Changes

Producible oil from shales or closely associated organic-lean intraformational lithofacies such as carbonates is referred to as a shale-oil resource system. Organic-rich mudstones, calcareous mudstones, or argillaceous lime mudstones are typically both the source for the petroleum and either a primary or secondary reservoir target, but optimum production can be derived from organic-lean juxtaposed carbonates, silts, or sands. Where organic-rich and organic-lean intervals are juxtaposed, the term hybrid shale-oil resource system is applied.

Producible oil from shales or closely associated organic-lean intraformational lithofacies such as carbonates is referred to as a shale-oil resource system. Organic-rich mudstones, calcareous mudstones, or argillaceous lime mudstones are typically both the source for the petroleum and either a primary or secondary reservoir target, but optimum production can be derived from organic-lean juxtaposed carbonates, silts, or sands. Where organic-rich and organic-lean intervals are juxtaposed, the term hybrid shale-oil resource system is applied.

These systems are classified as (1) organic-rich mudstones without open fractures, (2) organic-rich mudstones with open fractures, and (3) hybrid systems that have juxtaposed, continuous organic-rich and organic-lean intervals (Figure 1). For example, the Bakken Formation production is accounted for by both open-fractured shale (e.g., Bicentennial field) and hybrid shale (e.g., Elm Coulee, Sanish, and Parshall fields), where organic-rich shales are juxtaposed to organic-lean intervals, such as the Middle Member (dolomitic sand) and Three Forks (carbonate). However, Barnett Shale oil is almost always from a tight mudstone with some related matrix porosity (EOG Resources, 2010). Monterey Shale-oil production is primarily from open-fractured shale in tectonically active areas of California. Various shale-oil resource systems are classified based on available data in Table 1. To suggest that these types are mutually exclusive is also incorrect because there can be a significant overlap in a single shale-oil resource system.

These systems are classified as (1) organic-rich mudstones without open fractures, (2) organic-rich mudstones with open fractures, and (3) hybrid systems that have juxtaposed, continuous organic-rich and organic-lean intervals ([[:File:M97Ch1.2FG1.jpg|Figure 1]]). For example, the Bakken Formation production is accounted for by both open-fractured shale (e.g., Bicentennial field) and hybrid shale (e.g., Elm Coulee, Sanish, and Parshall fields), where organic-rich shales are juxtaposed to organic-lean intervals, such as the Middle Member (dolomitic sand) and Three Forks (carbonate). However, Barnett Shale oil is almost always from a tight mudstone with some related matrix porosity (EOG Resources, 2010). Monterey Shale-oil production is primarily from open-fractured shale in tectonically active areas of California. Various shale-oil resource systems are classified based on available data in Table 1. To suggest that these types are mutually exclusive is also incorrect because there can be a significant overlap in a single shale-oil resource system.

[[File:M97Ch1.2FG1.jpg|thumb|300px|FIGURE 1. Shale-oil resource systems. A simple classification scheme includes continuous (1) organic-rich mudstones with no open fractures (tight shale), (2) organic-rich mudstones with open fractures (fractured shale), and (3) organic-rich mudstones with juxtaposed organic-lean facies (hybrid shale).]]

[[File:M97Ch1.2FG1.jpg|thumb|500px|{{figure number|1}}Shale-oil resource systems. A simple classification scheme includes continuous (1) organic-rich mudstones with no open fractures (tight shale), (2) organic-rich mudstones with open fractures (fractured shale), and (3) organic-rich mudstones with juxtaposed organic-lean facies (hybrid shale).]]

Although shale-oil plays with oil stored in open-fractured shale have been pursued for more than 100 yr, organic-rich and low-permeability shales and hybrid shale-oil systems are now being pursued based on knowledge and technologies gained from production of shale-gas resource systems and likely hold the largest untapped oil resource potential. Whereas fractured and hybrid shale-oil systems have the highest productivity to date, organic-rich tight shales are the most difficult to obtain high oil flow rates because of ultra-low permeability, typically high clay and low carbonate contents, and organic richness whereby adsorption plays a role in retention of petroleum.

Although shale-oil plays with oil stored in open-fractured shale have been pursued for more than 100 yr, organic-rich and low-permeability shales and hybrid shale-oil systems are now being pursued based on knowledge and technologies gained from production of shale-gas resource systems and likely hold the largest untapped oil resource potential. Whereas fractured and hybrid shale-oil systems have the highest productivity to date, organic-rich tight shales are the most difficult to obtain high oil flow rates because of ultra-low permeability, typically high clay and low carbonate contents, and organic richness whereby adsorption plays a role in retention of petroleum.

