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However, this area of the Williston Basin was largely ignored because it was thought that it was too immature for petroleum generation and the Middle Member was too tight to serve as a conduit and reservoir for migrated hydrocarbons. Upper Bakken Shale in this area is classically characterized as immature to earliest oil window thermal maturity (%Roe from Tmax of 0.58–0.65). The lower % Roe from Tmax (0.58) is from whole rock that contains both oil and kerogen, whereas the upper value (0.65% Roe) is from extracted rock, which is only kerogen and more accurate. This also demonstrates that some oil carryover into the Rock-Eval S2 peak also exists, even in the presence of high API gravity oil. When normalized to TOC, extracted oil from S2 retained in the Bakken Shale exceeds 100 mg/g, thereby occupying most of the sorptive sites in the organic matter, meaning free oil in Rock-Eval S1 is largely movable oil.<ref name=Jetal2011>Jarvie, D. M., R. J. Coskey, M. S. Johnson, and J. E. Leonard, 2011, The geology and geochemistry of the Parshall field area, Mountrail County, North Dakota, in J. W. Robinson, J. A. LeFever, and S. B. Gaswirth, eds., The Bakken-Three Forks petroleum system in the Williston Basin: Denver, Colorado, Rocky Mountain Association of Geologists, p. 229–281.</ref> Measured Ro data were 0.40% lowered by the presence of solid bitumen and oil. Despite this low thermal maturity, the upper Bakken Shale is highly oil saturated, with OSI values averaging about 80 mg/g in the 2-36H-Parshall well, and exhibiting occasional oil crossover. This suggests earlier than expected oil generation and active expulsion. However, biomarker data of the Parshall field oils suggest a slightly higher thermal maturity for the oils of about 0.70% Roe, whereas the upper Bakken Shale extracts have biomarker-derived maturity values that are lower, approximately 0.50 to 0.60% Roe, thereby implying oil migration from more thermally mature areas of the Bakken Shale to the west of the Parshall field.

However, this area of the Williston Basin was largely ignored because it was thought that it was too immature for petroleum generation and the Middle Member was too tight to serve as a conduit and reservoir for migrated hydrocarbons. Upper Bakken Shale in this area is classically characterized as immature to earliest oil window thermal maturity (%Roe from Tmax of 0.58–0.65). The lower % Roe from Tmax (0.58) is from whole rock that contains both oil and kerogen, whereas the upper value (0.65% Roe) is from extracted rock, which is only kerogen and more accurate. This also demonstrates that some oil carryover into the Rock-Eval S2 peak also exists, even in the presence of high API gravity oil. When normalized to TOC, extracted oil from S2 retained in the Bakken Shale exceeds 100 mg/g, thereby occupying most of the sorptive sites in the organic matter, meaning free oil in Rock-Eval S1 is largely movable oil.<ref name=Jetal2011>Jarvie, D. M., R. J. Coskey, M. S. Johnson, and J. E. Leonard, 2011, The geology and geochemistry of the Parshall field area, Mountrail County, North Dakota, in J. W. Robinson, J. A. LeFever, and S. B. Gaswirth, eds., The Bakken-Three Forks petroleum system in the Williston Basin: Denver, Colorado, Rocky Mountain Association of Geologists, p. 229–281.</ref> Measured Ro data were 0.40% lowered by the presence of solid bitumen and oil. Despite this low thermal maturity, the upper Bakken Shale is highly oil saturated, with OSI values averaging about 80 mg/g in the 2-36H-Parshall well, and exhibiting occasional oil crossover. This suggests earlier than expected oil generation and active expulsion. However, biomarker data of the Parshall field oils suggest a slightly higher thermal maturity for the oils of about 0.70% Roe, whereas the upper Bakken Shale extracts have biomarker-derived maturity values that are lower, approximately 0.50 to 0.60% Roe, thereby implying oil migration from more thermally mature areas of the Bakken Shale to the west of the Parshall field.

