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A shale resource system is described as a continuous organic-rich source rock(s) that may be both a source and a reservoir rock for the production of petroleum (oil and gas) or may charge and seal petroleum in juxtaposed, continuous organic-lean interval(s). As such, there may be both primary migration processes that are limited to movement within the source interval<ref name=W&L1984>Welte, D., and Leythauser, 1984, Geological and physicochemical conditions for primary migration of hydrocarbons: Naturwissenschaften, v. 70, p. 133–137, doi:10.1007/BF00401597.M</ref> and secondary migration into nonsource horizons juxtaposed to the source rock(s).<ref name=W&L1984 /> Certainly additional migration away from the resource system into nonjuxtaposed, noncontinuous reservoirs may also occur. In this scheme, fractured shale-oil systems, that is, shales with open fractures, are included as shale resource systems.

A shale resource system is described as a continuous organic-rich source rock(s) that may be both a source and a reservoir rock for the production of petroleum (oil and gas) or may charge and seal petroleum in juxtaposed, continuous organic-lean interval(s). As such, there may be both primary migration processes that are limited to movement within the source interval<ref name=W&L1984>Welte, D., and Leythauser, 1984, Geological and physicochemical conditions for primary migration of hydrocarbons: Naturwissenschaften, v. 70, p. 133–137, doi:10.1007/BF00401597.M</ref> and secondary migration into nonsource horizons juxtaposed to the source rock(s).<ref name=W&L1984 /> Certainly additional migration away from the resource system into nonjuxtaposed, noncontinuous reservoirs may also occur. In this scheme, [[fracture]]d shale-oil systems, that is, shales with open fractures, are included as shale resource systems.

Two basic types of producible shale resource systems exist: gas- and oil-producing systems with overlap in the amount of gas versus oil. Although dry gas resource systems produce almost exclusively methane, wet gas systems produce some liquids and oil systems produce some gas. These are commonly described as either shale gas or shale oil, depending on which product predominates production. Although industry parlance commonly describes these as shale plays, these are truly mudstone; nonetheless, the term shale is used herein. It is important, however, to view these as a petroleum system,<ref>Magoon, L. B., and W. G. Dow, 1994, [http://archives.datapages.com/data/specpubs/methodo2/data/a077/a077/0001/0000/0003.htm The petroleum system], 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. 3–24.</ref> regardless of reservoir lithofacies or quality, because all the components and processes are applicable.

Two basic types of producible shale resource systems exist: gas- and oil-producing systems with overlap in the amount of gas versus oil. Although dry gas resource systems produce almost exclusively methane, wet gas systems produce some liquids and oil systems produce some gas. These are commonly described as either shale gas or shale oil, depending on which product predominates production. Although industry parlance commonly describes these as shale plays, these are truly [[mudstone]]; nonetheless, the term shale is used herein. It is important, however, to view these as a petroleum system,<ref>Magoon, L. B., and W. G. Dow, 1994, [http://archives.datapages.com/data/specpubs/methodo2/data/a077/a077/0001/0000/0003.htm The petroleum system], 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. 3–24.</ref> regardless of reservoir [[lithofacies]] or quality, because all the components and processes are applicable.

Given this definition of shale resource systems, these plays are not new with production from fractured mudstone reservoirs ongoing for more than 100 yr.<ref>Curtis, J. B., 2002, [http://archives.datapages.com/data/bulletns/2002/11nov/1921/1921.htm Fractured shale gas systems]: AAPG Bulletin, v. 86, no. 11, p. 1921–1938.</ref> Gas from Devonian shales in the Appalachian Basin and oil from fractured Monterey Shale, for example, have had ongoing long-term (100+ yr) production. The paradigm shift in the new millennium is the pursuit of tight mudstone systems, and although fractures may be present, they are usually healed with minerals such as calcite. Of course, having a brittle rock typically with a high silica content is also very important. These systems are organic-rich mudstones or calcareous mudstones that have retained gas or oil and have also expelled petroleum. The close association of source and nonsource intervals has sometimes made it difficult to ascertain which horizon is the actual source rock, for example, Austin Chalk and interbedded Eagle Ford Shale.<ref>Grabowski, G. J., 1995, Organic-rich chalks and calcareous mudstones of the Upper Cretaceous Austin Chalk and Eagleford Formation, south-central Texas, U.S.A., in B. J. Katz, ed., Petroleum source rocks: Berlin, Springer-Verlag, p. 209–234.</ref> Of course, in addition to retained or juxtaposed expelled petroleum, most of these organic-rich source rocks have expelled petroleum that has migrated, typically longer distances, into conventional reservoirs.

