Changes

==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 (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.

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

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<ref name=J&B1984 /> and similarly in vertical Monterey Formation wells.<ref name=Jrvetal1995>Jarvie, D. M., J. T. Senftle, W. Hughes, L. Dzou, J. J. Emme, and R. J. Elsinger, 1995, [http://wwgeochem.com/references/Jarvieetal1995Examplesandnewapplicationsinapplyingorganicgeochemistry.pdf Examples and new applications in applying organic geochemistry for detection and qualitative assessment of overlooked petroleum reservoirs], in J. O. Grimalt and C. Dorronsoro, eds., Organic geochemistry: Developments and applications to energy, climate, environment, and human history: 17th International Meeting on Organic Geochemistry, p. 380–382.</ref> Data from Sandvik et al.<ref name=Sndvk1992 /> and similarly by Pepper<ref name=Ppper1992>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.</ref> 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.<ref name=Jrvetal1995>Jarvie, D. M., J. T. Senftle, W. Hughes, L. Dzou, J. J. Emme, and R. J. Elsinger, 1995, [http://wwgeochem.com/references/Jarvieetal1995Examplesandnewapplicationsinapplyingorganicgeochemistry.pdf Examples and new applications in applying organic geochemistry for detection and qualitative assessment of overlooked petroleum reservoirs], in J. O. Grimalt and C. Dorronsoro, eds., Organic geochemistry: Developments and applications to energy, climate, environment, and human history: 17th International Meeting on Organic Geochemistry, p. 380–382.</ref> Data from Sandvik et al.<ref name=Sndvk1992 /> and similarly by Pepper<ref name=Ppper1992>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.</ref> 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%<ref>Cooles, G. P., A. S. Mackenzie, and T. M. Quigley, 1986, Calculation of petroleum masses generated and expelled from source rocks: Organic Geochemistry, v. 10, p. 235–245, doi:10.1016/0146-6380(86)90026-4.</ref>, 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.

The Upper Mississippian Heath Shale in the Central Montana trough is a candidate shale-oil resource system. This system is a fractured shale-oil play with higher porosity and some vertical wells have flowed 200 bbl/day.<ref name=O&G2010a>Oil & Gas Journal, 2010a, [http://www.ogj.com/index/article-display.articles.oil-gas-journal.exploration-development-2.2010.08.montana-heath_shale.QP129867.dcmp=rss.page=1.html Montana Heath Shale oil potential due tests].</ref>

The Upper Mississippian Heath Shale in the Central Montana trough is a candidate shale-oil resource system. This system is a fractured shale-oil play with higher porosity and some vertical wells have flowed 200 bbl/day.<ref name=O&G2010a>Oil & Gas Journal, 2010a, [http://www.ogj.com/index/article-display.articles.oil-gas-journal.exploration-development-2.2010.08.montana-heath_shale.QP129867.dcmp=rss.page=1.html Montana Heath Shale oil potential due tests].</ref>

The TOC data from Cole and Drozd (1994) show an average TOC of 7.6% on 32 core samples from Fergus County, Montana, although the authors state that the thickness of the source rock is less than 10 m (20–30 ft), with calcareous shales being the best source rock intervals. They also state that “a large part of generated hydrocarbons remained within the source rock interval” (p. 382). Thermal maturity values range from immature to late oil window primarily in parts of Musselshell, Rosebud, and Garfield counties (Cole and Drozd, 1994).

The TOC data from Cella and Drozd<ref name=C&D>Cella, G. A., and R. J. Drozd, 1994, [http://archives.datapages.com/data/specpubs/methodo2/data/a077/a077/0001/0350/0371.htm Heath-Tyler(!) petroleum system in central Montana], in L. B. Magoon and W. G. Dow, eds., The petroleum system: From source to trap: [http://store.aapg.org/detail.aspx?id=1022 AAPG Memoir 60], p. 371–385.</ref> show an average TOC of 7.6% on 32 core samples from Fergus County, Montana, although the authors state that the thickness of the source rock is less than 10 m (20–30 ft), with calcareous shales being the best source rock intervals. They also state that “a large part of generated hydrocarbons remained within the source rock interval” (p. 382). Thermal maturity values range from immature to late oil window primarily in parts of Musselshell, Rosebud, and Garfield counties.<ref name=C&D />

The Continental 1-Staunton well illustrates the variability in various geochemical characteristics of the Heath Shale. ([[:File:M97Ch1.2FG17.jpg|Figure 17]]). The average TOC value is 4.52% in this well, but the range is 0.20 to 13.66% with a high standard deviation of 5.20%. Carbonate carbon data are not available. The pyrolysis yields (present-day Rock-Eval measured kerogen [S2pd]) and HIpd are also highly variable, with HIpd values averaging 315 mg HC/g TOC, with a range of 137 to 523 mg HC/g TOC. Thermal maturity is early oil window with % Roe from Tmax values of 0.51 to 0.72%. Conversion of organic matter is thus likely about 10 to 20%.

