in this well. Note the extremely low carbonate content (lt2%) and sulfur content of as much as 3%. S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

The Lower Cretaceous Tuscaloosa Marine Shale (TMS) ranges in thickness from 152.4 m (500 ft) to more than 243.8 m (800 ft) overlain and underlain by sands. The depth to the TMS is found at 3048 m (10,000 ft) and deeper. One well, the Texas Pacific Oil Co. 1-Winfred Blades, in Tangipahoa Parish, Louisiana, produced more than 3180 m3 (20,000 bbl) of oil from perforations in the TMS between 3375 and 3549 m (11,073–11,644 ft) (John et al., 1997).

The Lower Cretaceous Tuscaloosa Marine Shale (TMS) ranges in thickness from 152.4 m (500 ft) to more than 243.8 m (800 ft) overlain and underlain by sands. The depth to the TMS is found at 3048 m (10,000 ft) and deeper. One well, the Texas Pacific Oil Co. 1-Winfred Blades, in Tangipahoa Parish, Louisiana, produced more than 3180 m3 (20,000 bbl) of oil from perforations in the TMS between 3375 and 3549 m (11,073–11,644 ft) (John et al., 1997).

====Heath Shale====

====Heath Shale====

[[File:M97Ch1.2FG17.jpg|thumb|300px|{{figure number|17}}Continental 1-Staunton geochemical log through the Heath Shale in the Central Montana trough. The Heath Shale shows the oil crossover in a carbonate interval at about 2560 ft (sim780 m) and below 2655 ft (lt809 m). TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG17.jpg|thumb|500px|{{figure number|17}}Continental 1-Staunton geochemical log through the Heath Shale in the Central Montana trough. The Heath Shale shows the oil crossover in a carbonate interval at about 2560 ft (sim780 m) and below 2655 ft (lt809 m). TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

The Upper Mississippian Heath Shale in the Central Montana trough is a candidate shale-oil resource system. This system is a fractured shale-oil play with higher porosity and some vertical wells have flowed 200 bbl/day (Oil amp Gas Journal, 2010a).

The Upper Mississippian Heath Shale in the Central Montana trough is a candidate shale-oil resource system. This system is a fractured shale-oil play with higher porosity and some vertical wells have flowed 200 bbl/day (Oil amp Gas Journal, 2010a).

====Marcellus and Utica Shales====

====Marcellus and Utica Shales====

[[File:M97Ch1.2FG18.jpg|thumb|300px|{{figure number|18}}Database of the Ordovician Utica and Devonian Marcellus shales showing the oil crossover effect on select samples. S1 = Rock-Eval measured oil contents.]]

[[File:M97Ch1.2FG18.jpg|thumb|500px|{{figure number|18}}Database of the Ordovician Utica and Devonian Marcellus shales showing the oil crossover effect on select samples. S1 = Rock-Eval measured oil contents.]]

The Devonian Marcellus Shale is regarded as becoming the largest shale-gas resource system in the United States, but areas are also present in western New York and West Virginia where the shale is in the oil window. Wells in these areas show the oil crossover effect. Data from the State Museum of New York show OSI values more than 100 mg oil/g TOC in Erie, Livingston, Allegany, Chautauqua, and Otsego counties and also to the south in northwestern West Virginia (Nyahay et al., 2007).

The Devonian Marcellus Shale is regarded as becoming the largest shale-gas resource system in the United States, but areas are also present in western New York and West Virginia where the shale is in the oil window. Wells in these areas show the oil crossover effect. Data from the State Museum of New York show OSI values more than 100 mg oil/g TOC in Erie, Livingston, Allegany, Chautauqua, and Otsego counties and also to the south in northwestern West Virginia (Nyahay et al., 2007).

==International shale-oil plays==

==International shale-oil plays==

[[File:M97Ch1.2FG19.jpg|thumb|300px|{{figure number|19}}Database of the Triassic Montney Shale samples from the Western Canada sedimentary basin showing the oil crossover effect on select samples. Data from the Geological Survey of Canada (Jarvie, 2011). S1 = Rock-Eval measured oil contents.]]

[[File:M97Ch1.2FG19.jpg|thumb|500px|{{figure number|19}}Database of the Triassic Montney Shale samples from the Western Canada sedimentary basin showing the oil crossover effect on select samples. Data from the Geological Survey of Canada (Jarvie, 2011). S1 = Rock-Eval measured oil contents.]]

 

===Western Canada Sedimentary Basin===

===Western Canada Sedimentary Basin===

Although the Doig Phosphate and Montney Shale are discussed as a shale-gas resource system, they can also produce substantial liquid petroleum depending on the location. What is interesting about the Montney Shale is the overridingly low TOC values reported, suggesting it as only a poor to fair source rock (see part 1 of this chapter). Furthermore, Riediger et al. (1990) correlate several known oil accumulations in the Montney Formation to be sourced by either the Doig Phosphate or the Jurassic Nordegg Formation. Regardless, both gas and oil production is ongoing in the Montney Formation, and it can be described in a variety of ways as a tight resource system with petroleum sourced internally by more organic-rich Montney Shale or by secondary migration from the overlying Doig Phosphate, or by tertiary migration from the Nordegg Formation.

Although the Doig Phosphate and Montney Shale are discussed as a shale-gas resource system, they can also produce substantial liquid petroleum depending on the location. What is interesting about the Montney Shale is the overridingly low TOC values reported, suggesting it as only a poor to fair source rock (see part 1 of this chapter). Furthermore, Riediger et al. (1990) correlate several known oil accumulations in the Montney Formation to be sourced by either the Doig Phosphate or the Jurassic Nordegg Formation. Regardless, both gas and oil production is ongoing in the Montney Formation, and it can be described in a variety of ways as a tight resource system with petroleum sourced internally by more organic-rich Montney Shale or by secondary migration from the overlying Doig Phosphate, or by tertiary migration from the Nordegg Formation.

===Paris Basin, France===

===Paris Basin, France===

[[File:M97Ch1.2FG20.jpg|thumb|300px|{{figure number|20}}The oil crossover effect in the Toarcian Shale, Paris Basin, France. Data from Espitalie et al. (1988). TOC = total organic carbon.]]

[[File:M97Ch1.2FG21.jpg|thumb|300px|{{figure number|21}}Geochemical log of the 1-Donnemarie well, Paris Basin, France. The oil crossover is apparent just below the organic-rich Toarcian Shale and also in a conventional Triassic sandstone reservoir that has been produced for about 20 yr. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

M97Ch1.2FG20.jpg|{{figure number|20}}The oil crossover effect in the Toarcian Shale, Paris Basin, France. Data from Espitalie et al. (1988). TOC = total organic carbon.

M97Ch1.2FG21.jpg|{{figure number|21}}Geochemical log of the 1-Donnemarie well, Paris Basin, France. The oil crossover is apparent just below the organic-rich Toarcian Shale and also in a conventional Triassic sandstone reservoir that has been produced for about 20 yr. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.

Recently, the Paris Basin of France is described as having shale-oil resource potential (Toreador Resources, 2010). Substantiating this, it has been recently announced that Vermillion Energy has achieved oil flow of 32 to 38deg API oil in Paris Basin Toarcian Shale (Vermillion Energy, 2010). The company reported porosity as high as 12%.

Recently, the Paris Basin of France is described as having shale-oil resource potential (Toreador Resources, 2010). Substantiating this, it has been recently announced that Vermillion Energy has achieved oil flow of 32 to 38deg API oil in Paris Basin Toarcian Shale (Vermillion Energy, 2010). The company reported porosity as high as 12%.