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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.

Success in shale-gas resource systems has renewed interest in efforts to attempt to produce oil from organic-rich mudstones or juxtaposed lithofacies as reservoir rocks. The economic value of petroleum liquids is greater than that of natural gas; thus, efforts to move from gas into more liquid-rich and black-oil areas have been another United States exploration and production paradigm shift since about 2008.

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.<ref name=EOGResources2010>EOG Resources, 2010, [http://wwgeochem.com/references/EOGMay2010Investorpresentation.pdf Investor presentation], 223 p.</ref> 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.

Shale-oil resource systems are organic-rich mudstones that have generated oil that is stored in the organic-rich mudstone intervals or migrated into juxtaposed, continuous organic-lean intervals. This definition includes not only the organic-rich mudstone or shale itself, but also those systems with juxtaposed (overlying, underlying, or interbedded) organic-lean rocks, such as carbonates. Systems such as the Bakken and Niobrara formations with juxtaposed organic-lean units to organic-rich source rocks are considered part of the same shale-oil resource system. Thus, these systems may include primary and secondary migrated oil. Oil that has undergone tertiary migration to nonjuxtaposed reservoirs is part of a petroleum system, but not a shale-oil resource system.

[[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).]]

 

 

 

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 [[mudstone]]s, 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 ([[: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 play|Barnett Shale]] oil is almost always from a tight mudstone with some related matrix porosity.<ref name=EOGResources2010>EOG Resources, 2010, [http://wwgeochem.com/references/EOGMay2010Investorpresentation.pdf Investor presentation], 223 p.</ref> 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 [[:File:M97Ch1Tbl1.jpeg|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.

 

M97Ch1.2FG1.jpg|{{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.

A special, but separate, shale resource system is oil shale. It is preferred to refer to oil shale as a kerogen resource system or as kerogen oil as it does not contain sufficient amounts of free oil to produce, but must be heated to generate oil from kerogen either in the subsurface or after mining and retorting. This 2d part of chapter 1 will only discuss shale-oil resource systems that have already generated petroleum because of geologic heating processes.

A special, but separate, shale resource system is [[oil shale]]. It is preferred to refer to oil shale as a [[kerogen]] resource system or as kerogen oil as it does not contain sufficient amounts of free oil to produce, but must be heated to generate oil from kerogen either in the subsurface or after mining and retorting. This 2d part of chapter 1 will only discuss shale-oil resource systems that have already generated petroleum because of geologic heating processes.

With the remarkable success in locating and producing shale-gas resource systems, an overabundance of gas has reduced its current economic value and there has been an exploration and development shift toward locating producible shale-oil resource systems. Recent announcements of the oil resource potential of several shale-oil resource systems have substantiated the volume of oil they contain, for example, 5.88253 times 107 m3 (370 million bbl of oil equivalent [BOE]) in the Barnett Shale, 1.430886 times 107 m3 (90 million BOE) in the Bakken Formation core area, and 1.430886 times 108 m3 (900 million BOE) in the Eagle Ford Shale.<ref name=EOGResources2010 /> However, the keys to unlocking these high volumes of oil are not fully understood or developed to date.

With the remarkable success in locating and producing shale-gas resource systems, an overabundance of gas has reduced its current economic value and there has been an exploration and development shift toward locating producible shale-oil resource systems. Recent announcements of the oil resource potential of several shale-oil resource systems have substantiated the volume of oil they contain, for example, 5.88253 times 107 m3 (370 million bbl of oil equivalent [BOE]) in the [[Barnett shale play|Barnett Shale]], 1.430886 times 107 m3 (90 million BOE) in the Bakken Formation core area, and 1.430886 times 108 m3 (900 million BOE) in the Eagle Ford Shale.<ref name=EOGResources2010 /> However, the keys to unlocking these high volumes of oil are not fully understood or developed to date.

==Background==

==Background==

Identifying source rocks in the oil window is the first step to identifying areas of potential petroleum exploitation. However, the oil window must be considered carefully because the oil window does vary, depending on the source rock, although thermal maturity values from about 0.60 to 1.40% Ro are the most likely values significant for petroleum liquid generation. Regardless of thermal maturity, there must be sufficient oil saturation to allow the possibility of commercial production of oil.