==Oil crossover effect==

==Oil crossover effect==

A geochemical indication of potentially producible oil is indicated by the oil crossover effect, that is, the crossover of oil content, either Rock-Eval S1 or EOM relative to organic richness (TOC, absolute values), or when the oil saturation index (OSI) (S1 times 100/TOC) reaches a value of about 100 mg hydrocarbons (HC)/g TOC. This is illustrated by graphic results describing Upper Jurassic Bazhenov Shale open-fractured shale-oil production. These data values are derived from the graphic of Lopatin et al. (2003) for Bazhenov shales in the 11-18-Maslikhov well, and they clearly show the oil crossover effect and the productive intervals (Figure 2). Such high crossover in an organic-rich shale is indicative of an open-fracture network.

A geochemical indication of potentially producible oil is indicated by the oil crossover effect, that is, the crossover of oil content, either Rock-Eval S1 or EOM relative to organic richness (TOC, absolute values), or when the oil saturation index (OSI) (S1 times 100/TOC) reaches a value of about 100 mg hydrocarbons (HC)/g TOC. This is illustrated by graphic results describing Upper Jurassic Bazhenov Shale open-fractured shale-oil production. These data values are derived from the graphic of Lopatin et al. (2003) for Bazhenov shales in the 11-18-Maslikhov well, and they clearly show the oil crossover effect and the productive intervals (Figure 2). Such high crossover in an organic-rich shale is indicative of an open-fracture network.

Rock-Eval S1 or EOM yields alone have little meaning in assessing potential production because they do not account for the organic background. For example, coals might have an S1 value of 10 mg HC/g rock, but with a TOC of 50% or higher, the OSI is quite low, indicative of low oil saturation with a high expulsion or production threshold.

Rock-Eval S1 or EOM yields alone have little meaning in assessing potential production because they do not account for the organic background. For example, coals might have an S1 value of 10 mg HC/g rock, but with a TOC of 50% or higher, the OSI is quite low, indicative of low oil saturation with a high expulsion or production threshold.

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

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

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).

A geochemical log of this well demonstrates oil crossover in the 1371.6 to 1417.3 m (4500–4650 ft) interval (Figure 3). These results are from cuttings of this well that were archived and reanalyzed in 2010. The relatively high values for OSI suggest open fractures in the shale. The TOC values average about 2.2% with less than 25% carbonate. A deeper zone from 1493.5 to 1569.7 m (4900–5150 ft) shows a very high oil content but very little oil crossover and was not perforated. However, it would likely have flowed oil, although the rate would have been low, depending on oil quality. Whereas free oil yields (S1) are high (as much as 0.0108 m3/m3 or 80 bbl/ac-ft), there is also a very high remaining generation potential (S2) indicative of low thermal maturity, although some of this is likely extractable organic matter (EOM) carryover given the low API gravity of the oil. Thus, the total oil content is higher, and the S2 and HI are lower; extraction and reanalysis would provide the total oil yield. For example, data on whole rock and extracted rock from the Getty 163-Los Alamos well, Santa Maria Basin onshore, demonstrate that only 15–30% of the oil is found in Rock-Eval S1, whereas the bulk is found in Rock-Eval S2. This carryover effect is a function of oil quality, especially API gravity, but also the lithofacies.

A geochemical log of this well demonstrates oil crossover in the 1371.6 to 1417.3 m (4500–4650 ft) interval (Figure 3). These results are from cuttings of this well that were archived and reanalyzed in 2010. The relatively high values for OSI suggest open fractures in the shale. The TOC values average about 2.2% with less than 25% carbonate. A deeper zone from 1493.5 to 1569.7 m (4900–5150 ft) shows a very high oil content but very little oil crossover and was not perforated. However, it would likely have flowed oil, although the rate would have been low, depending on oil quality. Whereas free oil yields (S1) are high (as much as 0.0108 m3/m3 or 80 bbl/ac-ft), there is also a very high remaining generation potential (S2) indicative of low thermal maturity, although some of this is likely extractable organic matter (EOM) carryover given the low API gravity of the oil. Thus, the total oil content is higher, and the S2 and HI are lower; extraction and reanalysis would provide the total oil yield. For example, data on whole rock and extracted rock from the Getty 163-Los Alamos well, Santa Maria Basin onshore, demonstrate that only 15–30% of the oil is found in Rock-Eval S1, whereas the bulk is found in Rock-Eval S2. This carryover effect is a function of oil quality, especially API gravity, but also the lithofacies.

Other examples of open-fractured shale-oil production include the Niobrara, Pierre (U.S. Geological Survey, 2003), Upper Bakken shale-oil systems (North Dakota Geological Survey, 2010), and the West Siberian Jurassic Bazhenov Shale (Lopatin et al., 2003).

Other examples of open-fractured shale-oil production include the Niobrara, Pierre (U.S. Geological Survey, 2003), Upper Bakken shale-oil systems (North Dakota Geological Survey, 2010), and the West Siberian Jurassic Bazhenov Shale (Lopatin et al., 2003).

