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

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

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

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

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Other examples of open-fractured shale-oil production include the Niobrara, Pierre,<ref>U. S. Geological Survey, 2003, [http://pubs.usgs.gov/fs/fs-002-03/FS-002-03.pdf 2002 U.S. Geological Survey assessment of oil and gas resource potential of the Denver Basin Province of Colorado, Kansas, Nebraska, South Dakota, and Wyoming]: U.S. Geological Survey Fact Sheet FS-002-03, February 2003, 3 p.</ref> Upper Bakken shale-oil systems,<ref name=ND2010>North Dakota Geological Survey, 2010, [https://www.dmr.nd.gov/oilgas/bakkenwells.asp Bakken horizontal wells by producing zone, upper Bakken Shale].</ref> and the West Siberian Jurassic Bazhenov Shale.<ref name=Lptn2003 />

Other examples of open-fractured shale-oil production include the Niobrara, Pierre,<ref>U. S. Geological Survey, 2003, [http://pubs.usgs.gov/fs/fs-002-03/FS-002-03.pdf 2002 U.S. Geological Survey assessment of oil and gas resource potential of the Denver Basin Province of Colorado, Kansas, Nebraska, South Dakota, and Wyoming]: U.S. Geological Survey Fact Sheet FS-002-03, February 2003, 3 p.</ref> Upper Bakken shale-oil systems,<ref name=ND2010>North Dakota Geological Survey, 2010, [https://www.dmr.nd.gov/oilgas/bakkenwells.asp Bakken horizontal wells by producing zone, upper Bakken Shale].</ref> and the West Siberian Jurassic Bazhenov Shale.<ref name=Lptn2003 />

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 & Gas in a synclinal part of the onshore Santa Maria Basin. The Coastal Oil & Gas (O&G) 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===

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

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

Elsewhere in California, organic-rich source rocks are also found in the San Joaquin Basin. These shales, age equivalent to the Monterey Shale, are the Miocene Antelope and McLure shales that are also oil productive. An example is provided by the Arco Oil amp Gas 1-Bear Valley well, Asphalto field in Kern County, California. In the early 1990s, Arco's Research Center and Humble Geochemical Services completed analyses of this well as a joint research project prompting completion of the well in the Antelope Shale. The geochemical results were later presented, showing the production of about 250 bbl of oil/day from the Antelope Shale.<ref name=Jrvetal1995 /> 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 & 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.<ref name=Jrvetal1995 /> 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.

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.<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).

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,<ref>Oil & Gas Journal, 2010c, [http://www.pennenergy.com/index/petroleum/display/6670774195/articles/oil-gas-financial-journal/volume-6/Issue_7/Features/Whiting_Petroleum_s__sweet_spot__is_most_prolific_part_of_the_Bakken.html Whiting Petroleum's sweet spot is most prolific part of the Bakken].</ref> 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.<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>

The Bakken shales have intermittent oil crossover indicative of active generation and expulsion. Extracts of the Bakken Shale yield CTemp values<ref>BeMent, W. O., R. A. Levey, and F. D. Mango, 1994, [http://wwgeochem.com/references/BeMentetalabstract.pdf The temperature of oil generation as defined with a C7 chemistry maturity parameter (2,4-DMP/2,3-DMP ratio)]: First Joint AAPG/AMPG Research Conference, Geological Aspects of Petroleum Systems, October 2–6, 1994, Mexico City, Mexico.</ref><ref>Mango, F. D., 1997, The light hydrocarbons in petroleum: A critical review: Organic Geochemistry, v. 26, no. 7/8, p. 417–440.</ref> 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===

A short horizontal well drilled by Columbia Gas Development Corp. in 1991, the 27-1-Kane Springs Federal, flowed 145 m3 (914 bbl) of oil and 8200 m3 (290 mcf) of gas over the Cane Creek Shale interval from 2267 to 2512 m (7438–8240 ft), with a pressure gradient of 19.2 kPa/m (0.85 psi/ft).<ref name=Chdsy />

A short horizontal well drilled by Columbia Gas Development Corp. in 1991, the 27-1-Kane Springs Federal, flowed 145 m3 (914 bbl) of oil and 8200 m3 (290 mcf) of gas over the Cane Creek Shale interval from 2267 to 2512 m (7438–8240 ft), with a pressure gradient of 19.2 kPa/m (0.85 psi/ft).<ref name=Chdsy />