Given this definition of shale resource systems, these plays are not new with production from fractured mudstone reservoirs ongoing for more than 100 yr.<ref>Curtis, J. B., 2002, [http://archives.datapages.com/data/bulletns/2002/11nov/1921/1921.htm Fractured shale gas systems]: AAPG Bulletin, v. 86, no. 11, p. 1921–1938.</ref> Gas from Devonian shales in the Appalachian Basin and oil from fractured Monterey Shale, for example, have had ongoing long-term (100+ yr) production. The paradigm shift in the new millennium is the pursuit of tight mudstone systems, and although fractures may be present, they are usually healed with minerals such as calcite. Of course, having a brittle rock typically with a high silica content is also very important. These systems are organic-rich mudstones or calcareous mudstones that have retained gas or oil and have also expelled petroleum. The close association of source and nonsource intervals has sometimes made it difficult to ascertain which horizon is the actual source rock, for example, Austin Chalk and interbedded Eagle Ford Shale.<ref>Grabowski, G. J., 1995, Organic-rich chalks and calcareous mudstones of the Upper Cretaceous Austin Chalk and Eagleford Formation, south-central Texas, U.S.A., in B. J. Katz, ed., Petroleum source rocks: Berlin, Springer-Verlag, p. 209–234.</ref> Of course, in addition to retained or juxtaposed expelled petroleum, most of these organic-rich source rocks have expelled petroleum that has migrated, typically longer distances, into conventional reservoirs.

Around the world, including Saudi Arabia, natural gas is being sought as a replacement for the far more valuable and expensive oil resource. The challenge is to develop and use this resource soundly, economically, safely, and effectively in our energy mix. It provides a means to an environmentally reasonable and abundant energy resource with a long production potential, thereby providing a bridge to the future until new energy sources are available at a reasonable cost and sufficient capacity to meet our industrial, social, and political needs—be they renewable or other forms of energy resources.

Around the world, including Saudi Arabia, natural gas is being sought as a replacement for the far more valuable and expensive oil resource. The challenge is to develop and use this resource soundly, economically, safely, and effectively in our energy mix. It provides a means to an environmentally reasonable and abundant energy resource with a long production potential, thereby providing a bridge to the future until new energy sources are available at a reasonable cost and sufficient capacity to meet our industrial, social, and political needs—be they renewable or other forms of energy resources.

