Changes

An independent geologist, Dick Findley, proposed the idea of producible oil in the Middle Member of the Bakken Formation in 1995, leading to the discovery of the giant Elm Coulee field in eastern Montana in 1996 with the first horizontal well drilled in 2000.<ref>Durham, L. S., 2009, [http://www.aapg.org/explorer/2009/08aug/findley0809.cfm Learning curve continues: Elm Coulee idea opened new play]: AAPG Explorer, August 2009.</ref> Taking Findley's idea, independent geologist Michael S. Johnson extrapolated the idea into Mountrail County, North Dakota, which is located on the eastern flank of the oil window based on various investigators.<ref>Meissner, F. F., 1978, Petroleum geology of the Bakken Formation, Williston Basin, North Dakota and Montana, in D. Estelle and R. Miller, eds., The economic geology of the Williston Basin, 1978 Williston Basin Symposium: Billings, Montana, Montana Geological Society, p. 207–230.</ref><ref>Dembicki Jr., H., and F. L. Pirkle, 1985, [http://archives.datapages.com/data/bulletns/1984-85/data/pg/0069/0004/0550/0567.htm Regional source rock mapping using a source potential rating index]: AAPG Bulletin, v. 69, no. 4, p. 567–581.</ref> Although the same facies of the Middle Member as found in Elm Coulee did not extend that far east, the Middle Member was still charged with oil as shown by the discovery well, the 1-36H-Parshall well that flowed 73.6 m3 (463 bbl/day) of 42deg API oil and 3624.5 m3/day (128 mcf/day) with a GOR of 49 m3/m3 (276 scf/bbl). The next well, the 2-36H-Parshall, flowed 140 m3 (883 bbl/day) of oil and 7079 m3 (250 mcf/day) of gas, yielding a GOR of 50.4 m3/m3 (283 scf/bbl). Recent production from Parshall and Sanish fields typically ranges from 318 to 636 m3 (2000–4000 bbl/day) using very long laterals (as much as 3044 m; ~10,000 ft).

An independent geologist, Dick Findley, proposed the idea of producible oil in the Middle Member of the Bakken Formation in 1995, leading to the discovery of the giant Elm Coulee field in eastern Montana in 1996 with the first horizontal well drilled in 2000.<ref>Durham, L. S., 2009, [http://www.aapg.org/explorer/2009/08aug/findley0809.cfm Learning curve continues: Elm Coulee idea opened new play]: AAPG Explorer, August 2009.</ref> Taking Findley's idea, independent geologist Michael S. Johnson extrapolated the idea into Mountrail County, North Dakota, which is located on the eastern flank of the oil window based on various investigators.<ref>Meissner, F. F., 1978, Petroleum geology of the Bakken Formation, Williston Basin, North Dakota and Montana, in D. Estelle and R. Miller, eds., The economic geology of the Williston Basin, 1978 Williston Basin Symposium: Billings, Montana, Montana Geological Society, p. 207–230.</ref><ref>Dembicki Jr., H., and F. L. Pirkle, 1985, [http://archives.datapages.com/data/bulletns/1984-85/data/pg/0069/0004/0550/0567.htm Regional source rock mapping using a source potential rating index]: AAPG Bulletin, v. 69, no. 4, p. 567–581.</ref> Although the same facies of the Middle Member as found in Elm Coulee did not extend that far east, the Middle Member was still charged with oil as shown by the discovery well, the 1-36H-Parshall well that flowed 73.6 m3 (463 bbl/day) of 42deg API oil and 3624.5 m3/day (128 mcf/day) with a GOR of 49 m3/m3 (276 scf/bbl). The next well, the 2-36H-Parshall, flowed 140 m3 (883 bbl/day) of oil and 7079 m3 (250 mcf/day) of gas, yielding a GOR of 50.4 m3/m3 (283 scf/bbl). Recent production from Parshall and Sanish fields typically ranges from 318 to 636 m3 (2000–4000 bbl/day) using very long laterals (as much as 3044 m; ~10,000 ft).