Identifying source rocks in the oil window is the first step to identifying areas of potential petroleum exploitation. However, the oil window must be considered carefully because the oil window does vary, depending on the source rock, although thermal maturity values from about 0.60 to 1.40% Ro are the most likely values significant for petroleum liquid generation. Regardless of thermal maturity, there must be sufficient oil saturation to allow the possibility of commercial production of oil.

Although an organic-rich source rock in the oil window with good oil saturation is the most likely place to have oil, it is also the most difficult to produce, unless it has open fractures or an organic-lean facies closely associated with it. This is due to molecular size, viscosity, and sorption of oil. However, juxtaposed organic-lean lithofacies such as carbonates, sands, or silts in shale-oil resource plays are very important to higher productivity due to short distances of secondary migration (where secondary migration is defined as movement from the source rock to nonsource intervals;<ref>Welte, D. H., and D. Leythaeuser, 1984, Geological and physicochemical conditions for primary migration of hydrocarbons: Naturwissenschaften, v. 70, p. 133–137, doi:10.1007/BF00401597.</ref> added storage potential, and low sorption affinities. Secondary migration is defined as movement from the source rock to non-source intervals that also results in some fractionation of the expelled oil with heavier, more polar components of crude oil retained in the organic-rich shale. Juxtaposed means contact of organic-rich with organic-lean intervals regardless of position (overlying, underlying, or interbedded). Petroleum that undergoes tertiary migration would move outside the shale resource system and this would account for conventional petroleum or other unconventional resource systems. Even in a hybrid shale-oil resource system, the source rock itself may be contributing to actual production and may be considered as a component of the oil in place (OIP).

Although an organic-rich source rock in the oil window with good oil saturation is the most likely place to have oil, it is also the most difficult to produce, unless it has open fractures or an organic-lean facies closely associated with it. This is due to molecular size, viscosity, and sorption of oil. However, juxtaposed organic-lean lithofacies such as carbonates, sands, or silts in shale-oil resource plays are very important to higher productivity due to short distances of secondary migration (where secondary migration is defined as movement from the source rock to nonsource intervals;<ref>Welte, D. H., and D. Leythaeuser, 1984, Geological and physicochemical conditions for primary migration of hydrocarbons: Naturwissenschaften, v. 70, p. 133–137, doi:10.1007/BF00401597.</ref> added storage potential, and low sorption affinities. Secondary migration is defined as movement from the source rock to non-source intervals that also results in some fractionation of the expelled oil with heavier, more polar components of [[crude oil]] retained in the organic-rich shale. Juxtaposed means contact of organic-rich with organic-lean intervals regardless of position (overlying, underlying, or interbedded). Petroleum that undergoes tertiary migration would move outside the shale resource system and this would account for conventional petroleum or other unconventional resource systems. Even in a hybrid shale-oil resource system, the source rock itself may be contributing to actual production and may be considered as a component of the oil in place (OIP).

Processes involving the generation of carbon (CO2) and organic acids have been postulated for the creation of secondary porosity in conventional petroleum systems<ref>Surdam, R. C., L. J. Crossey, E. Sven Hagen, and H. P. Heasler, 1989, [http://archives.datapages.com/data/bulletns/1988-89/data/pg/0073/0001/0000/0001.htm Organic-Inorganic interactions and sandstone diagenesis]: AAPG Bulletin, v. 73, no. 1, p. 1–23.</ref> but have mostly been discounted because, in part, of the low volume of generated acid relative to carbonate. However, this process appears quite important in unconventional carbonate-rich shale-oil resource systems. Acid dissolution of carbonates as a source of secondary porosity has been cited in the Bakken Middle Member along with thin-section substantiation.<ref name=Ptmn2001>Pitman, J. K., L. C. Price, and J. A. LeFever, 2001, Diagenesis and fracture development in the Bakken Formationm Williston Basin: Implications for reservior quality in the Middle Member: U.S. Geological Survey Professional Paper 1653, 19 p.</ref> The acid source is presumed to be organic acids released during kerogen diagenesis,<ref name=Ptmn2001 /> but acidity is also derived from the CO2 released from both kerogen and pre-oil window release of CO2 from thermal decomposition of siderite-forming carbonic acid. Immature Bakken shale was found to release large amounts of carbon dioxide under relatively low hydrous pyrolysis conditions (225–275degC [437–527degF])<ref>L. C. Price, 1997, personal communication</ref><ref>Price, L. C., C. E. Dewitt, and G. Desborough, 1998, Implications of hydrocarbons in carbonaceous metamorphic and hydrothermal ore-deposit rocks as related to hydolytic disproportionation of OM: U.S. Geological Survey Open-File Report 98-758, 127 p.</ref><ref>L. Wenger, 2010, personal communication</ref> likely from kerogen diagenesis. The release of CO2 also explains the apparent increase in hydrogen indices during diagenesis, which is but an artifact of organic carbon loss. In addition, carbonates will also release CO2 under increasing thermal stress, with siderite being the most labile (pre- to early oil window); dolomites, more refractory (highly variable late oil–to–dry gas windows); and calcite, in metagenesis.<ref name=J&J2007>Jarvie, B. M., and D. M. Jarvie, 2007, [http://wwgeochem.com/references/JarvieandJarvie2007ThermalDecompositionofCarbonates.pdf Thermal decomposition of various carbonates: Kinetics results and geological temperatures of conversion]: 23rd International Meeting on Organic Geochemistry (IMOG) 2007, Torquay, UK, September 9–14, 2007, p. 311–312.</ref>