A second Monterey Shale example is a deep Monterey Shale well drilled by Coastal Oil amp Gas in a synclinal part of the onshore Santa Maria Basin. The Coastal Oil amp Gas (OampG) Corp. 3-Hunter-Careaga well, Careaga Canyon field, flowed 53.9 m3/day (339 bbl/day) of 33deg API oil with 1.85 times 104 m3/day (653 mcf/day) of gas and 15 m3/day (95 bbl) of formation water from the Monterey Shale (scout ticket). It had a reported GOR of 343 m3/m3 (1926 scf/bbl). The well was perforated over numerous intervals from 2740 to 3711 m (8990–12,175 ft) with a maximum flow of 8.2 m3/day (516 bbl/day) and 2.20 times 104 m3/day (778 mcf/day). A geochemical log of this well illustrates its much higher thermal maturity, explaining the high GOR for a Monterey Shale well (Figure 4). The TOC values are variable, ranging from just under 3.00% to less than 0.50%. The highest oil crossover tends to occur where TOC values are lowest, suggesting variable lithofacies, but not open fractures as the oil crossover is marginal, reaching about 100 mg/g (average, 94 mg/g) in the 2793 to 3048 m (9165 to 10,000 ft) interval, with isolated exceptions over 100 mg/g at 3269 to 3305 m (10,725–10,845 ft) and 3580 to 3616 m (11,745–11,865 ft). Based on these data, the optimum interval for landing a horizontal would be in the 2903 to 2940 m (9525 to 9645 ft) zone, although multiple zones with OSI greater than 100 would flow oil. Additional oil likely exists in the pyrolysis (S2) peak because low TOC samples have substantial pyrolysis yields with some of the highest HI values, again indicative of oil carryover into the pyrolysis yield. Thermal maturity, as indicated by vitrinite reflectance equivalency (Roe) from Tmax, suggests maturity values spanning the entire oil window with the early oil window at 2743.2 m (9000 ft) and latest oil window at 3657.6 m (12,000 ft).

A second Monterey Shale example is a deep Monterey Shale well drilled by Coastal Oil amp Gas in a synclinal part of the onshore Santa Maria Basin. The Coastal Oil amp Gas (OampG) Corp. 3-Hunter-Careaga well, Careaga Canyon field, flowed 53.9 m3/day (339 bbl/day) of 33deg API oil with 1.85 times 104 m3/day (653 mcf/day) of gas and 15 m3/day (95 bbl) of formation water from the Monterey Shale (scout ticket). It had a reported GOR of 343 m3/m3 (1926 scf/bbl). The well was perforated over numerous intervals from 2740 to 3711 m (8990–12,175 ft) with a maximum flow of 8.2 m3/day (516 bbl/day) and 2.20 times 104 m3/day (778 mcf/day). A geochemical log of this well illustrates its much higher thermal maturity, explaining the high GOR for a Monterey Shale well (Figure 4). The TOC values are variable, ranging from just under 3.00% to less than 0.50%. The highest oil crossover tends to occur where TOC values are lowest, suggesting variable lithofacies, but not open fractures as the oil crossover is marginal, reaching about 100 mg/g (average, 94 mg/g) in the 2793 to 3048 m (9165 to 10,000 ft) interval, with isolated exceptions over 100 mg/g at 3269 to 3305 m (10,725–10,845 ft) and 3580 to 3616 m (11,745–11,865 ft). Based on these data, the optimum interval for landing a horizontal would be in the 2903 to 2940 m (9525 to 9645 ft) zone, although multiple zones with OSI greater than 100 would flow oil. Additional oil likely exists in the pyrolysis (S2) peak because low TOC samples have substantial pyrolysis yields with some of the highest HI values, again indicative of oil carryover into the pyrolysis yield. Thermal maturity, as indicated by vitrinite reflectance equivalency (Roe) from Tmax, suggests maturity values spanning the entire oil window with the early oil window at 2743.2 m (9000 ft) and latest oil window at 3657.6 m (12,000 ft).

This well was perforated over the entire Monterey Shale interval and did produce during a 5 yr period 2.60 times 104 m3 (163,603 bbl) of oil, 6.369 times 106 m3 (224,936 mcf) of gas, and 1.39 times 105 m3 (872,175 bbl) of formation water with the water cut increasing greatly in year 5 when the well was shut in.

This well was perforated over the entire Monterey Shale interval and did produce during a 5 yr period 2.60 times 104 m3 (163,603 bbl) of oil, 6.369 times 106 m3 (224,936 mcf) of gas, and 1.39 times 105 m3 (872,175 bbl) of formation water with the water cut increasing greatly in year 5 when the well was shut in.