United States independent petroleum companies, led originally by Mitchell Energy and Development Corp. (MEDC), pursued and developed these unconventional shale-gas reservoir systems mostly during the last 10 yr in principal, although Mitchell's effort began much earlier. In 1982, drilling of the MEDC 1-Slay well Barnett Shale for its shale-gas resource potential was the launch point for this revolutionary exploration and production (EampP) effort.<ref name=St2007>Steward, D. B., 2007, The Barnett Shale play: Phoenix of the Fort Worth Basin—A history: The Fort Worth Geological Society and The North Texas Geological Society, ISBN 978-0-9792841-0-6, 202 p.</ref> It was an incredibly difficult resource to exploit and was noncommercial through the 1980s and most of the 1990s. Even the first Barnett Shale horizontal well, drilled in 1991, the MEDC 1-Sims, was not an economic or even technical success. Horizontal drilling is an important part of the equation that has led to the development of shale resource plays, but it is only one component in a series of interlinked controls on obtaining gas flow from shale. For example, without understanding the importance of rock mechanical properties, stress fields, and stimulation processes, horizontal drilling alone would not have caused the shale-gas resource to develop so dramatically. Good gas flow rates in the 1990s were typically 1.4 times 104 m3/day (500 mcf/day) or less for most Barnett Shale wells, all of which were verticals except for the 1-Sims well. The economics were enhanced when MEDC began using slick-water stimulation to reduce costs, with the surprising benefit of improved performance in terms of gas flow rates.<ref name=St2007 /> It was also learned that vertical wells could be restimulated, which raised production back to significant levels, commonly reaching or exceeding original gas flow rates. The use of technologies such as three-dimensional seismic and microseismic proved highly beneficial in moving the success of Barnett Shale forward.<ref name=St2007 /> For example, a key point still argued to this day is the impact of structure and faulting on production potential. Obviously, conventional wisdom would suggest these as positive risk factors, when in fact they are typically negative. It was learned that stimulation energy was thieved by the presence of structures and faults, thereby typically lowering success when present.<ref name=St2007 /> Application of microseismic surveys allowed engineers to map where the stimulation energy was being directed, thereby allowing adjustments to the stimulation program.<ref name=St2007 />

United States independent petroleum companies, led originally by Mitchell Energy and Development Corp. (MEDC), pursued and developed these unconventional shale-gas reservoir systems mostly during the last 10 yr in principal, although Mitchell's effort began much earlier. In 1982, drilling of the MEDC 1-Slay well [[Barnett Shale]] for its shale-gas resource potential was the launch point for this revolutionary exploration and production (EampP) effort.<ref name=St2007>Steward, D. B., 2007, The Barnett Shale play: Phoenix of the Fort Worth Basin—A history: The Fort Worth Geological Society and The North Texas Geological Society, ISBN 978-0-9792841-0-6, 202 p.</ref> It was an incredibly difficult resource to exploit and was noncommercial through the 1980s and most of the 1990s. Even the first Barnett Shale [[horizontal well]], drilled in 1991, the MEDC 1-Sims, was not an economic or even technical success. Horizontal drilling is an important part of the equation that has led to the development of shale resource plays, but it is only one component in a series of interlinked controls on obtaining gas flow from shale. For example, without understanding the importance of rock mechanical properties, stress fields, and stimulation processes, horizontal drilling alone would not have caused the shale-gas resource to develop so dramatically. Good gas flow rates in the 1990s were typically 1.4 times 104 m3/day (500 mcf/day) or less for most Barnett Shale wells, all of which were verticals except for the 1-Sims well. The [[economics]] were enhanced when MEDC began using slick-water stimulation to reduce costs, with the surprising benefit of improved performance in terms of gas flow rates.<ref name=St2007 /> It was also learned that vertical wells could be restimulated, which raised production back to significant levels, commonly reaching or exceeding original gas flow rates. The use of technologies such as three-dimensional seismic and microseismic proved highly beneficial in moving the success of Barnett Shale forward.<ref name=St2007 /> For example, a key point still argued to this day is the impact of structure and faulting on production potential. Obviously, conventional wisdom would suggest these as positive risk factors, when in fact they are typically negative. It was learned that stimulation energy was thieved by the presence of structures and faults, thereby typically lowering success when present.<ref name=St2007 /> Application of microseismic surveys allowed engineers to map where the stimulation energy was being directed, thereby allowing adjustments to the stimulation program.<ref name=St2007 />

Ultimately, industry's use of horizontal wells and new technologies enhanced success in the Barnett Shale, and industry began to recognize its gas resource potential. However, the Barnett Shale-gas resource system was typically viewed as a unique case that could not be reproduced elsewhere.

