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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.<ref>Williams, P., 2010, [http://www.oilandgasinvestor.com/Magazine/2010/1/item50371.php Oil-prone shales: Oil and Gas Investor].</ref>

An example of fractured Monterey Shale production is given by the Union Oil A82-19 Jesus Maria well drilled in 1987 located in Lompoc field, Santa Barbara County, California. Initial tests on the well above the interval from 1379.2 to 1437.1 m (4525–4715 ft) yielded 24.6 m3/day (155 bbl/day) of 17deg API oil and 481.4 m3/day (17 mcf/day), with a gas-oil ratio (GOR) of 19.5 m3/m3 (109 scf/bbl) according to a scout ticket for this well.

An example of fractured Monterey Shale production is given by the Union Oil A82-19 Jesus Maria well drilled in 1987 located in Lompoc field, Santa Barbara County, California. Initial tests on the well above the interval from 1379.2 to 1437.1 m (4525–4715 ft) yielded 24.6 m3/day (155 bbl/day) of 17deg API oil and 481.4 m3/day (17 mcf/day), with a gas-oil ratio (GOR) of 19.5 m3/m3 (109 scf/bbl) according to a scout ticket for this well.

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 ([[:M97Ch1.2FG3.jpg|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.<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 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).

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

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

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

M97Ch1.2FG6.jpg|{{figure number|6}}(A, B) Geochemical database of total organic carbon (TOC) and Rock-Eval analyses from the North Dakota Geological Survey.<ref name=ND2008>North Dakota Geological Survey, 2008, [https://www.dmr.nd.gov/ndgs/bakken/bakkenthree.asp Bakken TOCs]. </ref> A plot of free oil contents versus TOC illustrates the oil crossover effect of the upper Bakken Shale, Middle Member of the Bakken Formation, lower Bakken Shale, and Three Forks: (A) all data with up to 30% TOC, and (B) reduced scale emphasizing the Middle Member of the Bakken Formation and Three Forks data. S1 = Rock-Eval measured oil contents.

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

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

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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<ref name=ND2010 /> 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).

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

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

*  

*  

* Miranda, R. M., and C. C. Walters, 1992, Geochemical variations in sedimentary matter within a “homogeneous” shale core (Tuscaloosa Formation, Upper Cretaceous, Mississippi: Organic Geochemistry, v. 18, no. 6, p. 899–911, doi:10.1016/0146-6380(92)90057-5.

* Miranda, R. M., and C. C. Walters, 1992, Geochemical variations in sedimentary matter within a “homogeneous” shale core (Tuscaloosa Formation, Upper Cretaceous, Mississippi: Organic Geochemistry, v. 18, no. 6, p. 899–911, doi:10.1016/0146-6380(92)90057-5.

* North Dakota Geological Survey, 2008, Bakken TOCs: https://www.dmr.nd.gov/ndgs/bakken/bakkenthree.asp (accessed May 10, 2009).

*  

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* Nyahay, R., J. Leone, L. Smith, J. Martin, and D. Jarvie, 2007, Shale gas potential in New York: Result from recent NYSERDA-sponsored reseaqrch, AAPG Annual Meeting, Long Beach, California, April 1–4, 2007, AAPG Bulletin: http://www.searchanddiscovery.com/20047/07101nyahay/index.htm (accessed January 10, 2011).

* Oil amp Gas Journal, 2010a, Montana Heath Shale oil potential due tests: 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 (accessed November 12, 2010).

* Oil amp Gas Journal, 2010a, Montana Heath Shale oil potential due tests: 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 (accessed November 12, 2010).

* Tanck, G. S., 1997, Distribution and origin of organic carbon in the Upper Cretaceous Niobrara Formation and Sharon Springs Member of the Pierre Shale, Western Interior, United States: Ph.D. thesis, University of Arizona, Tuscon, Arizona, 411 p.

* Tanck, G. S., 1997, Distribution and origin of organic carbon in the Upper Cretaceous Niobrara Formation and Sharon Springs Member of the Pierre Shale, Western Interior, United States: Ph.D. thesis, University of Arizona, Tuscon, Arizona, 411 p.

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* Toreador Resources: 2010, Paris Basin shale oil: Toreador taking the lead, Unconventional Oil 2010, October 12, 2010, London: http://www.toreador.net/images/presentations/Toreador_Unconventional_Oil_2010.pdf.

* U. S. Geological Survey, 2003, 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.: http://pubs.usgs.gov/fs/fs-002-03/FS-002-03.pdf (accessed November 12, 2010).

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