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

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

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.

A geochemical log of this well shows OSI gt 100 mg hydrocarbons/g TOC in the Antelope Shale over a broad interval from 1815 to 1998 m (5955–6555 ft) (Figure 5). Although a broader interval was perforated, the bulk of the producible oil appears to be located in the interval where oil crossover occurs. This would be the zone to target for perforation or landing a horizontal well. Oil crossover also exists in the Reef Ridge Formation.

A geochemical log of this well shows OSI gt 100 mg hydrocarbons/g TOC in the Antelope Shale over a broad interval from 1815 to 1998 m (5955–6555 ft) (Figure 5). Although a broader interval was perforated, the bulk of the producible oil appears to be located in the interval where oil crossover occurs. This would be the zone to target for perforation or landing a horizontal well. Oil crossover also exists in the Reef Ridge Formation.

Potentially recoverable oil is still in the range of 0.0116 m3/m3 (90 bbl/ac-ft) or 2.09 times 106 m3/km2 (34 million bbl/mi2). The OIP value is estimated to average approximately 2.93 times 107 m3/km2 (184 million bbl/mi2) based on total oil yields from Rock-Eval data. This is not corrected upward for any potential hydrocarbon losses caused by evaporation and sample handling.

Potentially recoverable oil is still in the range of 0.0116 m3/m3 (90 bbl/ac-ft) or 2.09 times 106 m3/km2 (34 million bbl/mi2). The OIP value is estimated to average approximately 2.93 times 107 m3/km2 (184 million bbl/mi2) based on total oil yields from Rock-Eval data. This is not corrected upward for any potential hydrocarbon losses caused by evaporation and sample handling.

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

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

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).

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. (1984), 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. (1984), 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 (Jarvie et al., 2011).

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%.

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

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

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.

Data from core chips of the Golden Buckeye Petroleum 2-Gill Land Associates well demonstrate this vastly different TOC content (Tanck, 1997) (Figure 8). This well flowed 20.7 m3 (130 bbl/day) of oil and 7220.8 m3 (255 mcf/day) of gas, with only 1.11 m3 (7 bbl/day) of water from the Niobrara B interval. The GOR is reported at 308.1 m3/m3 (1730 scf/bbl). The thesis by Tanck (1997) did not include carbonate carbon data, although calcite content is reported to be 84% at 2066.2 m (6779 ft). The productive Niobrara B is found in the 2054.3 to 2065.0 m (6740 to 6775 ft) interval, where oil crossover exists (Figure 8). Oil saturations range from 63 to 80% of pore volume, with porosities of approximately 5 to 6% in this interval (Tanck, 1997). A deeper zone at 2075.7 to 2080.3 m (6810–6825 ft) has similarly high oil saturations, but much lower porosities in the 3 to 4% range (Tanck, 1997).

Data from core chips of the Golden Buckeye Petroleum 2-Gill Land Associates well demonstrate this vastly different TOC content (Tanck, 1997) (Figure 8). This well flowed 20.7 m3 (130 bbl/day) of oil and 7220.8 m3 (255 mcf/day) of gas, with only 1.11 m3 (7 bbl/day) of water from the Niobrara B interval. The GOR is reported at 308.1 m3/m3 (1730 scf/bbl). The thesis by Tanck (1997) did not include carbonate carbon data, although calcite content is reported to be 84% at 2066.2 m (6779 ft). The productive Niobrara B is found in the 2054.3 to 2065.0 m (6740 to 6775 ft) interval, where oil crossover exists (Figure 8). Oil saturations range from 63 to 80% of pore volume, with porosities of approximately 5 to 6% in this interval (Tanck, 1997). A deeper zone at 2075.7 to 2080.3 m (6810–6825 ft) has similarly high oil saturations, but much lower porosities in the 3 to 4% range (Tanck, 1997).

The shale intervals are more organic rich and have higher oil contents indicative of source rocks that have generated hydrocarbons. In general, however, the higher the TOC, the lower is the oil crossover. Porosities are also lower in the shale, typically in the range of 2 to 3% (Tanck, 1997).

The shale intervals are more organic rich and have higher oil contents indicative of source rocks that have generated hydrocarbons. In general, however, the higher the TOC, the lower is the oil crossover. Porosities are also lower in the shale, typically in the range of 2 to 3% (Tanck, 1997).

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

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

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).

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.

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.

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

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

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).