Although biomarker data suggest migration, light hydrocarbon data (n-C6 and n-C7 and isomers) in the Bakken Shale show some geochemical traits that are similar to produced oil, suggesting that some localized upper Bakken Shale-sourced oil is being produced along with slightly more mature oil.<ref name=Jetal2011 /> In fact, the distribution of light hydrocarbons correlates closely to oils produced from Lodgepole Mound oils in Stark County, North Dakota, that are among the lowest maturity Bakken Shale-sourced oils.<ref name=Jrv2001>Jarvie, D. M., 2001, Williston Basin petroleum systems: Inferences from oil geochemistry and geology: The Mountain Geologist, v. 38, p. 19–41.</ref> The GOR values at the Parshall field are quite low, approximately 71.2 m3/m3 (400 scf/bbl), whereas nearby Sanish field oils are approximately 142.5 m3/m3 (800 scf/bbl). However, both oils are about 42deg API. The GOR values calculated from rock extract fingerprints using the oil-derived formulation of Mango and Jarvie (2001) measured on the upper Bakken Shale rock extracts average 68.4 m3/m3 (384 scf/bbl) for the Parshall field and about 155.3 m3/m3 (872 scf/bbl) for the Sanish field, agreeing with reported values for the produced oils.<ref name=Jrv2011>Jarvie, D. M., 2011, [http://www.searchanddiscovery.com/documents/2011/80131jarvie/ndx_jarvie.pdf Unconventional oil petroleum systems: Shales and shale hybrids]: AAPG International Conference and Exhibition, Calgary, Alberta, Canada, September 12–15, 2010.</ref> These data suggest a very localized source.

Although biomarker data suggest migration, light hydrocarbon data (n-C6 and n-C7 and isomers) in the Bakken Shale show some geochemical traits that are similar to produced oil, suggesting that some localized upper Bakken Shale-sourced oil is being produced along with slightly more mature oil.<ref name=Jetal2011 /> In fact, the distribution of light hydrocarbons correlates closely to oils produced from Lodgepole Mound oils in Stark County, North Dakota, that are among the lowest maturity Bakken Shale-sourced oils.<ref name=Jrv2001>Jarvie, D. M., 2001, Williston Basin petroleum systems: Inferences from oil geochemistry and geology: The Mountain Geologist, v. 38, p. 19–41.</ref> The GOR values at the Parshall field are quite low, approximately 71.2 m3/m3 (400 scf/bbl), whereas nearby Sanish field oils are approximately 142.5 m3/m3 (800 scf/bbl). However, both oils are about 42deg API. The GOR values calculated from rock extract fingerprints using the oil-derived formulation of Mango and Jarvie<ref>Mango, F. D., and D. M. Jarvie, 2001, [http://wwgeochem.com/references/MangoandJarvie2001GORfromoilcomposition.pdf GOR from oil composition (abs.)]: 20th International Meeting on Organic Geochemistry, Nancy, France, September 10–14, 2001, v. 1, p. 406–407.</ref> measured on the upper Bakken Shale rock extracts average 68.4 m3/m3 (384 scf/bbl) for the Parshall field and about 155.3 m3/m3 (872 scf/bbl) for the Sanish field, agreeing with reported values for the produced oils.<ref name=Jrv2011>Jarvie, D. M., 2011, [http://www.searchanddiscovery.com/documents/2011/80131jarvie/ndx_jarvie.pdf Unconventional oil petroleum systems: Shales and shale hybrids]: AAPG International Conference and Exhibition, Calgary, Alberta, Canada, September 12–15, 2010.</ref> These data suggest a very localized source.

Published data tables from the North Dakota Geological Survey (2008) show the oil crossover effect in samples from the Middle Bakken and Three Forks Formation (Figure 6A, B). As previously shown by Price et al.,<ref>Price, L. C., T. Ging, T. Daws, A. Love, M. Pawlewicz, and D. Anders, 1984, Organic metamorphism in the Mississippian–Devonian Bakken Shale, North Dakota portion of the Williston Basin, in J. Woodward, F. F. Meissner, and J. L. Clayton, eds., Hydrocarbon source rocks of the greater Rocky Mountain region: Denver, Colorado, Rocky Mountain Association of Geologists, p. 83–133.</ref> the reduction of hydrogen indices in the hotter parts of the basin is indicative of generation and expulsion. The whereabouts of the charge was uncertain, but the oil crossover effect in panels A and B of Figure 6 shows that a lot of oil was charged into the Middle Member and Three Forks formations. Only a few upper and lower Bakken shales show the oil crossover effect, with typical values between 20 and 70 mg oil/g TOC indicative of residual oil saturation after expulsion.

