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[[File:M97FG2.jpg|thumb|400px|{{figure number|2}}Comparison of Montney Shale and Doig Phosphate in terms of total organic carbon (TOC) and porosity. The Montney Shale shows poor and inverse correlation to TOC, whereas the Doig Phosphate shows good and positive correlation indicative of organically derived porosity. The positive y-(porosity) intercept for the Doig indicates about 2% matrix porosity. The inverse correlation of the Montney Shale is suggestive of a hybrid system where porosity is derived primarily from matrix as opposed to organic porosity. BV = bulk volume; R2 = linear correlation coefficient.]]

[[File:M97FG2.jpg|thumb|400px|{{figure number|2}}Comparison of Montney Shale and Doig Phosphate in terms of total organic carbon (TOC) and porosity. The Montney Shale shows poor and inverse correlation to TOC, whereas the Doig Phosphate shows good and positive correlation indicative of organically derived porosity. The positive y-(porosity) intercept for the Doig indicates about 2% matrix porosity. The inverse correlation of the Montney Shale is suggestive of a hybrid system where porosity is derived primarily from matrix as opposed to organic porosity. BV = bulk volume; R2 = linear correlation coefficient.]]

What are the characteristics of these shale resource plays that caused them to be either overlooked or ignored? It was certainly not their source rock characteristics because most are organic-rich source rocks at varying levels of thermal maturity that have sourced conventional oil and gas fields in virtually every basin where they have been exploited. Although their petroleum source potential is well known, their rock properties were very unattractive for reservoir potential amplified by their recognition as not only source rocks, but also as seal or cap rocks, certifying their nonreservoir properties. However, their retention and storage capacity for petroleum was largely ignored and mud gas log responses noted with the somewhat derogatory shale-gas moniker. Because these shale resource plays were a combination of source rocks and seals, the retention of hydrocarbons is a factor that was overlooked. Diffusion, albeit a slow process, suggested that oil and especially gas were mostly lost from such rocks over geologic time. For example, modeling petroleum generation in the Barnett Shale indicates that maximum generation may have been reached 250 Ma (Jarvie et al., 2005a). Because of a complex burial and uplift history, maximum generation could have been reached about 25 Ma, but nonetheless, retention of generated hydrocarbons to the present day was not perceived as likely or certainly not to a commercial extent. As such, even in a good seal rock, diffusion should have resulted in a substantial loss of gas, thereby limiting the resource potential of the system. The presence of fractures, although healed, and the presence of conventional oil and gas reservoirs in the Fort Worth Basin, suggested that expulsion and diffusion had possibly drained the shale. In addition, gas contents measured on the MEDC 1-Sims well, 1991, were not very encouraging, suggesting non-commercial amounts of gas.<ref name=St2007 />

What are the characteristics of these shale resource plays that caused them to be either overlooked or ignored? It was certainly not their source rock characteristics because most are organic-rich source rocks at varying levels of thermal maturity that have sourced conventional oil and gas fields in virtually every basin where they have been exploited. Although their petroleum source potential is well known, their rock properties were very unattractive for reservoir potential amplified by their recognition as not only source rocks, but also as seal or cap rocks, certifying their nonreservoir properties. However, their retention and storage capacity for petroleum was largely ignored and mud gas log responses noted with the somewhat derogatory shale-gas moniker. Because these shale resource plays were a combination of source rocks and seals, the retention of hydrocarbons is a factor that was overlooked. Diffusion, albeit a slow process, suggested that oil and especially gas were mostly lost from such rocks over geologic time. For example, modeling petroleum generation in the Barnett Shale indicates that maximum generation may have been reached 250 Ma.<ref>Jarvie, D. M., R. J. Hill, and R. M. Pollastro, 2005a, Assessment of the gas potential and yields from shales: The Barnett Shale model, in B. Cardott, ed., Oklahoma Geological Survey circular 110, Unconventional Gas of the Southern Mid-Continent Symposium, March 9–10, 2005, Oklahoma City, Oklahoma, p. 37–50.</ref> Because of a complex burial and uplift history, maximum generation could have been reached about 25 Ma, but nonetheless, retention of generated hydrocarbons to the present day was not perceived as likely or certainly not to a commercial extent. As such, even in a good seal rock, diffusion should have resulted in a substantial loss of gas, thereby limiting the resource potential of the system. The presence of fractures, although healed, and the presence of conventional oil and gas reservoirs in the Fort Worth Basin, suggested that expulsion and diffusion had possibly drained the shale. In addition, gas contents measured on the MEDC 1-Sims well, 1991, were not very encouraging, suggesting non-commercial amounts of gas.<ref name=St2007 />

Overlooked were various characteristics of organic-rich mudstones. They certainly have the capacity to generate and expel hydrocarbons, but they also have retentive capacity and a self-created storage capacity. Data from Sandvik et al. (1992) and Pepper (1992) suggest that expulsion is a function of both original organic richness and hydrogen indices as they relate to a sorptive capacity of organic matter. The work by Pepper (1992) suggests that only about 60% of Barnett Shale petroleum should have been expelled, assuming an original hydrogen index (HIo) of 434 mg HC/g TOC. By difference, this suggests that 40% of the generated petroleum was retained in the Barnett Shale, with retained oil ultimately being cracked to gas and a carbonaceous char, if sufficient thermal maturity (gt1.4% vitrinite reflectance equivalency [Roe]) was reached. This retained fraction of primary and secondarily generated and retained gas readily accounts for all the gas in the Fort Worth Basin Barnett Shale (Jarvie et al., 2007).