A geochemical database of Eagle Ford Shale demonstrates that many samples show oil crossover (Jarvie, 2007) (Figure 10). A geochemical log of the Champlin Petroleum Co. 1-Mixon well in De Witt County, Texas, illustrates what is commonly seen in wells along the Austin Chalk trend (Figure 11). This mudstone shale-gas/shale-oil resource system contains about 60% carbonate content on average. Thus, the Eagle Ford may be more aptly described as a calcareous shale or argillaceous lime mudstone (J. A. Breyer, 2010, personal communication). The lean TOC interval from 2475 to 2510 m (8120–8235 ft) is the Austin Chalk, which shows intermittent oil crossover. The Austin Chalk is productive along this trend, and such productive zones are readily identifiable by the oil crossover effect. The Eagle Ford Shale is present below 2511.5 m (8240 ft), and the TOC increases to a high of just less than 6.00%, with carbonate contents remaining very high. Intermittent, but consistent, oil crossover occurs in various intervals of this well, for example, 2523.7 to 2542.0 m (8280–8340 ft) and especially 2546.6 to 2572.5 m (8355–8440 ft). This geochemical log is typical of almost all wells along this trend that are in the oil or early wet gas window.

A geochemical database of Eagle Ford Shale demonstrates that many samples show oil crossover (Jarvie, 2007) (Figure 10). A geochemical log of the Champlin Petroleum Co. 1-Mixon well in De Witt County, Texas, illustrates what is commonly seen in wells along the Austin Chalk trend (Figure 11). This mudstone shale-gas/shale-oil resource system contains about 60% carbonate content on average. Thus, the Eagle Ford may be more aptly described as a calcareous shale or argillaceous lime mudstone (J. A. Breyer, 2010, personal communication). The lean TOC interval from 2475 to 2510 m (8120–8235 ft) is the Austin Chalk, which shows intermittent oil crossover. The Austin Chalk is productive along this trend, and such productive zones are readily identifiable by the oil crossover effect. The Eagle Ford Shale is present below 2511.5 m (8240 ft), and the TOC increases to a high of just less than 6.00%, with carbonate contents remaining very high. Intermittent, but consistent, oil crossover occurs in various intervals of this well, for example, 2523.7 to 2542.0 m (8280–8340 ft) and especially 2546.6 to 2572.5 m (8355–8440 ft). This geochemical log is typical of almost all wells along this trend that are in the oil or early wet gas window.

Some oil carryover into the remaining generation potential (Rock-Eval S2 peak) likely occurs but not sufficient to affect Tmax to any substantial amount. The Tmax values range from 440 to 450degC (824 to 842degF) (or sim0.75 to 0.95% Roe), placing the Eagle Ford Shale in this well in the peak oil-generation window.

Some oil carryover into the remaining generation potential (Rock-Eval S2 peak) likely occurs but not sufficient to affect Tmax to any substantial amount. The Tmax values range from 440 to 450degC (824 to 842degF) (or sim0.75 to 0.95% Roe), placing the Eagle Ford Shale in this well in the peak oil-generation window.

In the Barnett Shale, as TOC increases, carbonate carbon content generally decreases (Figure 12). However, the Lower Cretaceous Eagle Ford Shale shows no particular trend, with high TOC Eagle Ford Shale samples having ample carbonate content in this data set ranging from about 30 to 70%, whereas organic-lean intervals show both high and very low carbonate contents.

In the Barnett Shale, as TOC increases, carbonate carbon content generally decreases (Figure 12). However, the Lower Cretaceous Eagle Ford Shale shows no particular trend, with high TOC Eagle Ford Shale samples having ample carbonate content in this data set ranging from about 30 to 70%, whereas organic-lean intervals show both high and very low carbonate contents.

The Eagle Ford Shale-oil resource system may be an ideal case to study the impact of CO2 and organic acid generation because of the intimate association of carbonates with organic matter.

The Eagle Ford Shale-oil resource system may be an ideal case to study the impact of CO2 and organic acid generation because of the intimate association of carbonates with organic matter.

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

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

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

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

In the Powder River Basin, there has been success in producing oil from the Lower Cretaceous Mowry Shale (IHS Energy News on Demand, 2010). The EOG Resources 1-16H-Trans Am well was reported to have flowed 3.2 m3/day (20 bbl/day) of oil, 8.5 times 104 m3/day (30,000 ft3/day) of gas, and 51.7 m3/day (325 bbl/day) of water (IHS Energy News on Demand, 2010). After 6 months of production, the well had produced 1023 m3/day (6436 bbl/day) of oil, 4.02 times 105 m3/day (14.2 million ft3/day) of gas, and 310.5 m3/day (1953 bbl/day) of water. The horizontal length was about 1167.08 m (3829 ft) with 14 hydraulic fracturing stages completed. Stimulation of various zones ranged from 3.18 times 102 to 3.18 times 103 m3 (2000–20,000 bbl) of slick water, with about 2.1772 times 104 to 1.81437 times 105 kg (48,000–400,000 lb) of 841/420 mum (20/40 mesh) and 149 mum (100 mesh) sand (scout ticket). The Mowry Shale is at about 2621.28 m (8600 ft) in this area.