Processes involving the generation of carbon (CO2) and organic acids have been postulated for the creation of secondary porosity in conventional petroleum systems<ref>Surdam, R. C., L. J. Crossey, E. Sven Hagen, and H. P. Heasler, 1989, [http://archives.datapages.com/data/bulletns/1988-89/data/pg/0073/0001/0000/0001.htm Organic-Inorganic interactions and sandstone diagenesis]: AAPG Bulletin, v. 73, no. 1, p. 1–23.</ref> but have mostly been discounted because, in part, of the low volume of generated acid relative to carbonate. However, this process appears quite important in unconventional carbonate-rich shale-oil resource systems. Acid dissolution of carbonates as a source of secondary porosity has been cited in the Bakken Middle Member along with thin-section substantiation.<ref name=Ptmn2001>Pitman, J. K., L. C. Price, and J. A. LeFever, 2001, Diagenesis and fracture development in the Bakken Formationm Williston Basin: Implications for reservior quality in the Middle Member: U.S. Geological Survey Professional Paper 1653, 19 p.</ref> The acid source is presumed to be organic acids released during kerogen [[diagenesis]],<ref name=Ptmn2001 /> but acidity is also derived from the CO2 released from both kerogen and pre-oil window release of CO2 from thermal decomposition of siderite-forming carbonic acid. Immature Bakken shale was found to release large amounts of carbon dioxide under relatively low hydrous pyrolysis conditions (225–275degC [437–527degF])<ref>L. C. Price, 1997, personal communication</ref><ref>Price, L. C., C. E. Dewitt, and G. Desborough, 1998, Implications of hydrocarbons in carbonaceous metamorphic and hydrothermal ore-deposit rocks as related to hydolytic disproportionation of OM: U.S. Geological Survey Open-File Report 98-758, 127 p.</ref><ref>L. Wenger, 2010, personal communication</ref> likely from kerogen diagenesis. The release of CO2 also explains the apparent increase in hydrogen indices during diagenesis, which is but an artifact of organic carbon loss. In addition, carbonates will also release CO2 under increasing thermal stress, with siderite being the most labile (pre- to early oil window); [[dolomites]], more refractory (highly variable late oil–to–dry gas windows); and calcite, in [[metagenesis]].<ref name=J&J2007>Jarvie, B. M., and D. M. Jarvie, 2007, [http://wwgeochem.com/references/JarvieandJarvie2007ThermalDecompositionofCarbonates.pdf Thermal decomposition of various carbonates: Kinetics results and geological temperatures of conversion]: 23rd International Meeting on Organic Geochemistry (IMOG) 2007, Torquay, UK, September 9–14, 2007, p. 311–312.</ref>

Carbon dioxide in saqueous solution during kerogen diagenesis (i.e., pre-oil generation) is also a source of pressure increase in a closed system aiding the creation of potential conduits for petroleum migration. Ultimately, in contact with carbonate rocks, these acids will eventually result in mineral-rich (e.g., Ca++) solutions that precipitate. This was also shown by the carbon isotopic analysis of calcite cements, by Pitman et al.,<ref name=Ptmn2001 /> that were shown to be derived from marine carbonates.

Carbon dioxide in saqueous solution during kerogen diagenesis (i.e., pre-oil generation) is also a source of pressure increase in a closed system aiding the creation of potential conduits for petroleum migration. Ultimately, in contact with carbonate rocks, these acids will eventually result in mineral-rich (e.g., Ca++) solutions that precipitate. This was also shown by the carbon isotopic analysis of calcite cements, by Pitman et al.,<ref name=Ptmn2001 /> that were shown to be derived from marine carbonates.