Published data tables from the North Dakota Geological Survey (2008) show the oil crossover effect in samples from the Middle Bakken and Three Forks Formation (Figure 6A, B). As previously shown by Price et al.,<ref>Price, L. C., T. Ging, T. Daws, A. Love, M. Pawlewicz, and D. Anders, 1984, Organic metamorphism in the Mississippian–Devonian Bakken Shale, North Dakota portion of the Williston Basin, in J. Woodward, F. F. Meissner, and J. L. Clayton, eds., Hydrocarbon source rocks of the greater Rocky Mountain region: Denver, Colorado, Rocky Mountain Association of Geologists, p. 83–133.</ref> the reduction of hydrogen indices in the hotter parts of the basin is indicative of generation and expulsion. The whereabouts of the charge was uncertain, but the oil crossover effect in panels A and B of Figure 6 shows that a lot of oil was charged into the Middle Member and Three Forks formations. Only a few upper and lower Bakken shales show the oil crossover effect, with typical values between 20 and 70 mg oil/g TOC indicative of residual oil saturation after expulsion.

Recent production is from the Barnett Shale itself, that is, a mudstone-dominated system with high quartz content. A critical assessment of this mudstone oil reservoir suggests that the organic-rich mudstone with high clay and quartz content and low carbonate content inhibits production of oil because of its organic richness (5–8% TOC in these areas). Storage porosity is also minimal with oil in nanopores associated with organic matter and matrix porosity.<ref name=EOGResources2010 /> Although biogenic silica yields are abundant, averaging upward of 40%, the close association of this biogenic silica with organic matter tends to inhibit flow of oil due not only to low permeability, but also the sorption of more polar components of oil to organic matter. Barnett Shale black oil tends to have a much broader range of petroleum present, as shown by Jarvie et al.,<ref>Jarvie, D. M., R. J. Hill, T. E. Ruble, and R. M. Pollastro, 2007, [http://archives.datapages.com/data/bulletns/2007/04apr/BLTN06068/BLTN06068.HTM Unconventional shale-gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment], in R. J. Hill and D. M. Jarvie, eds., AAPG Bulletin Special Issue: Barnett Shale, v. 90, no. 4, p. 475–499.</ref> so both molecular size and the presence of polar compounds in the oil, as well as minimal porosity and especially low permeability in the shale, all combine to inhibit flow from this reservoir.

Recent production is from the Barnett Shale itself, that is, a mudstone-dominated system with high quartz content. A critical assessment of this mudstone oil reservoir suggests that the organic-rich mudstone with high clay and quartz content and low carbonate content inhibits production of oil because of its organic richness (5–8% TOC in these areas). Storage porosity is also minimal with oil in nanopores associated with organic matter and matrix porosity.<ref name=EOGResources2010 /> Although biogenic silica yields are abundant, averaging upward of 40%, the close association of this biogenic silica with organic matter tends to inhibit flow of oil due not only to low permeability, but also the sorption of more polar components of oil to organic matter. Barnett Shale black oil tends to have a much broader range of petroleum present, as shown by Jarvie et al.,<ref>Jarvie, D. M., R. J. Hill, T. E. Ruble, and R. M. Pollastro, 2007, [http://archives.datapages.com/data/bulletns/2007/04apr/BLTN06068/BLTN06068.HTM Unconventional shale-gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment], in R. J. Hill and D. M. Jarvie, eds., AAPG Bulletin Special Issue: Barnett Shale, v. 90, no. 4, p. 475–499.</ref> so both molecular size and the presence of polar compounds in the oil, as well as minimal porosity and especially low permeability in the shale, all combine to inhibit flow from this reservoir.

Before the recent surge in pursuit of shale-oil resource systems, a vertical well drilled by Four Sevens Oil Co. in Clay County, northwestern Fort Worth Basin, had an initial production of about 32 m3/day (200 bbl/day) (L. Brogdon, 2008, personal communication). A geochemical log of this well shows oil crossover in the lower half of the Barnett Shale with a very low carbonate content (Figure 9). The Pennsylvanian Marble Falls lies conformably on top of the Barnett Shale, with TOC values less than 1.00% and with high carbonate contents between 50 and 75 wt. %. Compare this carbonate with that of the Middle Member of the Bakken Formation, and it is readily apparent that both the TOC and oil saturation are low. Thus, it is not just a matter of low TOC values in carbonates providing the low threshold to oil saturation as indicated by OSI, but the necessity of emplaced oil. As the TOC increases into the upper Barnett Shale, the carbonate content decreases. The average carbonate content in the Barnett Shale is 11 wt. %. From vitrinite equivalency based on a Tmax of about 0.80% Roe and HIs in the 280 mg/g range or about 35% conversion, the Barnett Shale is in the main phase of oil generation in this locale.