In the Powder River Basin, there has been success in producing oil from the Lower Cretaceous Mowry Shale (IHS Energy News on Demand, 2010). The EOG Resources 1-16H-Trans Am well was reported to have flowed 3.2 m3/day (20 bbl/day) of oil, 8.5 times 104 m3/day (30,000 ft3/day) of gas, and 51.7 m3/day (325 bbl/day) of water (IHS Energy News on Demand, 2010). After 6 months of production, the well had produced 1023 m3/day (6436 bbl/day) of oil, 4.02 times 105 m3/day (14.2 million ft3/day) of gas, and 310.5 m3/day (1953 bbl/day) of water. The horizontal length was about 1167.08 m (3829 ft) with 14 hydraulic fracturing stages completed. Stimulation of various zones ranged from 3.18 times 102 to 3.18 times 103 m3 (2000–20,000 bbl) of slick water, with about 2.1772 times 104 to 1.81437 times 105 kg (48,000–400,000 lb) of 841/420 mum (20/40 mesh) and 149 mum (100 mesh) sand (scout ticket). The Mowry Shale is at about 2621.28 m (8600 ft) in this area.

A geochemical log of the Home Petroleum 2-Phoenix Unit in Johnson County, Wyoming, shows oil crossover in the Mowry Shale at 3478.51 m (11,412.4 ft) (Figure 13). The oil yield is reasonably high in this interval of 17.7 m (58 ft). This computes to about 2.385 times 105 m3/2.589988 km2 (1,500,000 bbl/mi2) using unadjusted S1 values.

A geochemical log of the Home Petroleum 2-Phoenix Unit in Johnson County, Wyoming, shows oil crossover in the Mowry Shale at 3478.51 m (11,412.4 ft) (Figure 13). The oil yield is reasonably high in this interval of 17.7 m (58 ft). This computes to about 2.385 times 105 m3/2.589988 km2 (1,500,000 bbl/mi2) using unadjusted S1 values.

[[File:M97Ch1.2FG13.jpg|thumb|300px|FIGURE 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:M97Ch1.2FG14.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.]]

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.

Oil crossover is apparent in the Mowry Shale and Muddy Formation at 3753.6 m (12,315 ft) and 3799.3 to 3826.7 m (12,465–12,555 ft).

Oil crossover is apparent in the Mowry Shale and Muddy Formation at 3753.6 m (12,315 ft) and 3799.3 to 3826.7 m (12,465–12,555 ft).

====Paradox Basin====

====Paradox Basin====

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).

An example of the Pennsylvanian Cane Creek section is provided by a geochemical log of the Mobil Oil Corp. 12-3-Jakeys Ridge well (Figure 15). These data illustrate the high organic carbon content throughout this 755.9 m (5760.81 ft) interval of the Cane Creek Shale, with an overall average of 7.67%. However, four distinct intervals are present, with average TOC values over the uppermost interval of 67 m (219.81 ft) with 1.34%, 146.3 m (479.98 ft) of 4.91%, 231.7 m (701.11 ft) of 13.49%, and 42.7 m (140.09 ft) of 6.61%. Although extremely high oil contents (S1) are present in the organic-rich interval, the values only exceed 100 mg/g at 2315.5 m (7596.76 ft), whereas the uppermost lean zone in this well has the highest OSI values averaging 120 mg/g over 67 m (219.81 ft). Thermal maturity is middle oil window based on the % Roe from Tmax measurements. The present-day hydrogen index (HIpd) values are low given this level of thermal maturity, suggesting either high-level conversion at this thermal maturity or lower than expected HIo values. The HIo values are estimated to have been 123, 265, 475, and 356 mg/g for the four different organic richness zones previously described.

An example of the Pennsylvanian Cane Creek section is provided by a geochemical log of the Mobil Oil Corp. 12-3-Jakeys Ridge well (Figure 15). These data illustrate the high organic carbon content throughout this 755.9 m (5760.81 ft) interval of the Cane Creek Shale, with an overall average of 7.67%. However, four distinct intervals are present, with average TOC values over the uppermost interval of 67 m (219.81 ft) with 1.34%, 146.3 m (479.98 ft) of 4.91%, 231.7 m (701.11 ft) of 13.49%, and 42.7 m (140.09 ft) of 6.61%. Although extremely high oil contents (S1) are present in the organic-rich interval, the values only exceed 100 mg/g at 2315.5 m (7596.76 ft), whereas the uppermost lean zone in this well has the highest OSI values averaging 120 mg/g over 67 m (219.81 ft). Thermal maturity is middle oil window based on the % Roe from Tmax measurements. The present-day hydrogen index (HIpd) values are low given this level of thermal maturity, suggesting either high-level conversion at this thermal maturity or lower than expected HIo values. The HIo values are estimated to have been 123, 265, 475, and 356 mg/g for the four different organic richness zones previously described.

