Changes

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; Welte and Leythauser, 1984), 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 (Surdam et al., 1988) 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 (Pitman et al., 2001). The acid source is presumed to be organic acids released during kerogen diagenesis (Pitman et al., 2001), 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]) (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).

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. (1998), 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 (2008) 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 (2008) noted the potential of alkanes to be converted to acids.

* Pepper, A. S., 1992, Estimating the petroleum expulsion behavior of source rocks: A novel quantitative approach, in W. A. England and A. L. Fleet, eds., Petroleum migration: Geological Society (London) Special Publication 59, p. 9–31.

* Pepper, A. S., 1992, Estimating the petroleum expulsion behavior of source rocks: A novel quantitative approach, in W. A. England and A. L. Fleet, eds., Petroleum migration: Geological Society (London) Special Publication 59, p. 9–31.

* 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.

* 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.

*  

* 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.

* 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.

* 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.

* 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.

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

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

* 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.

* 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.

* Surdam, R. C., L. J. Crossey, E. Sven Hagen, and H. P. Heasler, 1989, Organic-Inorganic interactions and sandstone diagenesis: AAPG Bulletin, v. 73, no. 1, p. 1–23.

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