Before the recent surge in pursuit of shale-oil resource systems, a vertical well drilled by Four Sevens Oil Co. in Clay County, northwestern Fort Worth Basin, had an initial production of about 32 m3/day (200 bbl/day).<ref>L. Brogdon, 2008, personal communication</ref> A geochemical log of this well shows oil crossover in the lower half of the Barnett Shale with a very low carbonate content ([[:File:M97Ch1.2FG9.jpg|Figure 9]]). The Pennsylvanian Marble Falls lies conformably on top of the Barnett Shale, with TOC values less than 1.00% and with high carbonate contents between 50 and 75 wt. %. Compare this carbonate with that of the Middle Member of the Bakken Formation, and it is readily apparent that both the TOC and oil saturation are low. Thus, it is not just a matter of low TOC values in carbonates providing the low threshold to oil saturation as indicated by OSI, but the necessity of emplaced oil. As the TOC increases into the upper Barnett Shale, the carbonate content decreases. The average carbonate content in the Barnett Shale is 11 wt. %. From vitrinite equivalency based on a Tmax of about 0.80% Roe and HIs in the 280 mg/g range or about 35% conversion, the Barnett Shale is in the main phase of oil generation in this locale.

The free oil content (S1) increases in the lowermost Barnett Shale exceeding TOC and shows oil crossover, whereas the upper Barnett Shale does not. However, such oil crossover with low porosity and permeability in an organic-rich, carbonate-poor rock will not readily flow black oil. The retained oil averages about 0.0155 m3/m3 (120 bbl /ac-ft) or a computed OIP based on average oil yields (S1) of 2.36 times 106 m3/km2 (38.5 million bbl/mi2) using 500 ft (152 m) of shale thickness without any correction for evaporate and handling losses to S1 yields. Although this vertical well flowed oil, the rate declined quickly, indicative of the problem of extracting oil from a tight mudstone with a low carbonate content and no known open fractures.

The free oil content (S1) increases in the lowermost Barnett Shale exceeding TOC and shows oil crossover, whereas the upper Barnett Shale does not. However, such oil crossover with low porosity and permeability in an organic-rich, carbonate-poor rock will not readily flow black oil. The retained oil averages about 0.0155 m3/m3 (120 bbl /ac-ft) or a computed OIP based on average oil yields (S1) of 2.36 times 106 m3/km2 (38.5 million bbl/mi2) using 500 ft (152 m) of shale thickness without any correction for evaporate and handling losses to S1 yields. Although this vertical well flowed oil, the rate declined quickly, indicative of the problem of extracting oil from a tight mudstone with a low carbonate content and no known open fractures.

The presence of reasonable to high amounts of silica, in this case biogenically derived and associated with organic matter, does not impact shale-oil resource systems the way it does shale-gas resource systems at least in those successes to date. Comparison of the Bakken and Niobrara with the Barnett Shale-oil resource system oil rates and recoveries demonstrates the importance of carbonates in shale-oil resource systems.

The presence of reasonable to high amounts of silica, in this case biogenically derived and associated with organic matter, does not impact shale-oil resource systems the way it does shale-gas resource systems at least in those successes to date. Comparison of the Bakken and Niobrara with the Barnett Shale-oil resource system oil rates and recoveries demonstrates the importance of carbonates in shale-oil resource systems.

More recently, vertical wells drilled by EOG Resources have had IPs of 48, 103, 70, 159, and 72 m3/day (300, 650, 440, 1000, and 450 bbl/day) of oil flow, with gas flow of 2832, 11,327, 19,822, 56,634, and 19,822 m3/day (100, 400, 700, 2,000, and 700 mcf/day), respectively, which they refer to as their combo Barnett Shale play.<ref name=EOGResources2010 /> These wells are located in Cooke and Montague counties, Texas, in the north and northeastern areas of the Fort Worth Basin. As shown by their argon ion-milled scanning electron microscope micrographs from western Cooke County, virtually no organic porosity exists, but matrix porosity was 2 to 3%, with pore throats of 4000 to 7000 nm<ref name=EOGResources2010 /> or about 100 times greater than those found in the core gas-producing areas of the Barnett Shale. In Cooke County, northeastern Fort Worth Basin toward the Muenster arch, the Barnett Shale thickens to more than 213.4 m (700 ft) and becomes enriched in carbonate. In this area, debris flows have been inferred from core observations (Bowker, 2008). However, in western Montague County, Texas, EOG Resources reports pore throats of 4 to 50 nm, thereby making a more challenging production area despite a high quartz content and being in the oil window.