[[File:M97Ch1.2FG15.jpg|thumb|300px|FIGURE 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:M97Ch1.2FG16.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.]]

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).

A geochemical log of this well illustrates the extremely low carbonate and organic carbon contents, low OSI values, and about 1 to 2% sulfur throughout the sampled interval (Figure 16). The TOCpd values average only 0.84% with a range of 0.21 to 1.36%. Miranda and Walters (1992) estimate about 20% conversion of organic matter. As such, TOCo values would only increase to about 0.92% or a range of 0.25 to 1.60%. The HIo values are estimated to be on the low end of marine shales at 284 mg HC/g TOC on average with a range of 150 to 402 mg HC/g TOC. Not only is the Tuscaloosa organic lean, but it also has extremely low carbonate (sim1%) and about 2% sulfur contents. The conversion of pyrolysis yields to oil would yield about 7.27 times 104 m3 (1.184 million bbl/mi2). Over the 15,280.93 km2 (5900 mi2) of Tuscaloosa deposition, this would amount to just about 1.11 times 109 m3 (7 billion bbl) of oil equivalent with a very high retention of generated oil based on the low HIo values, as previously predicted by John et al. (1997). The issue is not with this estimate, but being able to recover even a minimal percentage of this volume of oil. Such a low carbonate shale-oil resource system will be one of the most difficult systems to stimulate and achieve good and enduring oil flow. However, it should be noted that the clay and quartz contents are not known. Based on the organic matter, Tuscaloosa sourced oil would be a high API gravity oil or condensate, but with sulfur present. The better likelihood for production is the closely associated sands. This type of system remains a significant challenge to developing similar unconventional shale-oil plays.

A geochemical log of this well illustrates the extremely low carbonate and organic carbon contents, low OSI values, and about 1 to 2% sulfur throughout the sampled interval (Figure 16). The TOCpd values average only 0.84% with a range of 0.21 to 1.36%. Miranda and Walters (1992) estimate about 20% conversion of organic matter. As such, TOCo values would only increase to about 0.92% or a range of 0.25 to 1.60%. The HIo values are estimated to be on the low end of marine shales at 284 mg HC/g TOC on average with a range of 150 to 402 mg HC/g TOC. Not only is the Tuscaloosa organic lean, but it also has extremely low carbonate (sim1%) and about 2% sulfur contents. The conversion of pyrolysis yields to oil would yield about 7.27 times 104 m3 (1.184 million bbl/mi2). Over the 15,280.93 km2 (5900 mi2) of Tuscaloosa deposition, this would amount to just about 1.11 times 109 m3 (7 billion bbl) of oil equivalent with a very high retention of generated oil based on the low HIo values, as previously predicted by John et al. (1997). The issue is not with this estimate, but being able to recover even a minimal percentage of this volume of oil. Such a low carbonate shale-oil resource system will be one of the most difficult systems to stimulate and achieve good and enduring oil flow. However, it should be noted that the clay and quartz contents are not known. Based on the organic matter, Tuscaloosa sourced oil would be a high API gravity oil or condensate, but with sulfur present. The better likelihood for production is the closely associated sands. This type of system remains a significant challenge to developing similar unconventional shale-oil plays.

[[File:M97Ch1.2FG16.jpg|thumb|300px|FIGURE 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:M97Ch1.2FG17.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.]]

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).

The Continental 1-Staunton well illustrates the variability in various geochemical characteristics of the Heath Shale. (Figure 17). The average TOC value is 4.52% in this well, but the range is 0.20 to 13.66% with a high standard deviation of 5.20%. Carbonate carbon data are not available. The pyrolysis yields (present-day Rock-Eval measured kerogen [S2pd]) and HIpd are also highly variable, with HIpd values averaging 315 mg HC/g TOC, with a range of 137 to 523 mg HC/g TOC. Thermal maturity is early oil window with % Roe from Tmax values of 0.51 to 0.72%. Conversion of organic matter is thus likely about 10 to 20%.

The Continental 1-Staunton well illustrates the variability in various geochemical characteristics of the Heath Shale. (Figure 17). The average TOC value is 4.52% in this well, but the range is 0.20 to 13.66% with a high standard deviation of 5.20%. Carbonate carbon data are not available. The pyrolysis yields (present-day Rock-Eval measured kerogen [S2pd]) and HIpd are also highly variable, with HIpd values averaging 315 mg HC/g TOC, with a range of 137 to 523 mg HC/g TOC. Thermal maturity is early oil window with % Roe from Tmax values of 0.51 to 0.72%. Conversion of organic matter is thus likely about 10 to 20%.