Although kerogen diagenesis and carbonate minerals are sources of CO2 and organic acids, Gaupp and Schoener<ref>Gaupp, R., and R. Schoener, 2008, Intrareservoir generation of organic acids and late stage enhanced porosity in sandstones (abs.): AAPG Bulletin Search and Discovery article 90078, AAPG National Convention, San Antonio, Texas.</ref> noted the potential of alkanes to be converted to acids.

Although kerogen [[diagenesis]] and carbonate minerals are sources of CO2 and organic acids, Gaupp and Schoener<ref>Gaupp, R., and R. Schoener, 2008, Intrareservoir generation of organic acids and late stage enhanced porosity in sandstones (abs.): AAPG Bulletin Search and Discovery article 90078, AAPG National Convention, San Antonio, Texas.</ref> noted the potential of alkanes to be converted to acids.

A moderate to high quartz content has played a significant role in allowing shale-gas resource systems to be stimulated because of their contribution to rock brittleness. Derivation of this quartz has largely been from biogenic sources instead of detrital, meaning it is closely associated with organic matter. As such, this close association with organic matter inhibits oil flow not only because of lower permeability in an organic-rich mudstone, but also because of adsorption to organic matter. However, in organic-lean rock, adsorption is minimized, thereby enhancing the possibility of free oil flow, with the remaining obstacle of overcoming low permeability in the typical tight-oil resource system by stimulation or hydraulic fracturing.

A moderate to high quartz content has played a significant role in allowing shale-gas resource systems to be stimulated because of their contribution to rock [[brittleness]]. Derivation of this quartz has largely been from biogenic sources instead of detrital, meaning it is closely associated with organic matter. As such, this close association with organic matter inhibits oil flow not only because of lower permeability in an organic-rich mudstone, but also because of adsorption to organic matter. However, in organic-lean rock, adsorption is minimized, thereby enhancing the possibility of free oil flow, with the remaining obstacle of overcoming low permeability in the typical tight-oil resource system by stimulation or hydraulic fracturing.

Adsorption plays a very significant role in unconventional resource plays. It accounts, in part, for the retention of oil that is ultimately cracked to gas in shale-gas systems and provides varying amounts of adsorptive storage in shales (as well as in coalbed methane). Oil expelled into organic-lean lithofacies does not exhibit the high adsorption affinities found in organic-rich mudstones, thereby allowing better production characteristics. The molecular size of crude oil is important, but its adsorptive affinities may be equally or even more important in flow rates. Based on experimental data from Sandvik et al.,<ref name=Sndvk1992>Sandvik, E. I., W. A. Young, and D. J. Curry, 1992, Expulsion from hydrocarbon sources: The role of organic absorption, Advances in Organic Geochemistry 1991: Organic Geochemistry, v. 19, no. 1–3, p. 77–87, doi:10.1016/0146-6380(92)90028-V.</ref> only 14% of resins (polar compounds of low viscosity) is expelled, whereas 86% of this oil fraction is retained in the source rock. A much higher percentage of nonpolar saturated and aromatic hydrocarbons are expelled (sim60%), with the balance being retained under the closed-system experimental conditions that Sandvik et al.<ref name=Sndvk1992 /> used.

Adsorption plays a very significant role in unconventional resource plays. It accounts, in part, for the retention of oil that is ultimately cracked to gas in shale-gas systems and provides varying amounts of adsorptive storage in shales (as well as in coalbed methane). Oil expelled into organic-lean lithofacies does not exhibit the high adsorption affinities found in organic-rich mudstones, thereby allowing better production characteristics. The molecular size of crude oil is important, but its adsorptive affinities may be equally or even more important in flow rates. Based on experimental data from Sandvik et al.,<ref name=Sndvk1992>Sandvik, E. I., W. A. Young, and D. J. Curry, 1992, Expulsion from hydrocarbon sources: The role of organic absorption, Advances in Organic Geochemistry 1991: Organic Geochemistry, v. 19, no. 1–3, p. 77–87, doi:10.1016/0146-6380(92)90028-V.</ref> only 14% of resins (polar compounds of low viscosity) is expelled, whereas 86% of this oil fraction is retained in the source rock. A much higher percentage of nonpolar saturated and aromatic hydrocarbons are expelled (sim60%), with the balance being retained under the closed-system experimental conditions that Sandvik et al.<ref name=Sndvk1992 /> used.

