Changes

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 (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<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. (1992), 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. (1992) 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.

The interaction between the molecules in a shale-oil resource system is principally that of physical, chemical bonding. The behavior of the system is different in situations where the condensed phase has a fixed solid structure to which the volatile substance adheres, as opposed to cases where the condensed phase is a fluid, which (by definition) does not have a rigid solid structure. Inasmuch as sedimentary organic matter may be composed of both liquid or solid components, and quite commonly a heterogeneous mixture of both, then both processes of physical bonding (adsorption and solvation [commonly called absorption]) may be presumed to occur. Adsorption and solvation both entail some degree of solvent swelling, by which the molecular surface area available for physical bonding actually increases in the presence of the volatile substance. Inasmuch as these adsorption and solvation processes cannot easily be discriminated and the degree of solvent swelling is commonly unknown, the term sorption, instead of adsorption, is commonly used (J. Levine, 2010, personal communication).

The interaction between the molecules in a shale-oil resource system is principally that of physical, chemical bonding. The behavior of the system is different in situations where the condensed phase has a fixed solid structure to which the volatile substance adheres, as opposed to cases where the condensed phase is a fluid, which (by definition) does not have a rigid solid structure. Inasmuch as sedimentary organic matter may be composed of both liquid or solid components, and quite commonly a heterogeneous mixture of both, then both processes of physical bonding (adsorption and solvation [commonly called absorption]) may be presumed to occur. Adsorption and solvation both entail some degree of solvent swelling, by which the molecular surface area available for physical bonding actually increases in the presence of the volatile substance. Inasmuch as these adsorption and solvation processes cannot easily be discriminated and the degree of solvent swelling is commonly unknown, the term sorption, instead of adsorption, is commonly used.<ref>J. Levine, 2010, personal communication</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 (e.g., Baker, 1962). With the advent of the Rock-Eval with TOC instrument (Espitalie et al., 1984), 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 (Jarvie and Baker, 1984). 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 (Reed and Loucks, 2007; Loucks et al., 2009) that were described as microreservoirs by Barker (1974). 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 (Espitalie et al., 1984), 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

==Oil crossover effect==

==Oil crossover effect==

[[File:M97Ch1.2FG2.jpg|thumb|500px|{{figure number|2}}Example of oil crossover effect in productive Bazhenov Shale, West Siberian Basin, Russia. Data derived from graphic plots in Lopatin et al. (2003) illustrate that when free oil from Rock-Eval measured oil content (S1) exceeds total organic carbon (TOC) on an absolute basis, potentially producible oil is present. The oil saturation index (OSI) is simply (S1 times 100)/TOC, giving results in mg HC/g TOC. As such, when the OSI is greater than 100 mg/g, potentially producible oil is present (Jarvie and Baker, 1984).]]

[[File:M97Ch1.2FG2.jpg|thumb|500px|{{figure number|2}}Example of oil crossover effect in productive Bazhenov Shale, West Siberian Basin, Russia. Data derived from graphic plots in Lopatin et al. (2003) illustrate that when free oil from Rock-Eval measured oil content (S1) exceeds total organic carbon (TOC) on an absolute basis, potentially producible oil is present. The oil saturation index (OSI) is simply (S1 times 100)/TOC, giving results in mg HC/g TOC. As such, when the OSI is greater than 100 mg/g, potentially producible oil is present.<ref name=J&B1984 />]]

A geochemical indication of potentially producible oil is indicated by the oil crossover effect, that is, the crossover of oil content, either Rock-Eval S1 or EOM relative to organic richness (TOC, absolute values), or when the oil saturation index (OSI) (S1 times 100/TOC) reaches a value of about 100 mg hydrocarbons (HC)/g TOC. This is illustrated by graphic results describing Upper Jurassic Bazhenov Shale open-fractured shale-oil production. These data values are derived from the graphic of Lopatin et al. (2003) for Bazhenov shales in the 11-18-Maslikhov well, and they clearly show the oil crossover effect and the productive intervals (Figure 2). Such high crossover in an organic-rich shale is indicative of an open-fracture network.