The Continental 1-Staunton well illustrates the variability in various geochemical characteristics of the Heath Shale. ([[:File:M97Ch1.2FG17.jpg|Figure 17]]). The average TOC value is 4.52% in this well, but the range is 0.20 to 13.66% with a high standard deviation of 5.20%. Carbonate carbon data are not available. The pyrolysis yields (present-day Rock-Eval measured kerogen [S2pd]) and HIpd are also highly variable, with HIpd values averaging 315 mg HC/g TOC, with a range of 137 to 523 mg HC/g TOC. Thermal maturity is early oil window with % Roe from Tmax values of 0.51 to 0.72%. Conversion of organic matter is thus likely about 10 to 20%.

===Paris Basin, France===

===Paris Basin, France===

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M97Ch1.2FG20.jpg|{{figure number|20}}The oil crossover effect in the Toarcian Shale, Paris Basin, France. Data from Espitalie et al. (1988). TOC = total organic carbon.

M97Ch1.2FG20.jpg|{{figure number|20}}The oil crossover effect in the Toarcian Shale, Paris Basin, France. Data from Espitalie et al.<ref name=Esptl1988>Espitalie, J., J. R. Maxwell, P. Y. Chenet, and F. Marquis, 1988, Aspects of hydrocarbon migration in the Mesozoic in the Paris Basin as deduced from an organic geochemical survey, Advances in Organic Geochemistry 1987: Organic Geochemistry, v. 13, no. 1–3, p. 467–481, doi:10.1016/0146-6380(88)90068-X.</ref> TOC = total organic carbon.

M97Ch1.2FG21.jpg|{{figure number|21}}Geochemical log of the 1-Donnemarie well, Paris Basin, France. The oil crossover is apparent just below the organic-rich Toarcian Shale and also in a conventional Triassic sandstone reservoir that has been produced for about 20 yr. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.

M97Ch1.2FG21.jpg|{{figure number|21}}Geochemical log of the 1-Donnemarie well, Paris Basin, France. The oil crossover is apparent just below the organic-rich Toarcian Shale and also in a conventional Triassic sandstone reservoir that has been produced for about 20 yr. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.

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Recently, the Paris Basin of France is described as having shale-oil resource potential (Toreador Resources, 2010). Substantiating this, it has been recently announced that Vermillion Energy has achieved oil flow of 32 to 38deg API oil in Paris Basin Toarcian Shale (Vermillion Energy, 2010). The company reported porosity as high as 12%.

Recently, the Paris Basin of France is described as having shale-oil resource potential (Toreador Resources, 2010). Substantiating this, it has been recently announced that Vermillion Energy has achieved oil flow of 32 to 38deg API oil in Paris Basin Toarcian Shale (Vermillion Energy, 2010). The company reported porosity as high as 12%.

Average Toarcian Shale data from Espitalie et al. (1988) demonstrate the oil crossover effect (Figure 20). Furthermore, a geochemical log of a well from the Donnemarie field was constructed to illustrate the shale-oil system play (Figure 21). This log illustrates two reservoir systems: one proven conventional and an unproven unconventional. The oil crossover effect in this well is obvious between 3020 and 3240 m (sim9908–10,630 ft), where conventional Triassic sandstone production exists. Uphole from this conventional ongoing production, immediately below the organic-rich Toarcian Shale, a thick organic-lean interval is present in this well from 2465 to 2609 m (sim8087.2–8559.7 ft) where oil crossover occurs, indicative of an untested, but potential, hybrid shale-oil resource production. Given the source rock type, a marine shale, and conventionally produced oil quality elsewhere in the basin, oil in this interval would be expected to be more than 35deg API oil. The Toarcian Shale immediately above this zone of crossover has an average TOC of almost 2.00% and is in the earliest oil window at about 0.75% Roe (from Tmax). In addition, a Toarcian Shale sample at 2270 m (7447.8 ft) is organic rich (4.47% TOC) and exhibits very high oil content and oil crossover indicative of active generation and expulsion. A sample at 2530 m (8300.5 ft) does not show crossover, so it could be a seal between two free oil-saturated zones.

Average Toarcian Shale data from Espitalie et al.<ref name=Esptl1988 /> demonstrate the oil crossover effect (Figure 20). Furthermore, a geochemical log of a well from the Donnemarie field was constructed to illustrate the shale-oil system play (Figure 21). This log illustrates two reservoir systems: one proven conventional and an unproven unconventional. The oil crossover effect in this well is obvious between 3020 and 3240 m (sim9908–10,630 ft), where conventional Triassic sandstone production exists. Uphole from this conventional ongoing production, immediately below the organic-rich Toarcian Shale, a thick organic-lean interval is present in this well from 2465 to 2609 m (sim8087.2–8559.7 ft) where oil crossover occurs, indicative of an untested, but potential, hybrid shale-oil resource production. Given the source rock type, a marine shale, and conventionally produced oil quality elsewhere in the basin, oil in this interval would be expected to be more than 35deg API oil. The Toarcian Shale immediately above this zone of crossover has an average TOC of almost 2.00% and is in the earliest oil window at about 0.75% Roe (from Tmax). In addition, a Toarcian Shale sample at 2270 m (7447.8 ft) is organic rich (4.47% TOC) and exhibits very high oil content and oil crossover indicative of active generation and expulsion. A sample at 2530 m (8300.5 ft) does not show crossover, so it could be a seal between two free oil-saturated zones.