==Oil content in rock samples==

==Oil content in rock samples==

An approach that was used in the early days of geochemistry to characterize the oil content of sedimentary rocks was extracting reservoir rocks with solvent and normalizing the yield against TOC.<ref name=Bkr1962>Baker, D. R., 1962, [http://archives.datapages.com/data/bulletns/1961-64/data/pg/0046/0009/1600/1621.htm Organic geochemistry of Cherokee Group in southeastern Kansas and northeastern Oklahoma]: AAPG Bulletin, v. 46, p. 1621–1642.</ref> With the advent of the Rock-Eval with TOC instrument,<ref>Espitalie, J., M. Madec, and B. Tissot, 1984, Geochemical logging, in K. J. Voorhees, ed., Analytical pyrolysis: Techniques and applications: London, Butterworths, p. 276–304.</ref> an expedient approach became available to geochemists to make a comparable assessment of oil contents without performing the solvent extraction procedures and a separate TOC analysis. In this approach, free oil from the rock is thermally vaporized at 300degC (572degF) (all Rock-Eval microprocessor temperatures are nominal temperatures, with actual temperatures typically 30–40degC [86–104degF] higher) instead of solvent extracted, thereby giving the measured oil content (Rock-Eval S1 yield). A comparison of solvent extract of rocks to Rock-Eval S1 indicates that solvent extraction (depending on the solvent system) is more effective at extracting heavier petroleum products, whereas Rock-Eval S1 is more effective at quantitating the more volatile fraction of petroleum.<ref name=J&B1984>Jarvie, D. M., and D. R. Baker, 1984, [http://wwgeochem.com/references/JarvieandBaker1984ApplicationofRock-Evalforfindingbypassedpayzones.pdf Application of the Rock-Eval III oil show analyzer to the study of gaseous hydrocarbons in an Oklahoma gas well]: 187th ACS National Meeting, St. Louis, Missouri, April 8–13, 1984.</ref> With recent work in shale-gas resource systems, it is evident that a part of the petroleum is trapped in isolated pore spaces associated with organic matter<ref>Reed, R., and R. Loucks, 2007, [http://www.searchanddiscovery.net/abstracts/html/2007/annual/abstracts/lbReed.htm?q=%2Btext%3Ananopores Imaging nanoscale pores in the Mississippian Barnett Shale of the northern Fort Worth Basin]: AAPG Annual Convention, Long Beach, California, April 1–4, 2007.</ref><ref>Loucks, R. G., R. M. Reed, S. C. Ruppel, and D. M. Jarvie, 2009, [http://www.wwgeochem.com/res;jsessionid=ADFF62C01B05731FB0FD85F0F5A5B221.TCpfixus72a?name=Loucks+et+al+nanopore+paper.pdf&type=resource Morphology, genesis, and distribution of nanometer-scale pores in siliceous mudstones of the Mississippian Barnett Shale]: Journal of Sedimentary Research, v. 79, p. 848–861, doi:10.2110/jsr.2009.092.</ref> that were described as microreservoirs by Barker.<ref>Barker, C., 1974, [http://archives.datapages.com/data/bulletns/1974-76/data/pg/0058/0011/2300/2349.htm Pyrolysis techniques for source rock evaluation]: AAPG Bulletin, v. 58, no. 11, p. 2349–2361.</ref> These isolated pores contain free oil or gas that rupture at the higher temperatures experienced during pyrolysis, thereby eluting in the Rock-Eval measured kerogen (S2) peak as do high-molecular-weight constituents of bitumen and crude oil.

