Changes

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 />

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.<ref>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> and Pepper<ref name=Pppr1992>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 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<ref name=Pppr1992 /> 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.<ref name=Jrv2007>Jarvie, D. M., R. J. Hill, T. E. Ruble, and R. M. Pollastro, 2007, [http://archives.datapages.com/data/bulletns/2007/04apr/BLTN06068/BLTN06068.HTM 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.</ref>

In addition, work by Reed and Loucks (2007) and Loucks et al. (2009) showed that the development of organic porosity was a feature of Barnett Shale organic matter at gas window thermal maturity. This was speculated to provide a means of storage by Jarvie et al. (2006) because of the conversion of organic matter to gas and oil, some of which was expelled, ultimately creating pores associated with organic matter. Conversion of TOC from mass to volume shows that such organic porosity can be accounted for by organic matter conversion (Jarvie et al., 2007). Likewise, it was shown that such limited porosity (4–7%) can store sufficient gas under pressure-volume-temperature (PVT) conditions to account for the high volumes of gas in place (GIP) in the Barnett Shale. In fact, it is postulated that PVT conditions during maximum petroleum generation 250 Ma were much higher than the present day, and despite uplift, the gas storage capacity is actually higher than present-day PVT conditions would suggest. If any liquids are present, however, condensation of petroleum occurs to accommodate the fixed volume under the lower temperature and pressure conditions after uplift. As such, a two-phase petroleum system exists, and this is an important consideration, not only for the Barnett Shale, but also for other resource systems containing both liquid and gas whereby liquids can condense on pressure drawdown.

In addition, work by Reed and Loucks (2007) and Loucks et al. (2009) showed that the development of organic porosity was a feature of Barnett Shale organic matter at gas window thermal maturity. This was speculated to provide a means of storage by Jarvie et al. (2006) because of the conversion of organic matter to gas and oil, some of which was expelled, ultimately creating pores associated with organic matter. Conversion of TOC from mass to volume shows that such organic porosity can be accounted for by organic matter conversion.<ref name=Jrv2007 /> Likewise, it was shown that such limited porosity (4–7%) can store sufficient gas under pressure-volume-temperature (PVT) conditions to account for the high volumes of gas in place (GIP) in the Barnett Shale. In fact, it is postulated that PVT conditions during maximum petroleum generation 250 Ma were much higher than the present day, and despite uplift, the gas storage capacity is actually higher than present-day PVT conditions would suggest. If any liquids are present, however, condensation of petroleum occurs to accommodate the fixed volume under the lower temperature and pressure conditions after uplift. As such, a two-phase petroleum system exists, and this is an important consideration, not only for the Barnett Shale, but also for other resource systems containing both liquid and gas whereby liquids can condense on pressure drawdown.

Proof of the Barnett Shale-gas resource potential was substantiated by the MEDC 3-Kathy Keele well (now named the K. P. Lipscomb 3-GU) drilled in 1999, where pressure core was taken.<ref name=St2007 /> The result was an estimate of 2.13 times 109 m3/km2 (195 bcf/section), which exceeded previous estimates by about 250%.

Proof of the Barnett Shale-gas resource potential was substantiated by the MEDC 3-Kathy Keele well (now named the K. P. Lipscomb 3-GU) drilled in 1999, where pressure core was taken.<ref name=St2007 /> The result was an estimate of 2.13 times 109 m3/km2 (195 bcf/section), which exceeded previous estimates by about 250%.

</gallery>

</gallery>

Multiple ways to derive an original TOC (TOCo) value exist, two of which are (1) from a database or analysis of immature samples, thereby allowing the percentage of kerogen conversion to be estimated; and (2) by computation from visual kerogen assessments and related HI assumptions (Jarvie et al., 2007). However, it is difficult to assign an original HI (HI_o) to any source rock system in the absence of a collection of immature source rocks from various locations or even by measuring maceral percentages. For example, to assume all lacustrine shales such as the Green River Oil Shale have an HI_o of 700 or higher, or that all are equivalent to the Mahogany zone (950 mg HC/g TOC), is inconsistent with measured values that range from about 50 to 950 mg/g, with an average of only 534 mg HC/g TOC (Jarvie et al., 2006). Thus, our previous selection of 700 mg HC/g TOC for type I kerogen is likely overstated (Jarvie et al. 2007), and a comparable issue exists for organic matter categorized as a type II marine shale.