More recently, vertical wells drilled by EOG Resources have had IPs of 48, 103, 70, 159, and 72 m3/day (300, 650, 440, 1000, and 450 bbl/day) of oil flow, with gas flow of 2832, 11,327, 19,822, 56,634, and 19,822 m3/day (100, 400, 700, 2,000, and 700 mcf/day), respectively, which they refer to as their combo Barnett Shale play.<ref name=EOGResources2010 /> These wells are located in Cooke and Montague counties, Texas, in the north and northeastern areas of the Fort Worth Basin. As shown by their argon ion-milled scanning electron microscope micrographs from western Cooke County, virtually no organic porosity exists, but matrix porosity was 2 to 3%, with pore throats of 4000 to 7000 nm<ref name=EOGResources2010 /> or about 100 times greater than those found in the core gas-producing areas of the Barnett Shale. In Cooke County, northeastern Fort Worth Basin toward the Muenster arch, the Barnett Shale thickens to more than 213.4 m (700 ft) and becomes enriched in carbonate. In this area, debris flows have been inferred from core observations.<ref>Bowker, K., 2007, [http://archives.datapages.com/data/bulletns/2007/04apr/BLTN06018/BLTN06018.HTM Barnett Shale gas production, Fort Worth Basin: Issues and discussion]: AAPG Bulletin, v. 91, no. 4, p. 523–533, doi:10.1306/06190606018.</ref> However, in western Montague County, Texas, EOG Resources reports pore throats of 4 to 50 nm, thereby making a more challenging production area despite a high quartz content and being in the oil window.

EOG Resources estimates that approximately 1.11 times 107 m3 (70 million bbl) of oil and 4.96 times 109 (175 billion ft3) of gas in place per 2.59 km2 (0.9 mi2) exist in their Barnett Shale acreage in eastern Montague and western Cooke counties, Texas (Darbonne, 2010). In the best oil-producing area of the Barnett Shale, EOG's average initial production rates are 39.7 to 159.0 m3 (250–1000 bbl) of oil, 20.7 m3 (130 bbl) of gas liquids per million ft3 of gas, and 2.83–5.66 times 104 (1–2 million ft3) of gas/day. They drill both vertical and horizontal wells with 0.081 km2 (20 ac) or tighter spacing on the former as the Barnett Shale is between 213.3 and 457.2 m (700–1500 ft) thick as it approaches the Muenster arch in the northeastern part of the Fort Worth Basin.

EOG Resources estimates that approximately 1.11 times 107 m3 (70 million bbl) of oil and 4.96 times 109 (175 billion ft3) of gas in place per 2.59 km2 (0.9 mi2) exist in their Barnett Shale acreage in eastern Montague and western Cooke counties, Texas.<ref>Darbonne, N., 2010, [http://www.oilandgasinvestor.com/Headlines/2010/2/item53192.php EOG's Mark Papa: Barnett combo one of the “richest oil deposits we've ever encountered”]: Oil and Gas Investor, February 2010.</ref> In the best oil-producing area of the Barnett Shale, EOG's average initial production rates are 39.7 to 159.0 m3 (250–1000 bbl) of oil, 20.7 m3 (130 bbl) of gas liquids per million ft3 of gas, and 2.83–5.66 times 104 (1–2 million ft3) of gas/day. They drill both vertical and horizontal wells with 0.081 km2 (20 ac) or tighter spacing on the former as the Barnett Shale is between 213.3 and 457.2 m (700–1500 ft) thick as it approaches the Muenster arch in the northeastern part of the Fort Worth Basin.

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

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

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* BeMent, W. O., R. A. Levey, and F. D. Mango, 1994, The temperature of oil generation as defined with a C7 chemistry maturity parameter (2,4-DMP/2,3-DMP ratio): First Joint AAPG/AMPG Research Conference, Geological Aspects of Petroleum Systems, October 2–6, 1994, Mexico City, Mexico: http://wwgeochem.com/references/BeMentetalabstract.pdf (accessed November 12, 2010).

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