The Parshall field has proven to be a major field covering more than 3840 km2 (950,000 ac). The North Dakota Department of Mineral Resources projects estimated recoverable oil at 3.331 times 108 m3 (2.1 billion bbl), representing less than 1.5% of OIP (Johnson, 2009).

The Parshall field has proven to be a major field covering more than 3840 km2 (950,000 ac). The North Dakota Department of Mineral Resources projects estimated recoverable oil at 3.331 times 108 m3 (2.1 billion bbl), representing less than 1.5% of OIP.<ref>Johnson, M. S., 2009, Parshall field, North Dakota: Discovery of the year for the Rockies and beyond: Adapted from the oral presentation at AAPG Annual Convention, Denver, Colorado, June 7–10, 2009, Search and Discovery article 20081, posted September 25, 2009, 29 p.</ref>

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 (Jarvie et al., 2011). 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 (Jarvie et al., 2011). 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 (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.

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.

A geochemical log of the productive EOG Resources 1-05H NampD well in Mountrail County, North Dakota, provides insights into the Parshall field discoveries (Figure 7). This well flowed 204 m3/day (1285 bbl/day) of oil, 11,440 m3/day (404 mcf/day) of gas, and 240 m3/day (1511 bbl/day) of water. The GOR was 55.9 m3/m3 (314 scf/bbl). The GOR values from cuttings have a calculated GOR of 84.2 m3/m3 (473 scf/bbl), indicating sufficient maturity in the upper Bakken Shale to have generated these oils (Jarvie et al., 2011).

A geochemical log of the productive EOG Resources 1-05H NampD well in Mountrail County, North Dakota, provides insights into the Parshall field discoveries (Figure 7). This well flowed 204 m3/day (1285 bbl/day) of oil, 11,440 m3/day (404 mcf/day) of gas, and 240 m3/day (1511 bbl/day) of water. The GOR was 55.9 m3/m3 (314 scf/bbl). The GOR values from cuttings have a calculated GOR of 84.2 m3/m3 (473 scf/bbl), indicating sufficient maturity in the upper Bakken Shale to have generated these oils.<ref name=Jetal2011 />

The TOC values are high in the upper Bakken Shale, averaging 14.3%, with values ranging between 5.36 and 21.40%, and they are just slightly higher in the lower Bakken Shale at 15.17%, with a range from 8.87 to 24.7%. Carbonate contents in the upper and lower Bakken Shale average 10 and 6%, respectively. The carbonate-rich Scallion above the upper Bakken Shale and Middle Member are readily recognizable, with their high carbonate and low TOC contents. Similar results are found in the Three Forks Formation underlying the lower Bakken Shale. The carbonate content in the Middle Member of the Bakken Formation is primarily dolomite and averages approximately 38%, with a range between 21 and 70%.

The TOC values are high in the upper Bakken Shale, averaging 14.3%, with values ranging between 5.36 and 21.40%, and they are just slightly higher in the lower Bakken Shale at 15.17%, with a range from 8.87 to 24.7%. Carbonate contents in the upper and lower Bakken Shale average 10 and 6%, respectively. The carbonate-rich Scallion above the upper Bakken Shale and Middle Member are readily recognizable, with their high carbonate and low TOC contents. Similar results are found in the Three Forks Formation underlying the lower Bakken Shale. The carbonate content in the Middle Member of the Bakken Formation is primarily dolomite and averages approximately 38%, with a range between 21 and 70%.