An approach that was used in the early days of geochemistry to characterize the oil content of sedimentary rocks was extracting reservoir rocks with solvent and normalizing the yield against TOC.<ref name=Bkr1962>Baker, D. R., 1962, [http://archives.datapages.com/data/bulletns/1961-64/data/pg/0046/0009/1600/1621.htm Organic geochemistry of Cherokee Group in southeastern Kansas and northeastern Oklahoma]: AAPG Bulletin, v. 46, p. 1621–1642.</ref> With the advent of the Rock-Eval with TOC instrument,<ref>Espitalie, J., M. Madec, and B. Tissot, 1984, Geochemical logging, in K. J. Voorhees, ed., Analytical pyrolysis: Techniques and applications: London, Butterworths, p. 276–304.</ref> an expedient approach became available to geochemists to make a comparable assessment of oil contents without performing the solvent extraction procedures and a separate TOC analysis. In this approach, free oil from the rock is thermally vaporized at 300degC (572degF) (all Rock-Eval microprocessor temperatures are nominal temperatures, with actual temperatures typically 30–40degC [86–104degF] higher) instead of solvent extracted, thereby giving the measured oil content (Rock-Eval S1 yield). A comparison of solvent extract of rocks to Rock-Eval S1 indicates that solvent extraction (depending on the solvent system) is more effective at extracting heavier petroleum products, whereas Rock-Eval S1 is more effective at quantitating the more volatile fraction of petroleum.<ref name=J&B1984>Jarvie, D. M., and D. R. Baker, 1984, [http://wwgeochem.com/references/JarvieandBaker1984ApplicationofRock-Evalforfindingbypassedpayzones.pdf Application of the Rock-Eval III oil show analyzer to the study of gaseous hydrocarbons in an Oklahoma gas well]: 187th ACS National Meeting, St. Louis, Missouri, April 8–13, 1984.</ref> With recent work in shale-gas resource systems, it is evident that a part of the petroleum is trapped in isolated pore spaces associated with organic matter<ref>Reed, R., and R. Loucks, 2007, [http://www.searchanddiscovery.net/abstracts/html/2007/annual/abstracts/lbReed.htm?q=%2Btext%3Ananopores Imaging nanoscale pores in the Mississippian Barnett Shale of the northern Fort Worth Basin]: AAPG Annual Convention, Long Beach, California, April 1–4, 2007.</ref><ref>Loucks, R. G., R. M. Reed, S. C. Ruppel, and D. M. Jarvie, 2009, [http://www.wwgeochem.com/res;jsessionid=ADFF62C01B05731FB0FD85F0F5A5B221.TCpfixus72a?name=Loucks+et+al+nanopore+paper.pdf&type=resource Morphology, genesis, and distribution of nanometer-scale pores in siliceous mudstones of the Mississippian Barnett Shale]: Journal of Sedimentary Research, v. 79, p. 848–861, doi:10.2110/jsr.2009.092.</ref> that were described as microreservoirs by Barker.<ref>Barker, C., 1974, [http://archives.datapages.com/data/bulletns/1974-76/data/pg/0058/0011/2300/2349.htm Pyrolysis techniques for source rock evaluation]: AAPG Bulletin, v. 58, no. 11, p. 2349–2361.</ref> These isolated pores contain free oil or gas that rupture at the higher temperatures experienced during pyrolysis, thereby eluting in the Rock-Eval measured kerogen (S2) peak as do high-molecular-weight constituents of bitumen and [[crude oil]].

Thus, to obtain the total oil yield from a rock sample by Rock-Eval thermal extraction, it is necessary to analyze a whole rock (unextracted) and an extracted rock sample where

Thus, to obtain the total oil yield from a rock sample by Rock-Eval thermal extraction, it is necessary to analyze a whole rock (unextracted) and an extracted rock sample where

Although an oil crossover value of less than 100 mg HC/g TOC does not rule out the possibility of having producible oil, it does represent substantially higher risk based strictly on geochemical results. It may be that samples have been dried or more volatile liquids have evaporated, particularly in conventional reservoir lithofacies.

Although an oil crossover value of less than 100 mg HC/g TOC does not rule out the possibility of having producible oil, it does represent substantially higher risk based strictly on geochemical results. It may be that samples have been dried or more volatile liquids have evaporated, particularly in conventional reservoir lithofacies.

Finally, it is not only important to locate oil reservoirs, it is important also to assess the quality of the oil contained in the reservoir. Such techniques have been described<ref>Jarvie, D. M., A. Morelos, and Z. Han, 2001a, [http://www.wwgeochem.com/resources/Jarvie+2001+Williston+Basin+Petroleum+Systems+paper.pdf  Detection of pay zones and pay quality, Gulf of Mexico]: Gulf Coast Association of Geological Societies Transactions 51st Annual Convention, Shreveport, Louisiana, October 17–19, v. LI, p. 151–160.</ref> and are an essential part of assessing the economic value of a reservoir. Basic tests include determination of sulfur content, API gravity, viscosity, and yield of polar resin and asphaltene relative to nonpolar saturate and aromatic hydrocarbons. A quick screening approach is to use gas chromatography to predict oil quality based on the fingerprint derived from the rock extract; this is the same tool used on produced oil samples or recovered from reservoir tests.