Ultimately, industry's use of horizontal wells and new technologies enhanced success in the Barnett Shale, and industry began to recognize its gas resource potential. However, the Barnett Shale-gas resource system was typically viewed as a unique case that could not be reproduced elsewhere.

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.<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>

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<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 (abs.).</ref> and Loucks et al.<ref>Loucks, R. G., R. M. Reed, S. C. Ruppel, and D. M. Jarvie, 2009, 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> 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.<ref name=Jrvie2006>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</ref> 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.

In addition, work by Reed and Loucks<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 (abs.).</ref> and Loucks et al.<ref>Loucks, R. G., R. M. Reed, S. C. Ruppel, and D. M. Jarvie, 2009, 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> 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.<ref name=Jrvie2006>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</ref> 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.

==Organic richness: total organic carbon assessment==

==Organic richness: total organic carbon assessment==

One of the first and basic screening analyses for any source rock is organic richness, as measured by total organic carbon (TOC). The TOC is a measure of organic carbon present in a sediment sample, but it is not a measure of its generation potential alone, as that requires an assessment of hydrogen content or organic maceral percentages from chemical or visual kerogen assessments. As TOC values vary throughout a source rock because of organofacies differences and thermal maturity, and even depending on sample type, there has been a lengthy debate on what actual TOC values are needed to have a commercial source rock. All organic matter preserved in sediments will decompose into petroleum with sufficient temperature exposure; for EampP companies, it is a matter of the producibility and commerciality of such generation. In addition, the expulsion and retention of generated petroleum must be considered. However, original quantity (TOC) as well as source rock quality (type) of the source rock must be considered in combination to assess its petroleum generation potential.

One of the first and basic screening analyses for any source rock is organic richness, as measured by total organic carbon (TOC). The TOC is a measure of organic carbon present in a sediment sample, but it is not a measure of its generation potential alone, as that requires an assessment of hydrogen content or organic [[maceral]] percentages from chemical or visual [[kerogen]] assessments. As TOC values vary throughout a source rock because of organofacies differences and thermal maturity, and even depending on sample type, there has been a lengthy debate on what actual TOC values are needed to have a commercial source rock. All organic matter preserved in sediments will decompose into petroleum with sufficient temperature exposure; for EampP companies, it is a matter of the producibility and commerciality of such generation. In addition, the expulsion and retention of generated petroleum must be considered. However, original quantity (TOC) as well as source rock quality (type) of the source rock must be considered in combination to assess its petroleum generation potential.

From a qualitative point of view, part of this issue includes the assessment of variations in quantitative TOC values that are altered by, for example, thermal maturity, sample collection technique, sample type (cuttings versus core chips), sample quality (e.g., fines only, cavings, contamination), and any high grading of core or cuttings samples. Documented variations in cuttings through the Fayetteville and Chattanooga shales illustrate variations due to sample type and quality as cuttings commonly have mixing effects. An overlying organic-lean sediment will dilute an organic-rich sample often for 10 to 40 ft (3 to 12 m). This is evident in some Fayetteville and Chattanooga wells with cuttings analysis, where the uppermost parts of the organic-rich shales have TOC values suggesting the shale to be organic lean. However, TOC values increase with deeper penetration into the organic-rich shale, to and through the base of the shale, but then also continuing into underlying organic-lean sediments, until finally decreasing to low values.<ref name=Li2010a>Li, P., M. E. Ratchford, and D. M. Jarvie, 2010a, Geochemistry and thermal maturity analysis of the Fayetteville Shale and Chattanooga Shale in the western Arkoma Basin of Arkansas: Arkansas Geological Survey, Information Circular 40, DFF-OG-FS-EAB/ME 012, 58 p.</ref> This is a function of mixing of cuttings while drilling. The same issue in Barnett Shale wells was reported by MEDC,<ref name=St2007 /> who also reported lower vitrinite reflectance values for cuttings than core (sim0.15% Ro lower). The big problem with this mixing effect is that it does not always occur and picking of cuttings does not typically solve the problem in shale-gas resource systems, although it may work in less mature systems. One solution is to minimize the quantitation of the uppermost sections (sim9 m [sim30 ft]) of a shale of interest when cuttings are used for analysis. The inverse of this situation is often identifiable in known organic-lean sediments below an organic-rich shale or coal. This latter effect is more obvious below coaly intervals, where TOC values will be high unless picked free of coal.