Although carbonate carbon data were not reported on these well samples, it is anticipated that the organic-lean oil crossover zone below the Toarcian Shale is likely carbonate rich based on literature lithofacies descriptions.

Although carbonate carbon data were not reported on these well samples, it is anticipated that the organic-lean oil crossover zone below the Toarcian Shale is likely carbonate rich based on literature lithofacies descriptions.

In Latin America, various organic-rich shales that have sourced conventional oil reservoirs are potential targets for shale-oil resource systems. For example, the La Luna Shale of Colombia is one of the most obvious potential targets. The Upper Jurassic–Lower Cretaceous Vaca Muerta Shale is being pursued for its resource potential in the Neuquin Basin, Argentina. Other source rocks in the Neuquin Basin may also have potential shale-oil resources, such as the Lower to Middle Jurassic Los Molles Shale. A less known system is the Devonian Cordoba Shale of Uruguay. Other marine shale possibilities exist through most of Latin America.

In Latin America, various organic-rich shales that have sourced conventional oil reservoirs are potential targets for shale-oil resource systems. For example, the La Luna Shale of Colombia is one of the most obvious potential targets. The Upper Jurassic–Lower Cretaceous Vaca Muerta Shale is being pursued for its resource potential in the Neuquin Basin, Argentina. Other source rocks in the Neuquin Basin may also have potential shale-oil resources, such as the Lower to Middle Jurassic Los Molles Shale. A less known system is the Devonian Cordoba Shale of Uruguay. Other marine shale possibilities exist through most of Latin America.

TAG Oil has targeted a shale resource system from the uppermost Paleocene–lowermost Eocene Waipawa Black Shale and Upper Cretaceous–lowermost Paleocene Whangai fractured shale in New Zealand (TAG Oil, 2010). Permeabilities are typically from 10 to 200 microdarcys with 9 to 31% porosities (Francis, 2007). The gravity of oils is reported to be 50deg API (TAG Oil, 2010).

TAG Oil has targeted a shale resource system from the uppermost Paleocene–lowermost Eocene Waipawa Black Shale and Upper Cretaceous–lowermost Paleocene Whangai fractured shale in New Zealand.<ref name=TAGOIL>[http://www.tagoil.com/fractured-shale.asp TAG Oil], 2010.</ref> Permeabilities are typically from 10 to 200 microdarcys with 9 to 31% porosities.<ref>Francis, D., 2007, Reservoir analysis of Whangai Formation and Waipawa Black Shale: GNS New Zealand Government report, 11 p.</ref> The gravity of oils is reported to be 50deg API.<ref name=TAGOIL />

Thus, it is evident that production from not only shale-gas systems, but also shale-oil resource systems, will be a worldwide phenomenon. However, it is unlikely that shale-oil resource systems will have the dramatic impact of shale-gas resources unless knowledge and technologies are developed to extract the tightly retained oil in organic-rich mudstones.

Thus, it is evident that production from not only shale-gas systems, but also shale-oil resource systems, will be a worldwide phenomenon. However, it is unlikely that shale-oil resource systems will have the dramatic impact of shale-gas resources unless knowledge and technologies are developed to extract the tightly retained oil in organic-rich mudstones.

{{reflist}}

{{reflist}}

* Miranda, R. M., and C. C. Walters, 1992, Geochemical variations in sedimentary matter within a “homogeneous” shale core (Tuscaloosa Formation, Upper Cretaceous, Mississippi: Organic Geochemistry, v. 18, no. 6, p. 899–911, doi:10.1016/0146-6380(92)90057-5.

* Miranda, R. M., and C. C. Walters, 1992, Geochemical variations in sedimentary matter within a “homogeneous” shale core (Tuscaloosa Formation, Upper Cretaceous, Mississippi: Organic Geochemistry, v. 18, no. 6, p. 899–911, doi:10.1016/0146-6380(92)90057-5.

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* Riediger, C. L., M. G. Fowler, P. W. Brooks, and L. R. Snowdon, 1990, Triassic oils and potential Mesozoic source rocks: Peace River arch area, Western Canada Basin: Organic Geochemistry, v. 16, no. 1–3, p. 295–305, doi:10.1016/0146-6380(90)90049-6.

* Riediger, C. L., M. G. Fowler, P. W. Brooks, and L. R. Snowdon, 1990, Triassic oils and potential Mesozoic source rocks: Peace River arch area, Western Canada Basin: Organic Geochemistry, v. 16, no. 1–3, p. 295–305, doi:10.1016/0146-6380(90)90049-6.

* 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.

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* Toreador Resources: 2010, Paris Basin shale oil: Toreador taking the lead, Unconventional Oil 2010, October 12, 2010, London: http://www.toreador.net/images/presentations/Toreador_Unconventional_Oil_2010.pdf.

* Toreador Resources: 2010, Paris Basin shale oil: Toreador taking the lead, Unconventional Oil 2010, October 12, 2010, London: http://www.toreador.net/images/presentations/Toreador_Unconventional_Oil_2010.pdf.