A well drilled in 2009 by Whiting Oil amp Gas Corp., the 43-18H-Threemile in San Juan County, Utah, in the Cane Creek Shale was reported to have 8 to 13% porosity, 10 to 50 microdarcys permeability, and 20 to 35% water saturation; and was highly overpressured with a pressure gradient of 21.218 kPa/m (0.938 psi/ft).<ref name=Rsmssn>Rasmussen, L., T. Smith, L. Canter, M. Sonnenfeld, and J. Forster, 2010, [http://www.searchanddiscovery.net/abstracts/pdf/2010/rms/abstracts/ndx_rasmussen03.pdf Analysis of a long Cane Creek horizontal: New insight into an unconventional tight oil resource play, Paradox Basin, Utah (abs.)]: AAPG Rocky Mountain Section meeting, Durango, Colorado, June 13–16, 2010, AAPG Search and Discovery 90106.</ref> The well was completed with an uncemented liner and swell packers with 11-stage stimulation every 152.4 m (500 ft), each with 49,895.16 kg (110,000 lb) of proppant and 318 m3 (2000 bbl) of gel.<ref name=Rsmssn /> The scout ticket shows an initial flow rate of 1.145 m3/day (72 bbl/day) of oil, 1080 m3/day (38 mcf/day) of gas, and 31.16 m3/day (196 bbl/day) of water, but the well has since produced 1722 m3 (10,832 bbl) of oil, 5.16 times 104 m3 (1821 mcf) of gas, and 8863 m3 (55,745 bbl) of water, with a maximum GOR of 134.83 m3/m3 (757 scf/bbl).<ref name=IHSENOD2010 />

A well drilled in 2009 by Whiting Oil & Gas Corp., the 43-18H-Threemile in San Juan County, Utah, in the Cane Creek Shale was reported to have 8 to 13% porosity, 10 to 50 microdarcys permeability, and 20 to 35% water saturation; and was highly overpressured with a pressure gradient of 21.218 kPa/m (0.938 psi/ft).<ref name=Rsmssn>Rasmussen, L., T. Smith, L. Canter, M. Sonnenfeld, and J. Forster, 2010, [http://www.searchanddiscovery.net/abstracts/pdf/2010/rms/abstracts/ndx_rasmussen03.pdf Analysis of a long Cane Creek horizontal: New insight into an unconventional tight oil resource play, Paradox Basin, Utah (abs.)]: AAPG Rocky Mountain Section meeting, Durango, Colorado, June 13–16, 2010, AAPG Search and Discovery 90106.</ref> The well was completed with an uncemented liner and swell packers with 11-stage stimulation every 152.4 m (500 ft), each with 49,895.16 kg (110,000 lb) of proppant and 318 m3 (2000 bbl) of gel.<ref name=Rsmssn /> The scout ticket shows an initial flow rate of 1.145 m3/day (72 bbl/day) of oil, 1080 m3/day (38 mcf/day) of gas, and 31.16 m3/day (196 bbl/day) of water, but the well has since produced 1722 m3 (10,832 bbl) of oil, 5.16 times 104 m3 (1821 mcf) of gas, and 8863 m3 (55,745 bbl) of water, with a maximum GOR of 134.83 m3/m3 (757 scf/bbl).<ref name=IHSENOD2010 />

An example of the Pennsylvanian Cane Creek section is provided by a geochemical log of the Mobil Oil Corp. 12-3-Jakeys Ridge well ([[:File:M97Ch1.2FG15.jpg|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 ([[:File:M97Ch1.2FG15.jpg|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:M97Ch1.2FG16.jpg|thumb|500px|{{figure number|16}}Geochemical log of the Sun Oil Co. 1-Spinks well in Pike County, Mississippi, Mid-Gulf Coast Basin through the Tuscaloosa Shale. The Tuscaloosa Shale has poor to good total organic carbon (TOC) values with no crossover effect in this well. Note the extremely low carbonate content (lt2%) and sulfur content of as much as 3%. S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