Multiple ways to derive an original TOC (TOCo) value exist, two of which are (1) from a database or analysis of immature samples, thereby allowing the percentage of kerogen conversion to be estimated; and (2) by computation from visual kerogen assessments and related HI assumptions.<ref name=Jrv2007 /> However, it is difficult to assign an original HI (HI_o) to any source rock system in the absence of a collection of immature source rocks from various locations or even by measuring maceral percentages. For example, to assume all lacustrine shales such as the Green River Oil Shale have an HI_o of 700 or higher, or that all are equivalent to the Mahogany zone (950 mg HC/g TOC), is inconsistent with measured values that range from about 50 to 950 mg/g, with an average of only 534 mg HC/g TOC (Jarvie et al., 2006). Thus, our previous selection of 700 mg HC/g TOC for type I kerogen is likely overstated,<ref name=Jrv2007 /> and a comparable issue exists for organic matter categorized as a type II marine shale.

As most shale-gas resource plays to date have been marine shales, comparison of HI_o values for a worldwide collection of marine source rocks provides a means to assess the range of expected values. Using a database of immature marine source rocks, the predominant distribution of HI_o values is between 300 and 700 mg HC/g TOC, although the population of samples yield a range from about 250 to 800 mg HC/g TOC ([[:File:M97FG3.jpg|Figure 3]]). This is similar to, but broader than, the range of values suggested by Peters and Caasa (1994) for type II kerogens of 300 to 600 mg HC/g TOC and slightly broader than the range of values suggested by Jones (1984) of 300 to 700 mg HC/g TOC. The important point is that these are primarily marine shales with oil-prone kerogen with variable hydrogen contents. Lacustrine source rocks are not ruled out as potential shale-gas resource systems, but they likely require a much higher thermal maturity to crack their dominantly paraffin composition to gas; as of this date, no such systems have been commercially produced.

As most shale-gas resource plays to date have been marine shales, comparison of HI_o values for a worldwide collection of marine source rocks provides a means to assess the range of expected values. Using a database of immature marine source rocks, the predominant distribution of HI_o values is between 300 and 700 mg HC/g TOC, although the population of samples yield a range from about 250 to 800 mg HC/g TOC ([[:File:M97FG3.jpg|Figure 3]]). This is similar to, but broader than, the range of values suggested by Peters and Caasa (1994) for type II kerogens of 300 to 600 mg HC/g TOC and slightly broader than the range of values suggested by Jones (1984) of 300 to 700 mg HC/g TOC. The important point is that these are primarily marine shales with oil-prone kerogen with variable hydrogen contents. Lacustrine source rocks are not ruled out as potential shale-gas resource systems, but they likely require a much higher thermal maturity to crack their dominantly paraffin composition to gas; as of this date, no such systems have been commercially produced.

:<math>% \text{ of reactive carbon} = \text{HI}_{\text{o}} / 1177 </math>

:<math>% \text{ of reactive carbon} = \text{HI}_{\text{o}} / 1177 </math>

For example, if the HI_o of Barnett Shale is estimated to be 434 mg HC/g TOC (Jarvie et al., 2007), then dividing by 1177 mg/g yields the percentage of reactive carbon in the immature shale; that is, 37% of the TOCo could be converted to petroleum. As substantiation for this calculation, immature Barnett Shale outcrops from Lampasas County, Texas, average 36% reactive carbon, although the range of values is 29 to 43%. Similarly, data from Montgomery et al. (2005) suggest a 36% loss in TOCo on laboratory maturation of low-maturity Barnett Shale cuttings from Brown County, Texas. Likewise, immature Bakken Shale contains 60% GOC as carbon in Rock-Eval measured oil contents (S1) and measured kerogen yields (S2), which is consistent with an HI_o of 700 (59.5%).