From a qualitative point of view, part of this issue includes the assessment of variations in quantitative TOC values that are altered by, for example, thermal maturity, sample collection technique, sample type (cuttings versus core chips), sample quality (e.g., fines only, cavings, contamination), and any high grading of core or cuttings samples. Documented variations in cuttings through the Fayetteville and Chattanooga shales illustrate variations due to sample type and quality as cuttings commonly have mixing effects. An overlying organic-lean sediment will dilute an organic-rich sample often for 10 to 40 ft (3 to 12 m). This is evident in some Fayetteville and Chattanooga wells with cuttings analysis, where the uppermost parts of the organic-rich shales have TOC values suggesting the shale to be organic lean. However, TOC values increase with deeper penetration into the organic-rich shale, to and through the base of the shale, but then also continuing into underlying organic-lean sediments, until finally decreasing to low values.<ref name=Li2010a>Li, P., M. E. Ratchford, and D. M. Jarvie, 2010a, Geochemistry and thermal maturity analysis of the Fayetteville Shale and Chattanooga Shale in the western Arkoma Basin of Arkansas: Arkansas Geological Survey, Information Circular 40, DFF-OG-FS-EAB/ME 012, 58 p.</ref> This is a function of mixing of cuttings while drilling. The same issue in Barnett Shale wells was reported by MEDC,<ref name=St2007 /> who also reported lower vitrinite reflectance values for cuttings than core (sim0.15% Ro lower). The big problem with this mixing effect is that it does not always occur and picking of cuttings does not typically solve the problem in shale-gas resource systems, although it may work in less mature systems. One solution is to minimize the quantitation of the uppermost sections (sim9 m [sim30 ft]) of a shale of interest when cuttings are used for analysis. The inverse of this situation is often identifiable in known organic-lean sediments below an organic-rich shale or [[coal]]. This latter effect is more obvious below coaly intervals, where TOC values will be high unless picked free of coal.

In any case, what is measured in any geochemical laboratory is strictly present-day TOC (TOCpd), which is dependent on all previously mentioned factors. In the absence of other factors, the decrease in original TOC (TOCo) is a function of thermal maturity due to the conversion of organic matter to petroleum and a carbonaceous char. The TOC measurements may include organic in oil or bitumen, which may not be completely removed during the typical decarbonation step before the LECO TOC analysis. Bitumen and oil-free TOC is described in various ways but always having two components whose distribution is dependent on the originally deposited and preserved biomass: generative organic carbon (GOC) and nongenerative organic carbon (NGOC) fractions. These have been referred to by various names without specifying bitumen and/or oil free (e.g., reactive and inert carbon).<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.</ref> As such, the GOC fraction has sufficient hydrogen to generate hydrocarbons, whereas the NGOC fraction does not yield substantial amounts of hydrocarbons. Decomposition of the GOC also creates organic porosity, which is directly proportional to the GOC fraction and its extent of conversion. The NGOC fraction accounts for adsorbed gas storage and some organic porosity development due to restructuring of the organic matrix. The creation of such organic porosity in a reducing environment creates sites for possible catalytic activity by carbonaceous char<ref>Fuhrmann, A., K. F. M. Thompson, R. di Primio, and V. Dieckmann, 2003, Insight into petroleum composition based on thermal and catalytic cracking: 21st International Meeting on Organic Geochemistry (IMOG), Krakow, Poland, September 8–12, 2003, Book of Abstracts, part I, p. 321–322.</ref><ref>Alexander, R., D. Dawson, K. Pierce, and A. Murray, 2009, Carbon catalyzed hydrogen exchange in petroleum source rocks: Organic Geochemistry, v. 40, p. 951–955, doi:10.1016/j.orggeochem.2009.06.003.</ref> or other catalytic materials, for example, low valence transition metals.<ref>Mango, F. D., 1992, Transition metal catalysis in the generation of petroleum: A genetic anomaly in Ordovician oils: Geochimica et Cosmochimica Acta, v. 56, p. 3851–3854, doi:10.1016/0016-7037(92)90177-K.</ref><ref>Mango, F. D., 1996, Transition metal catalysis in the generation of natural gas: Organic Geochemistry, v. 24, no. 10–11, p. 977–984, doi:10.1016/S0146-6380(96)00092-7.</ref>