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

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

The Lower Cretaceous Tuscaloosa Marine Shale (TMS) ranges in thickness from 152.4 m (500 ft) to more than 243.8 m (800 ft) overlain and underlain by sands. The depth to the TMS is found at 3048 m (10,000 ft) and deeper. One well, the Texas Pacific Oil Co. 1-Winfred Blades, in Tangipahoa Parish, Louisiana, produced more than 3180 m3 (20,000 bbl) of oil from perforations in the TMS between 3375 and 3549 m (11,073–11,644 ft).<ref name=Jhn>John, C., B. L. Jones, J. E. Moncrief, R. Bourgeois, and B. J. Harder, 1997, [http://www.lgs.lsu.edu/deploy/uploads/Tuscaloosa%20Marine%20Shale.pdf An unproven unconventional seven-billion barrel oil resource: The Tuscaloosa Marine Shale].</ref>

Encore Acquisition, purchased by Denbury in 2010, drilled wells to test the shale-oil resource system of the Tuscaloosa Shale. The Encore Operating 4-13H-Jackson Joe well was drilled to about 46,811.7 m (15,650 ft) in Amite County, Mississippi. The well had a lateral of 502.9 (1650 ft) that was stimulated in three stages with 711 m3 (4471 bbl) of X-LinkGel and placed on pump (scout ticket). The TMS had an initial production rate of 114 m3 (175 bbl/day) over the interval from 4087.4 to 4092.2 m (13,410–13,426 ft).

Encore Acquisition, purchased by Denbury in 2010, drilled wells to test the shale-oil resource system of the Tuscaloosa Shale. The Encore Operating 4-13H-Jackson Joe well was drilled to about 46,811.7 m (15,650 ft) in Amite County, Mississippi. The well had a lateral of 502.9 (1650 ft) that was stimulated in three stages with 711 m3 (4471 bbl) of X-LinkGel and placed on pump (scout ticket). The TMS had an initial production rate of 114 m3 (175 bbl/day) over the interval from 4087.4 to 4092.2 m (13,410–13,426 ft).

Limited data are available on the TMS, but an article by Miranda and Walters (1992) provides detailed analyses of an upper-middle Tuscaloosa Shale core. Sun Oil Corp. drilled the 1-Spinks well in Pike County, Mississippi, taking 94.5 m (310 ft) of core. They report the core as having dark-gray fissile shale with occasional thin (5–25 cm [2–10 in.]) sand intervals. The well was perforated in three different intervals between 3356.15 and 3366.21 m (11,011–11,044 ft), but no oil or gas flow was recorded.

Limited data are available on the TMS, but an article by Miranda and Walters (1992) provides detailed analyses of an upper-middle Tuscaloosa Shale core. Sun Oil Corp. drilled the 1-Spinks well in Pike County, Mississippi, taking 94.5 m (310 ft) of core. They report the core as having dark-gray fissile shale with occasional thin (5–25 cm [2–10 in.]) sand intervals. The well was perforated in three different intervals between 3356.15 and 3366.21 m (11,011–11,044 ft), but no oil or gas flow was recorded.

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 ([[:File:M97Ch1.2FG16.jpg|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 ([[:File:M97Ch1.2FG16.jpg|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.<ref name=Jhn /> 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.

====Heath Shale====

====Heath Shale====

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

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

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

The Upper Mississippian Heath Shale in the Central Montana trough is a candidate shale-oil resource system. This system is a fractured shale-oil play with higher porosity and some vertical wells have flowed 200 bbl/day.<ref name=O&G2010a>Oil & Gas Journal, 2010a, [http://www.ogj.com/index/article-display.articles.oil-gas-journal.exploration-development-2.2010.08.montana-heath_shale.QP129867.dcmp=rss.page=1.html Montana Heath Shale oil potential due tests].</ref>

The TOC data from Cole and Drozd (1994) show an average TOC of 7.6% on 32 core samples from Fergus County, Montana, although the authors state that the thickness of the source rock is less than 10 m (20–30 ft), with calcareous shales being the best source rock intervals. They also state that “a large part of generated hydrocarbons remained within the source rock interval” (p. 382). Thermal maturity values range from immature to late oil window primarily in parts of Musselshell, Rosebud, and Garfield counties (Cole and Drozd, 1994).