For example, if the HI_o of Barnett Shale is estimated to be 434 mg HC/g TOC,<ref name=Jrv2007 /> then dividing by 1177 mg/g yields the percentage of reactive carbon in the immature shale; that is, 37% of the TOCo could be converted to petroleum. As substantiation for this calculation, immature Barnett Shale outcrops from Lampasas County, Texas, average 36% reactive carbon, although the range of values is 29 to 43%. Similarly, data from Montgomery et al. (2005) suggest a 36% loss in TOCo on laboratory maturation of low-maturity Barnett Shale cuttings from Brown County, Texas. Likewise, immature Bakken Shale contains 60% GOC as carbon in Rock-Eval measured oil contents (S1) and measured kerogen yields (S2), which is consistent with an HI_o of 700 (59.5%).

This relationship for calculating the amount of GOC is true for any immature source rock once HI_o is determined or estimated. Using this relationship with HI_o probabilities, the range of original GOC and NGOC percentages for any HI_o can be determined. The values for GOC and NGOC for P90, P50, and P10 are also shown in Table 1. These values should not be considered mutually exclusive for a single source rock. Subdividing various organofacies within a source rock, if any, should be a common practice for calculating volumes of hydrocarbon generated with each organofacies having its own thickness, HI_o, and TOCo. Ideally, these organofacies differences should be mappable in an area of study.

This relationship for calculating the amount of GOC is true for any immature source rock once HI_o is determined or estimated. Using this relationship with HI_o probabilities, the range of original GOC and NGOC percentages for any HI_o can be determined. The values for GOC and NGOC for P90, P50, and P10 are also shown in Table 1. These values should not be considered mutually exclusive for a single source rock. Subdividing various organofacies within a source rock, if any, should be a common practice for calculating volumes of hydrocarbon generated with each organofacies having its own thickness, HI_o, and TOCo. Ideally, these organofacies differences should be mappable in an area of study.

*  

*  

* 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.

*  

* Jones, R. W., 1984, Comparison of carbonate and shale source rocks, in J. Palacas, ed., Petroleum geochemistry and source rock potential of carbonate rocks: AAPG Studies in Geology 18, p. 163–180.

* Jones, R. W., 1984, Comparison of carbonate and shale source rocks, in J. Palacas, ed., Petroleum geochemistry and source rock potential of carbonate rocks: AAPG Studies in Geology 18, p. 163–180.

* Langford, F. F., and M.–M. Blanc-Valleron, 1990, Interpreting Rock-Eval pyrolysis data using graphs of pyrolizable hydrocarbons vs. total organic carbon: AAPG Bulletin, v. 74, no. 6, p. 799–804.

* Langford, F. F., and M.–M. Blanc-Valleron, 1990, Interpreting Rock-Eval pyrolysis data using graphs of pyrolizable hydrocarbons vs. total organic carbon: AAPG Bulletin, v. 74, no. 6, p. 799–804.

* Oil amp Gas Journal, 2010a, [http://www.ogj.com/index/article-tools-template/_printArticle/articles/oil-gas-journal/drilling-production-2/2010/08/north-africa_gets.html North Africa gets first shale gas frac job], August 30, 2010.

* Oil amp Gas Journal, 2010a, [http://www.ogj.com/index/article-tools-template/_printArticle/articles/oil-gas-journal/drilling-production-2/2010/08/north-africa_gets.html North Africa gets first shale gas frac job], August 30, 2010.

* Oil amp Gas Journal, 2010b, [http://www.ogj.com/index/article-tools-template.articles.oil-gas-journal.exploration-development-2.2010.07.south-africa_karoo.html South Africa Karoo shale gas hunt growing].

* Oil amp Gas Journal, 2010b, [http://www.ogj.com/index/article-tools-template.articles.oil-gas-journal.exploration-development-2.2010.07.south-africa_karoo.html South Africa Karoo shale gas hunt growing].

