Changes

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

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

These systems are classified as (1) organic-rich mudstones without open fractures, (2) organic-rich mudstones with open fractures, and (3) hybrid systems that have juxtaposed, continuous organic-rich and organic-lean intervals ([[: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: EOG_2010], 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.

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.

[[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).]]

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

Although 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]) (L. C. Price, 1997, personal communication; Price et al., 1998; L. Wenger, 2010, personal communication) 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 (Jarvie and Jarvie, 2007).

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>; L. Wenger, 2010, personal communication) 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 (Jarvie and Jarvie, 2007).

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 biomarker data suggest migration, light hydrocarbon data (n-C6 and n-C7 and isomers) in the Bakken Shale show some geochemical traits that are similar to produced oil, suggesting that some localized upper Bakken Shale-sourced oil is being produced along with slightly more mature oil (Jarvie et al., 2011). In fact, the distribution of light hydrocarbons correlates closely to oils produced from Lodgepole Mound oils in Stark County, North Dakota, that are among the lowest maturity Bakken Shale-sourced oils (Jarvie, 2001). The GOR values at the Parshall field are quite low, approximately 71.2 m3/m3 (400 scf/bbl), whereas nearby Sanish field oils are approximately 142.5 m3/m3 (800 scf/bbl). However, both oils are about 42deg API. The GOR values calculated from rock extract fingerprints using the oil-derived formulation of Mango and Jarvie (2001) measured on the upper Bakken Shale rock extracts average 68.4 m3/m3 (384 scf/bbl) for the Parshall field and about 155.3 m3/m3 (872 scf/bbl) for the Sanish field, agreeing with reported values for the produced oils (Jarvie, 2011). These data suggest a very localized source.

Although biomarker data suggest migration, light hydrocarbon data (n-C6 and n-C7 and isomers) in the Bakken Shale show some geochemical traits that are similar to produced oil, suggesting that some localized upper Bakken Shale-sourced oil is being produced along with slightly more mature oil (Jarvie et al., 2011). In fact, the distribution of light hydrocarbons correlates closely to oils produced from Lodgepole Mound oils in Stark County, North Dakota, that are among the lowest maturity Bakken Shale-sourced oils (Jarvie, 2001). The GOR values at the Parshall field are quite low, approximately 71.2 m3/m3 (400 scf/bbl), whereas nearby Sanish field oils are approximately 142.5 m3/m3 (800 scf/bbl). However, both oils are about 42deg API. The GOR values calculated from rock extract fingerprints using the oil-derived formulation of Mango and Jarvie (2001) measured on the upper Bakken Shale rock extracts average 68.4 m3/m3 (384 scf/bbl) for the Parshall field and about 155.3 m3/m3 (872 scf/bbl) for the Sanish field, agreeing with reported values for the produced oils (Jarvie, 2011). These data suggest a very localized source.

Published data tables from the North Dakota Geological Survey (2008) show the oil crossover effect in samples from the Middle Bakken and Three Forks Formation (Figure 6A, B). As previously shown by Price et al. (1984), the reduction of hydrogen indices in the hotter parts of the basin is indicative of generation and expulsion. The whereabouts of the charge was uncertain, but the oil crossover effect in panels A and B of Figure 6 shows that a lot of oil was charged into the Middle Member and Three Forks formations. Only a few upper and lower Bakken shales show the oil crossover effect, with typical values between 20 and 70 mg oil/g TOC indicative of residual oil saturation after expulsion.

Published data tables from the North Dakota Geological Survey (2008) show the oil crossover effect in samples from the Middle Bakken and Three Forks Formation (Figure 6A, B). As previously shown by Price et al.,<ref>Price, L. C., T. Ging, T. Daws, A. Love, M. Pawlewicz, and D. Anders, 1984, Organic metamorphism in the Mississippian–Devonian Bakken Shale, North Dakota portion of the Williston Basin, in J. Woodward, F. F. Meissner, and J. L. Clayton, eds., Hydrocarbon source rocks of the greater Rocky Mountain region: Denver, Colorado, Rocky Mountain Association of Geologists, p. 83–133.</ref> the reduction of hydrogen indices in the hotter parts of the basin is indicative of generation and expulsion. The whereabouts of the charge was uncertain, but the oil crossover effect in panels A and B of Figure 6 shows that a lot of oil was charged into the Middle Member and Three Forks formations. Only a few upper and lower Bakken shales show the oil crossover effect, with typical values between 20 and 70 mg oil/g TOC indicative of residual oil saturation after expulsion.

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

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

* Pepper, A. S., and P. J. Corvi, 1995, Simple models of petroleum formation. Part I: Oil and gas generation from kerogen: Marine and Petroleum Geology, v. 12, p. 291–320.

* Pepper, A. S., and P. J. Corvi, 1995, Simple models of petroleum formation. Part I: Oil and gas generation from kerogen: Marine and Petroleum Geology, v. 12, p. 291–320.

*  

*  

* Rasmussen, L., T. Smith, L. Canter, M. Sonnenfeld, and J. Forster, 2010, 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: http://www.searchanddiscovery.net/abstracts/pdf/2010/rms/abstracts/ndx_rasmussen03.pdf (accessed November 12, 2010).

* Rasmussen, L., T. Smith, L. Canter, M. Sonnenfeld, and J. Forster, 2010, 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: http://www.searchanddiscovery.net/abstracts/pdf/2010/rms/abstracts/ndx_rasmussen03.pdf (accessed November 12, 2010).

* Reed, R., and R. Loucks, 2007, Imaging nanoscale pores in the Mississippian Barnett Shale of the northern Fort Worth Basin: AAPG Annual Convention, Long Beach, California, April 1–4, 2007: http://www.searchanddiscovery.net/abstracts/html/2007/annual/abstracts/lbReed.htm?q=%2Btext%3Ananopores (accessed November 12, 2010).

* Reed, R., and R. Loucks, 2007, Imaging nanoscale pores in the Mississippian Barnett Shale of the northern Fort Worth Basin: AAPG Annual Convention, Long Beach, California, April 1–4, 2007: http://www.searchanddiscovery.net/abstracts/html/2007/annual/abstracts/lbReed.htm?q=%2Btext%3Ananopores (accessed November 12, 2010).