Continuous oil crossover is present in both the Scallion and Middle Member, with the Middle Member being the principal reservoir that is now drilled horizontally. Although a particular zone in the Middle Member, for example, the B zone (e.g., Oil amp Gas Journal, 2010c), is preferred by operators, the entire Middle Member is highly oil saturated. Absolute oil contents average about 0.00747 m3/m3 (58 bbl/ac-ft) in the Middle Member, whereas the Scallion has a much lower average of 0.00141 m3/m3 (11 bbl/ac-ft). Both of these values are based on absolute oil (S1) yields, and based on a comparison of rock extracts with produced oil, a substantial loss of hydrocarbons is evident in the rock extracts, with minimal C15- measured by gas chromatography (Jarvie et al., 2011). The upper Bakken Shale has a fingerprint nearly identical to the oil, whereas the Middle Member fingerprint looks like a topped (evaporated) oil (Jarvie et al., 2011). This illustrates an important difference between the organic-rich shales and the carbonates, as all samples were core chips taken at the same time. The organic-rich shale retains even light hydrocarbons from C5 to C10, whereas the organic-lean carbonate appears as a C15+ extract fingerprint with loss of light ends. The difference is not primarily caused by permeability differences, but retention (sorption) by the organic-rich mudstones of the Bakken shales. Although the Bakken Shale-oil yields (S1) are much higher than the Scallion and Middle Member free oil contents due to much evaporative loss, only a part of the oil in the shale would be producible, i.e., only excess oil exceeding the adsorption index (AI).

Continuous oil crossover is present in both the Scallion and Middle Member, with the Middle Member being the principal reservoir that is now drilled horizontally. Although a particular zone in the Middle Member, for example, the B zone (e.g., Oil amp Gas Journal, 2010c), is preferred by operators, the entire Middle Member is highly oil saturated. Absolute oil contents average about 0.00747 m3/m3 (58 bbl/ac-ft) in the Middle Member, whereas the Scallion has a much lower average of 0.00141 m3/m3 (11 bbl/ac-ft). Both of these values are based on absolute oil (S1) yields, and based on a comparison of rock extracts with produced oil, a substantial loss of hydrocarbons is evident in the rock extracts, with minimal C15- measured by gas chromatography.<ref name=Jetal2011 /> The upper Bakken Shale has a fingerprint nearly identical to the oil, whereas the Middle Member fingerprint looks like a topped (evaporated) oil.<ref name=Jetal2011 /> This illustrates an important difference between the organic-rich shales and the carbonates, as all samples were core chips taken at the same time. The organic-rich shale retains even light hydrocarbons from C5 to C10, whereas the organic-lean carbonate appears as a C15+ extract fingerprint with loss of light ends. The difference is not primarily caused by permeability differences, but retention (sorption) by the organic-rich mudstones of the Bakken shales. Although the Bakken Shale-oil yields (S1) are much higher than the Scallion and Middle Member free oil contents due to much evaporative loss, only a part of the oil in the shale would be producible, i.e., only excess oil exceeding the adsorption index (AI).

In addition, the high remaining generation potentials (Rock-Eval S2) in the Scallion and Middle Member are not kerogen content, but instead oil that has carried over into the pyrolysis (S2) yield. This is also noted by the lower equivalent Ro values in the Scallion and Middle Member data. Addition of this carryover oil to the free oil gives the total oil.

In addition, the high remaining generation potentials (Rock-Eval S2) in the Scallion and Middle Member are not kerogen content, but instead oil that has carried over into the pyrolysis (S2) yield. This is also noted by the lower equivalent Ro values in the Scallion and Middle Member data. Addition of this carryover oil to the free oil gives the total oil.