* 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.

*  

* Peters, K. E., and M. R. Caasa, 1994, Applied source rock geochemistry, in L. B. Magoon and W. G. Dow, eds., The petroleum system: From source to trap: AAPG Memoir 60, p. 93–117.

* Peters, K. E., and M. R. Caasa, 1994, Applied source rock geochemistry, in L. B. Magoon and W. G. Dow, eds., The petroleum system: From source to trap: AAPG Memoir 60, p. 93–117.

* Railroad Commission of Texas, 2011, [http://www.rrc.state.tx.us/meetings/ogpfd/RangePFD.PDF&sa=U&ei=WIAQT9DPA6Xu0gGBxlC_Aw&ved=0CAcQFjAB&client=internal-uds-cse&usg=AFQjCNHn-_WOT9BMMdwJJalA1JclwbfUfw Texas Railroad Commission hearing, 2011, Docket No. 7B-0268629] - Commission called hearing to consider whether operation of the Range Production Company Butler unit well no. 1H (RRC No. 253732) and the Teal unit well no. 1H (RRC No. 253779), Newark, East (Barnett Shale) Field, Hood County, Texas, are causing or contributing to contamination of certain domestic water wells in Parker County, Texas, v. 1, 123 p.

* Railroad Commission of Texas, 2011, [http://www.rrc.state.tx.us/meetings/ogpfd/RangePFD.PDF&sa=U&ei=WIAQT9DPA6Xu0gGBxlC_Aw&ved=0CAcQFjAB&client=internal-uds-cse&usg=AFQjCNHn-_WOT9BMMdwJJalA1JclwbfUfw Texas Railroad Commission hearing, 2011, Docket No. 7B-0268629] - Commission called hearing to consider whether operation of the Range Production Company Butler unit well no. 1H (RRC No. 253732) and the Teal unit well no. 1H (RRC No. 253779), Newark, East (Barnett Shale) Field, Hood County, Texas, are causing or contributing to contamination of certain domestic water wells in Parker County, Texas, v. 1, 123 p.

* Rullkotter, J., et al., 1988, Organic matter maturation under the influence of a deep intrusive 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 intrusive 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.

* Rushing, J. A., A. Chaouche, and K. E. Newsham, 2004, A mass balance approach for assessing basin-centered gas prospects: Integrating reservoir engineering, geochemistry, and petrophysics, in J. M. Cubitt, W. A. England, and S. R. Larter, eds., Understanding petroleum reservoirs: Toward an integrated reservoir engineering and geochemical approach: Geological Society (London) Special Publication 237, p. 373–390.

* Rushing, J. A., A. Chaouche, and K. E. Newsham, 2004, A mass balance approach for assessing basin-centered gas prospects: Integrating reservoir engineering, geochemistry, and petrophysics, in J. M. Cubitt, W. A. England, and S. R. Larter, eds., Understanding petroleum reservoirs: Toward an integrated reservoir engineering and geochemical approach: Geological Society (London) Special Publication 237, p. 373–390.

* 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.

*  

*  

*  

*  

*  

* Zou, C.-n., S.-z. Tao, X.-h. Gao, Y. Li, Z. Yang, Y.-j. Gong, D.-z. Dong, X.-j. Le, et al., 2010, [http://www.searchanddiscovery.net/abstracts/pdf/2010/annual/abstracts/ndx_caineng.pdf Basic contents, geological features and evaluation methods of continuous oil/gas plays in China]: AAPG Search and Discovery Article 90104, 7 p.

* Zou, C.-n., S.-z. Tao, X.-h. Gao, Y. Li, Z. Yang, Y.-j. Gong, D.-z. Dong, X.-j. Le, et al., 2010, [http://www.searchanddiscovery.net/abstracts/pdf/2010/annual/abstracts/ndx_caineng.pdf Basic contents, geological features and evaluation methods of continuous oil/gas plays in China]: AAPG Search and Discovery Article 90104, 7 p.