Finally, it is not only important to locate oil reservoirs, it is important also to assess the quality of the oil contained in the reservoir. Such techniques have been described<ref>Jarvie, D. M., A. Morelos, and Z. Han, 2001a, [http://www.wwgeochem.com/resources/Jarvie+2001+Williston+Basin+Petroleum+Systems+paper.pdf  Detection of pay zones and pay quality, Gulf of Mexico]: Gulf Coast Association of Geological Societies Transactions 51st Annual Convention, Shreveport, Louisiana, October 17–19, v. LI, p. 151–160.</ref> and are an essential part of assessing the economic value of a reservoir. Basic tests include determination of sulfur content, API [[gravity]], viscosity, and yield of polar resin and asphaltene relative to nonpolar saturate and aromatic hydrocarbons. A quick screening approach is to use [[gas chromatography]] to predict oil quality based on the fingerprint derived from the rock extract; this is the same tool used on produced oil samples or recovered from reservoir tests.

==Oil crossover effect examples==

==Oil crossover effect examples==

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

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>

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 & 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).

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 ([[:File:M97Ch1.2FG4.jpg|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.

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.

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.

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.

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).

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

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

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

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

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,<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).

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.

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

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

[[File:M97Ch1.2FG9.jpg|thumb|500px|{{figure number|9}}Geochemical log of Four Sevens 1-Scaling Ranch A, Clay County, Texas, Fort Worth Basin showing the oil crossover in the lower Barnett Shale with its lean carbonate content. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG9.jpg|thumb|500px|{{figure number|9}}Geochemical log of Four Sevens 1-Scaling Ranch A, Clay County, Texas, Fort Worth Basin showing the oil crossover in the lower [[Barnett shale play|Barnett Shale]] with its lean carbonate content. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

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.<ref>Hill, R. J., D. M. Jarvie, R. M. Pollastro, M. Henry, and J. D. King, 2007, [http://archives.datapages.com/data/bulletns/2007/04apr/BLTN06014/BLTN06014.HTM Oil and gas geochemistry and petroleum systems of the Fort Worth Basin], AAPG Bulletin Special Issue: AAPG Bulletin, v. 91, no. 4, p. 445–473, doi:10.1306/11030606014.</ref>

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.<ref>Hill, R. J., D. M. Jarvie, R. M. Pollastro, M. Henry, and J. D. King, 2007, [http://archives.datapages.com/data/bulletns/2007/04apr/BLTN06014/BLTN06014.HTM Oil and gas geochemistry and petroleum systems of the Fort Worth Basin], AAPG Bulletin Special Issue: AAPG Bulletin, v. 91, no. 4, p. 445–473, doi:10.1306/11030606014.</ref>

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 ([[:File:M97Ch1.2FG12.jpg|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 play|Barnett Shale]], as TOC increases, carbonate carbon content generally decreases ([[:File:M97Ch1.2FG12.jpg|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.

In the Powder River Basin, there has been success in producing oil from the Lower Cretaceous Mowry Shale.<ref name=IHSENOD2010 /> 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.<ref name=IHSENOD2010 /> 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.<ref name=IHSENOD2010 /> 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.<ref name=IHSENOD2010 /> 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.

The present-day TOC (TOCpd) values for the Mowry Shale only average 1.95%, with an estimated original TOC (TOCo) of 2.43%. The original hydrogen index (HIo) values average about 183 mg HC/g TOC, with a range from 128 to 400 mg/g. Based on the expulsion curves of Pepper<ref name=Ppper1992 /> based on original hydrogen index (HIo) values, such a system will expel between 0 and 50% of its generated products and, therefore, should retain a high percentage of generated products. At higher thermal maturities, peak to late oil window, the oil quality should be condensate-like in terms of API gravity. Oil crossover effect is noted in various intervals in Mowry Shale wells, but also in the underlying Muddy Formation sands that are produced as conventional reservoirs.

The present-day TOC (TOCpd) values for the Mowry Shale only average 1.95%, with an estimated original TOC (TOCo) of 2.43%. The original [[hydrogen index]] (HIo) values average about 183 mg HC/g TOC, with a range from 128 to 400 mg/g. Based on the expulsion curves of Pepper<ref name=Ppper1992 /> based on original hydrogen index (HIo) values, such a system will expel between 0 and 50% of its generated products and, therefore, should retain a high percentage of generated products. At higher thermal maturities, peak to late oil window, the oil quality should be condensate-like in terms of API gravity. Oil crossover effect is noted in various intervals in Mowry Shale wells, but also in the underlying Muddy Formation sands that are produced as conventional reservoirs.

