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;<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>

==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