The TOC data from Cole and Drozd (1994) show an average TOC of 7.6% on 32 core samples from Fergus County, Montana, although the authors state that the thickness of the source rock is less than 10 m (20–30 ft), with calcareous shales being the best source rock intervals. They also state that “a large part of generated hydrocarbons remained within the source rock interval” (p. 382). Thermal maturity values range from immature to late oil window primarily in parts of Musselshell, Rosebud, and Garfield counties (Cole and Drozd, 1994).

====Permian Basin====

====Permian Basin====

=====Wolfcamp Shale=====

=====Wolfcamp Shale=====

The Lower Wolfcamp Shale is being pursued for its shale-oil resource potential (Oil amp Gas Journal, 2010b). Vertical wells drilled by Pioneer Natural Resources Co. are reported to average 2 to 10 m3 (15–60 bbl/day) in 61.0 to 91.5 m (200–300 ft) of shale, with TOC values reported as very high (Oil amp Gas Journal, 2010b). Lower Wolfcamp Shale near the Horseshoe Atoll in Borden County, Texas, averages about 2.99% on cuttings, with thermal maturity in the early oil window; the TOCo is estimated to be 3.82% on average, with values over a broad range from 1 to 10%. Horizontal wells with approximately 1219.2 to 1524.0 m (4000 to 5000 ft) laterals with 14 hydraulic fracturing stages are anticipated (Oil amp Gas Journal, 2010b). This hybrid shale-oil resource play is often referred to as the Wolfberry play for the juxtaposition of Wolfcamp shales and Spraberry sands.

The Lower Wolfcamp Shale is being pursued for its shale-oil resource potential.<ref name=O&G2010b>Oil & Gas Journal, 2010b, [http://www.ogj.com/index/article-display/0885614732/articles/oil-gas-journal/explorationdevelopment-2/2010/10/pioneer-to_pursue.html Pioneer to pursue oil in Lower Wolfcamp shale].</ref> Vertical wells drilled by Pioneer Natural Resources Co. are reported to average 2 to 10 m3 (15–60 bbl/day) in 61.0 to 91.5 m (200–300 ft) of shale, with TOC values reported as very high.<ref name=O&G2010b /> Lower Wolfcamp Shale near the Horseshoe Atoll in Borden County, Texas, averages about 2.99% on cuttings, with thermal maturity in the early oil window; the TOCo is estimated to be 3.82% on average, with values over a broad range from 1 to 10%. Horizontal wells with approximately 1219.2 to 1524.0 m (4000 to 5000 ft) laterals with 14 hydraulic fracturing stages are anticipated.<ref name=O&G2010b /> This hybrid shale-oil resource play is often referred to as the Wolfberry play for the juxtaposition of Wolfcamp shales and Spraberry sands.

=====Bone Springs and Avalon Shale=====

=====Bone Springs and Avalon Shale=====

{{reflist}}

{{reflist}}

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* Cole, G. A., and R. J. Drozd, 1994, Heath-Tyler(!) petroleum system in central Montana, in L. B. Magoon and W. G. Dow, eds., The petroleum system: From source to trap: AAPG Memoir 60, p. 371–385.

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* Espitalie, J., J. R. Maxwell, P. Y. Chenet, and F. Marquis, 1988, Aspects of hydrocarbon migration in the Mesozoic in the Paris Basin as deduced from an organic geochemical survey, Advances in Organic Geochemistry 1987: Organic Geochemistry, v. 13, no. 1–3, p. 467–481, doi:10.1016/0146-6380(88)90068-X.

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* Rullkotter, J., et al., 1988, Organic matter maturation under the influence of a deep instrusive heat source: A natural experiment for quantitation of hydrocarbon generation and expulsion from a petroleum source rock (Toarcian Shale, northern Germany), Advances in Organic Geochemistry 1987: Organic Geochemistry, v. 13, no. 1–3, p. 847–856, doi:10.1016/0146-6380(88)90237-9.

* Rullkotter, J., et al., 1988, Organic matter maturation under the influence of a deep instrusive heat source: A natural experiment for quantitation of hydrocarbon generation and expulsion from a petroleum source rock (Toarcian Shale, northern Germany), Advances in Organic Geochemistry 1987: Organic Geochemistry, v. 13, no. 1–3, p. 847–856, doi:10.1016/0146-6380(88)90237-9.