The Bakken shales have intermittent oil crossover indicative of active generation and expulsion. Extracts of the Bakken Shale yield CTemp values (BeMent et al., 1994; Mango, 1997) of about 105degC (221degF), suggesting generation at lower than expected temperatures indicative of labile organofacies (Jarvie et al., 2011). Other compositional kinetic data on the Bakken Shale suggests that one organofacies of the Bakken Shale can generate oil at lower thermal maturity and relates to Tmax values just above 420degC (788degF) with 10% conversion at a Tmax of 427degC (801degF).<ref>Jarvie, D. M., R. J. Elsinger, and R. F. Inden, 1996, A comparison of the rates of hydrocarbon generation, from Lodgepole, False Bakken, and Bakken Formation petroleum source rocks, Williston Basin: 1996 Rocky Mountain Section Meeting, AAPG, Billings, Montana, p. 153–158.</ref>

The Bakken shales have intermittent oil crossover indicative of active generation and expulsion. Extracts of the Bakken Shale yield CTemp values (BeMent et al., 1994; Mango, 1997) of about 105degC (221degF), suggesting generation at lower than expected temperatures indicative of labile organofacies.<ref name=Jetal2011 /> Other compositional kinetic data on the Bakken Shale suggests that one organofacies of the Bakken Shale can generate oil at lower thermal maturity and relates to Tmax values just above 420degC (788degF) with 10% conversion at a Tmax of 427degC (801degF).<ref>Jarvie, D. M., R. J. Elsinger, and R. F. Inden, 1996, A comparison of the rates of hydrocarbon generation, from Lodgepole, False Bakken, and Bakken Formation petroleum source rocks, Williston Basin: 1996 Rocky Mountain Section Meeting, AAPG, Billings, Montana, p. 153–158.</ref>

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

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

Most of the Barnett Shale oil has been recovered in vertical wells in the oil window parts of the basin, that is, western and northern parts of the Fort Worth Basin. The Barnett Shale is thinner in the west but thickens toward the northeast and is less mature in both locations, with vitrinite reflectance values of about 0.60% Roe in Brown County in the far southwestern part of the basin and about 0.85% Roe in the north-northeastern parts of the basin, for example, Clay, Montague, and Cooke counties, Texas. Oil produced from a well in the southwest, the Explo Oil 3-Mitcham, yielded a 36deg API from the Barnett Shale at 0.60% Roe. Typical of marine shale source rocks, oils are 35deg API and higher, even at low thermal maturities.

Most of the Barnett Shale oil has been recovered in vertical wells in the oil window parts of the basin, that is, western and northern parts of the Fort Worth Basin. The Barnett Shale is thinner in the west but thickens toward the northeast and is less mature in both locations, with vitrinite reflectance values of about 0.60% Roe in Brown County in the far southwestern part of the basin and about 0.85% Roe in the north-northeastern parts of the basin, for example, Clay, Montague, and Cooke counties, Texas. Oil produced from a well in the southwest, the Explo Oil 3-Mitcham, yielded a 36deg API from the Barnett Shale at 0.60% Roe. Typical of marine shale source rocks, oils are 35deg API and higher, even at low thermal maturities.

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. (2007), 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) (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.

* IHS Energy News on Demand, 2010, Details reported on horizontal discovery in Power River Basin, March 16, 2010, press release.

* IHS Energy News on Demand, 2010, Details reported on horizontal discovery in Power River Basin, March 16, 2010, press release.

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* John, C., B. L. Jones, J. E. Moncrief, R. Bourgeois, and B. J. Harder, 1997, An unproven unconventional seven-billion barrel oil resource: The Tuscaloosa Marine Shale: http://www.lgs.lsu.edu/deploy/uploads/Tuscaloosa%20Marine%20Shale.pdf (accessed November 12, 2010).

* John, C., B. L. Jones, J. E. Moncrief, R. Bourgeois, and B. J. Harder, 1997, An unproven unconventional seven-billion barrel oil resource: The Tuscaloosa Marine Shale: http://www.lgs.lsu.edu/deploy/uploads/Tuscaloosa%20Marine%20Shale.pdf (accessed November 12, 2010).

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* Mango, F. D., 1997, The light hydrocarbons in petroleum: A critical review: Organic Geochemistry, v. 26, no. 7/8, p. 417–440.

* Mango, F. D., 1997, The light hydrocarbons in petroleum: A critical review: Organic Geochemistry, v. 26, no. 7/8, p. 417–440.