Overlooked were various characteristics of organic-rich mudstones. They certainly have the capacity to generate and expel hydrocarbons, but they also have retentive capacity and a self-created storage capacity. Data from Sandvik et al. (1992) and Pepper (1992) suggest that expulsion is a function of both original organic richness and hydrogen indices as they relate to a sorptive capacity of organic matter. The work by Pepper (1992) suggests that only about 60% of Barnett Shale petroleum should have been expelled, assuming an original hydrogen index (HIo) of 434 mg HC/g TOC. By difference, this suggests that 40% of the generated petroleum was retained in the Barnett Shale, with retained oil ultimately being cracked to gas and a carbonaceous char, if sufficient thermal maturity (gt1.4% vitrinite reflectance equivalency [Roe]) was reached. This retained fraction of primary and secondarily generated and retained gas readily accounts for all the gas in the Fort Worth Basin Barnett Shale (Jarvie et al., 2007).

* Horsfield, B., R. Littke, U. Mann, S. Bernard, T. A. T. Vu, R. di Primio, and H-M. Schulz, 2010, [http://www.searchanddiscovery.net/documents/2010/110126horsfield/ndx_horsfield.pdf Shale gas in the Posidonia Shale, Hils area, Germany: Genesis of shale gas: Physicochemical and geochemical constraints affecting methane adsorption and desorption]: AAPG Annual Convention, New Orleans, Louisiana, April 11–14, 2010, Search and Discovery Article 110126, 33 p.

* Horsfield, B., R. Littke, U. Mann, S. Bernard, T. A. T. Vu, R. di Primio, and H-M. Schulz, 2010, [http://www.searchanddiscovery.net/documents/2010/110126horsfield/ndx_horsfield.pdf Shale gas in the Posidonia Shale, Hils area, Germany: Genesis of shale gas: Physicochemical and geochemical constraints affecting methane adsorption and desorption]: AAPG Annual Convention, New Orleans, Louisiana, April 11–14, 2010, Search and Discovery Article 110126, 33 p.

* Jarvie, B. M., D. M. Jarvie, T. E. Ruble, H. Alimi, and V. Baum, 2006, [http://wwgeochem.com/references/jarviebrianetaldetailedgeochemicalevaluationofgreenrivershalecoreAAPG2006.pdf Detailed geochemical evaluation of Green River shale core: Implication for an unconventional source of hydrocarbons (abs.)]: AAPG Annual Meeting, Houston, Texas, April 9–12, 2006, v. 90

* Jarvie, B. M., D. M. Jarvie, T. E. Ruble, H. Alimi, and V. Baum, 2006, [http://wwgeochem.com/references/jarviebrianetaldetailedgeochemicalevaluationofgreenrivershalecoreAAPG2006.pdf Detailed geochemical evaluation of Green River shale core: Implication for an unconventional source of hydrocarbons (abs.)]: AAPG Annual Meeting, Houston, Texas, April 9–12, 2006, v. 90

* Jarvie, D. M., R. J. Hill, and R. M. Pollastro, 2005a, Assessment of the gas potential and yields from shales: The Barnett Shale model, in B. Cardott, ed., Oklahoma Geological Survey circular 110, Unconventional Gas of the Southern Mid-Continent Symposium, March 9–10, 2005, Oklahoma City, Oklahoma, p. 37–50.

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* Jarvie, D. M., R. J. Hill, R. M. Pollastro, D. A. Wavrek, K. A. Bowker, B. L. Claxton, and M. H. Tobey, 2005b, [http://wwgeochem.com/references/Jarvie-etal2005bcharacterizationofthermogenicgasandoilFtWorthBasinTexasEAGE-Algiers.pdf Characterization of thermogenic gas and oil in the Ft. Worth Basin, Texas]: European Association of Geoscientists and Engineers Meeting, Algiers, Algeria, April 8–10, 2005.

* Jarvie, D. M., R. J. Hill, R. M. Pollastro, D. A. Wavrek, K. A. Bowker, B. L. Claxton, and M. H. Tobey, 2005b, [http://wwgeochem.com/references/Jarvie-etal2005bcharacterizationofthermogenicgasandoilFtWorthBasinTexasEAGE-Algiers.pdf Characterization of thermogenic gas and oil in the Ft. Worth Basin, Texas]: European Association of Geoscientists and Engineers Meeting, Algiers, Algeria, April 8–10, 2005.

* Jarvie, D. M., R. J. Hill, T. E. Ruble, and R. M. Pollastro, 2007, Unconventional shale gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale gas assessment, in R. J. Hill and D. M. Jarvie, eds., AAPG Bulletin Special Issue: Barnett Shale: v. 90, no. 4, p. 475–499.

* Jarvie, D. M., R. J. Hill, T. E. Ruble, and R. M. Pollastro, 2007, Unconventional shale gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale gas assessment, in R. J. Hill and D. M. Jarvie, eds., AAPG Bulletin Special Issue: Barnett Shale: v. 90, no. 4, p. 475–499.