The oil crossover effect is noted in two samples: one at 778.76 m (2555 ft) and another at the base, 815.34 m (2675 ft); both are organic lean with 0.41% and 0.20% TOC, respectively, characteristic of hybrid shale-oil resource systems, and these may be the zones to target in future drilling efforts.

The oil crossover effect is noted in two samples: one at 778.76 m (2555 ft) and another at the base, 815.34 m (2675 ft); both are organic lean with 0.41% and 0.20% TOC, respectively, characteristic of hybrid shale-oil resource systems, and these may be the zones to target in future drilling efforts.

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

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

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).

A plot of TOC versus oil for both Marcellus and Utica shales shows the crossover effect even in areas where the shales show a high level of conversion indicative of gas window thermal maturity (Figure 18). This could be contamination or migrated oil.

A plot of TOC versus oil for both Marcellus and Utica shales shows the crossover effect even in areas where the shales show a high level of conversion indicative of gas window thermal maturity (Figure 18). This could be contamination or migrated oil.

====Permian Basin====

====Permian Basin====

==International shale-oil plays==

==International shale-oil plays==

===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.

Of these 192 samples, 16 samples from five different wells showed oil crossover (Figure 19). The production of gas from the Montney Shale can be restricted by the presence of oil in the system that tends to reduce gas flow rates. However, shale-oil resource potential exists, given the high amount of oil crossover in these data.

Of these 192 samples, 16 samples from five different wells showed oil crossover (Figure 19). The production of gas from the Montney Shale can be restricted by the presence of oil in the system that tends to reduce gas flow rates. However, shale-oil resource potential exists, given the high amount of oil crossover in these data.

===West Siberian Basin===

===West Siberian Basin===

===Paris Basin, France===

===Paris Basin, France===

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%.

Average Toarcian Shale data from Espitalie et al. (1988) demonstrate the oil crossover effect (Figure 20). Furthermore, a geochemical log of a well from the Donnemarie field was constructed to illustrate the shale-oil system play (Figure 21). This log illustrates two reservoir systems: one proven conventional and an unproven unconventional. The oil crossover effect in this well is obvious between 3020 and 3240 m (sim9908–10,630 ft), where conventional Triassic sandstone production exists. Uphole from this conventional ongoing production, immediately below the organic-rich Toarcian Shale, a thick organic-lean interval is present in this well from 2465 to 2609 m (sim8087.2–8559.7 ft) where oil crossover occurs, indicative of an untested, but potential, hybrid shale-oil resource production. Given the source rock type, a marine shale, and conventionally produced oil quality elsewhere in the basin, oil in this interval would be expected to be more than 35deg API oil. The Toarcian Shale immediately above this zone of crossover has an average TOC of almost 2.00% and is in the earliest oil window at about 0.75% Roe (from Tmax). In addition, a Toarcian Shale sample at 2270 m (7447.8 ft) is organic rich (4.47% TOC) and exhibits very high oil content and oil crossover indicative of active generation and expulsion. A sample at 2530 m (8300.5 ft) does not show crossover, so it could be a seal between two free oil-saturated zones.

Average Toarcian Shale data from Espitalie et al. (1988) demonstrate the oil crossover effect (Figure 20). Furthermore, a geochemical log of a well from the Donnemarie field was constructed to illustrate the shale-oil system play (Figure 21). This log illustrates two reservoir systems: one proven conventional and an unproven unconventional. The oil crossover effect in this well is obvious between 3020 and 3240 m (sim9908–10,630 ft), where conventional Triassic sandstone production exists. Uphole from this conventional ongoing production, immediately below the organic-rich Toarcian Shale, a thick organic-lean interval is present in this well from 2465 to 2609 m (sim8087.2–8559.7 ft) where oil crossover occurs, indicative of an untested, but potential, hybrid shale-oil resource production. Given the source rock type, a marine shale, and conventionally produced oil quality elsewhere in the basin, oil in this interval would be expected to be more than 35deg API oil. The Toarcian Shale immediately above this zone of crossover has an average TOC of almost 2.00% and is in the earliest oil window at about 0.75% Roe (from Tmax). In addition, a Toarcian Shale sample at 2270 m (7447.8 ft) is organic rich (4.47% TOC) and exhibits very high oil content and oil crossover indicative of active generation and expulsion. A sample at 2530 m (8300.5 ft) does not show crossover, so it could be a seal between two free oil-saturated zones.

Although carbonate carbon data were not reported on these well samples, it is anticipated that the organic-lean oil crossover zone below the Toarcian Shale is likely carbonate rich based on literature lithofacies descriptions.

Although carbonate carbon data were not reported on these well samples, it is anticipated that the organic-lean oil crossover zone below the Toarcian Shale is likely carbonate rich based on literature lithofacies descriptions.