A geochemical indication of potentially producible oil is indicated by the oil crossover effect, that is, the crossover of oil content, either Rock-Eval S1 or EOM relative to organic richness (TOC, absolute values), or when the oil saturation index (OSI) (S1 times 100/TOC) reaches a value of about 100 mg hydrocarbons (HC)/g TOC. This is illustrated by graphic results describing Upper Jurassic Bazhenov Shale open-fractured shale-oil production. These data values are derived from the graphic of Lopatin et al. (2003) for Bazhenov shales in the 11-18-Maslikhov well, and they clearly show the oil crossover effect and the productive intervals (Figure 2). Such high crossover in an organic-rich shale is indicative of an open-fracture network.

Rock-Eval S1 or EOM yields alone have little meaning in assessing potential production because they do not account for the organic background. For example, coals might have an S1 value of 10 mg HC/g rock, but with a TOC of 50% or higher, the OSI is quite low, indicative of low oil saturation with a high expulsion or production threshold.

Rock-Eval S1 or EOM yields alone have little meaning in assessing potential production because they do not account for the organic background. For example, coals might have an S1 value of 10 mg HC/g rock, but with a TOC of 50% or higher, the OSI is quite low, indicative of low oil saturation with a high expulsion or production threshold.

An empirical value exceeding 100 mg oil/g TOC was used to identify potential reservoir intervals in a conventional reservoir in the Anadarko Basin (Jarvie and Baker, 1984) and similarly in vertical Monterey Formation wells (Jarvie et al., 1995). Data from Sandvik et al. (1992) and similarly by Pepper (1992) suggest organic matter retains a portion of generated petroleum cited by both authors to be about 10 g of liquids sorbed per 100 g organic matter, that is, 100 mg HC/g TOC. Thus, there is a resistance to oil flow until the sorption threshold is exceeded, that is, values of OSI greater than 100 mg hydrocarbons per g of TOC. As Rock-Eval S1 is not a live oil quantitation, but instead a variably preserved rock-oil system, there is certainly loss of light oil due to evaporation, sample handling, and preparation before analysis. Loss of S1 is often estimated to be 35% (Cooles et al., 1986), but it is highly dependent on organic richness, lithofacies, oil type (light or heavy), and sample preservation. Organic-lean rocks such as sands, silts, and carbonates as found in conventional reservoirs would have a much higher loss than organic-rich, low-permeability mudstones. Drying samples in an oven will certainly impact the free oil content in Rock-Eval S1. Oil-based mud systems preclude the use of the Rock-Eval S1 and OSI.

An empirical value exceeding 100 mg oil/g TOC was used to identify potential reservoir intervals in a conventional reservoir in the Anadarko Basin<ref name=J&B1984 /> and similarly in vertical Monterey Formation wells (Jarvie et al., 1995). Data from Sandvik et al.<ref name=Sndvk1992 /> and similarly by Pepper (1992) suggest organic matter retains a portion of generated petroleum cited by both authors to be about 10 g of liquids sorbed per 100 g organic matter, that is, 100 mg HC/g TOC. Thus, there is a resistance to oil flow until the sorption threshold is exceeded, that is, values of OSI greater than 100 mg hydrocarbons per g of TOC. As Rock-Eval S1 is not a live oil quantitation, but instead a variably preserved rock-oil system, there is certainly loss of light oil due to evaporation, sample handling, and preparation before analysis. Loss of S1 is often estimated to be 35% (Cooles et al., 1986), but it is highly dependent on organic richness, lithofacies, oil type (light or heavy), and sample preservation. Organic-lean rocks such as sands, silts, and carbonates as found in conventional reservoirs would have a much higher loss than organic-rich, low-permeability mudstones. Drying samples in an oven will certainly impact the free oil content in Rock-Eval S1. Oil-based mud systems preclude the use of the Rock-Eval S1 and OSI.

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.

==References cited==

==References cited==

{{reflist}}

{{reflist}}

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* Barker, C., 1974, Pyrolysis techniques for source rock evaluation: AAPG Bulletin, v. 58, no. 11, p. 2349–2361.

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* 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.

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* TAG Oil, 2010: http://www.tagoil.com/fractured-shale.asp (accessed August 27, 2010).

* TAG Oil, 2010: http://www.tagoil.com/fractured-shale.asp (accessed August 27, 2010).