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) ([[:File:M97Ch1.2FG13.jpg|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) ([[:File:M97Ch1.2FG13.jpg|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.

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

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

Age-equivalent (Leonardian) Bone Springs and Avalon shales are found primarily in the Permian Basin in New Mexico but extend into central western Texas. This system represents a hybrid shale-oil resource system with organic-rich carbonate source rocks interbedded with sands and silts with a thickness of about 1066.8 m (3500 ft) and porosities ranging from 0 to 20% predominantly at about 10%. Depth to this resource system ranges from 1981.2 to 2743.2 m (6500–9000 ft). Geochemical data collected on the Bone Springs Shale show a TOCpd range of 2.09 to 6.98% at about 50% conversion,<ref name=Jrv2001b>Jarvie, D. M., J. D. Burgess, A. Morelos, R. K. Olson, P. A. Mariotti, and R. Lindsey, 2001b, [http://www.wwgeochem.co/references/Jarvieetal-AAPGAmarillo2001-PermianBasinPetroleumSystem.pdf Permian Basin petroleum systems investigations: Inferences from oil geochemistry and source rocks]: AAPG Midcontinent Section Meeting, Amarillo, Texas, September 30–October 2, 2001: AAPG Bulletin, v. 85, no. 9, p. 1693–1694.</ref> suggesting TOCo values of 2.79 to 9.31%. Carbonate contents span the full gamut of values ranging from as low as 5% to 100%. Oil crossover is noted in various Bone Springs and Avalon argillaceous lime mudstone intervals.

Age-equivalent (Leonardian) Bone Springs and Avalon shales are found primarily in the [[Permian Basin]] in New Mexico but extend into central western Texas. This system represents a hybrid shale-oil resource system with organic-rich carbonate source rocks interbedded with sands and silts with a thickness of about 1066.8 m (3500 ft) and porosities ranging from 0 to 20% predominantly at about 10%. Depth to this resource system ranges from 1981.2 to 2743.2 m (6500–9000 ft). Geochemical data collected on the Bone Springs Shale show a TOCpd range of 2.09 to 6.98% at about 50% conversion,<ref name=Jrv2001b>Jarvie, D. M., J. D. Burgess, A. Morelos, R. K. Olson, P. A. Mariotti, and R. Lindsey, 2001b, [http://www.wwgeochem.co/references/Jarvieetal-AAPGAmarillo2001-PermianBasinPetroleumSystem.pdf Permian Basin petroleum systems investigations: Inferences from oil geochemistry and source rocks]: AAPG Midcontinent Section Meeting, Amarillo, Texas, September 30–October 2, 2001: AAPG Bulletin, v. 85, no. 9, p. 1693–1694.</ref> suggesting TOCo values of 2.79 to 9.31%. Carbonate contents span the full gamut of values ranging from as low as 5% to 100%. Oil crossover is noted in various Bone Springs and Avalon argillaceous lime mudstone intervals.

Chesapeake Energy Corp. predicts that its Avalon Shale play will yield about 5.406 times 107 m3 (340 million) barrels of oil equivalent (BOE), whereas EOG Resources projects that its properties have a resource potential of about 1.033 times 107 m3 (65 million) BOE. Devon Energy Corp.'s best Avalon Shale wells have had initial production rates of more than 79 m3/day (500 bbl/day) of condensate, 79 m3/day (500 bbl/day) of natural gas liquids (NGL), and 8.5 to 1.41 times 104 m3/day (3–5 mmcf/day) of gas.

Chesapeake Energy Corp. predicts that its Avalon Shale play will yield about 5.406 times 107 m3 (340 million) barrels of oil equivalent (BOE), whereas EOG Resources projects that its properties have a resource potential of about 1.033 times 107 m3 (65 million) BOE. Devon Energy Corp.'s best Avalon Shale wells have had initial production rates of more than 79 m3/day (500 bbl/day) of condensate, 79 m3/day (500 bbl/day) of natural gas liquids (NGL), and 8.5 to 1.41 times 104 m3/day (3–5 mmcf/day) of gas.

==References cited==

==References cited==

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