In any case, what is measured in any geochemical laboratory is strictly present-day TOC (TOCpd), which is dependent on all previously mentioned factors. In the absence of other factors, the decrease in original TOC (TOCo) is a function of thermal maturity due to the conversion of organic matter to petroleum and a carbonaceous char. The TOC measurements may include organic in oil or bitumen, which may not be completely removed during the typical decarbonation step before the LECO TOC analysis. Bitumen and oil-free TOC is described in various ways but always having two components whose distribution is dependent on the originally deposited and preserved biomass: generative organic carbon (GOC) and nongenerative organic carbon (NGOC) fractions. These have been referred to by various names without specifying bitumen and/or oil free (e.g., reactive and inert carbon).<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.</ref> As such, the GOC fraction has sufficient hydrogen to generate hydrocarbons, whereas the NGOC fraction does not yield substantial amounts of hydrocarbons. Decomposition of the GOC also creates organic porosity, which is directly proportional to the GOC fraction and its extent of conversion. The NGOC fraction accounts for adsorbed gas storage and some organic porosity development due to restructuring of the organic matrix. The creation of such organic porosity in a reducing environment creates sites for possible catalytic activity by carbonaceous char<ref>Fuhrmann, A., K. F. M. Thompson, R. di Primio, and V. Dieckmann, 2003, Insight into petroleum composition based on thermal and catalytic [[cracking]]: 21st International Meeting on Organic Geochemistry (IMOG), Krakow, Poland, September 8–12, 2003, Book of Abstracts, part I, p. 321–322.</ref><ref>Alexander, R., D. Dawson, K. Pierce, and A. Murray, 2009, Carbon catalyzed hydrogen exchange in petroleum source rocks: Organic Geochemistry, v. 40, p. 951–955, doi:10.1016/j.orggeochem.2009.06.003.</ref> or other catalytic materials, for example, low valence transition metals.<ref>Mango, F. D., 1992, Transition metal catalysis in the generation of petroleum: A genetic anomaly in Ordovician oils: Geochimica et Cosmochimica Acta, v. 56, p. 3851–3854, doi:10.1016/0016-7037(92)90177-K.</ref><ref>Mango, F. D., 1996, Transition metal catalysis in the generation of natural gas: Organic Geochemistry, v. 24, no. 10–11, p. 977–984, doi:10.1016/S0146-6380(96)00092-7.</ref>

A slight increase in NGOC occurs as organic matter decomposes and uses the limited amounts of hydrogen in GOC (maximum of sim1.8 hydrogen to carbon [H-to-C] in the very best source rocks and about 2.0 H-to-C in bitumen and/or oil). Most shale-gas resource systems at a high thermal maturity have only small amounts or no GOC remaining and are dominated by the enhanced NGOC fraction. The decomposition of GOC generates all the petroleum, creates organic storage porosity, and both GOC and NGOC function in retention of generated petroleum that ultimately is cracked to gas in high-thermal-maturity shale-gas resource systems.

A slight increase in NGOC occurs as organic matter decomposes and uses the limited amounts of hydrogen in GOC (maximum of sim1.8 hydrogen to carbon [H-to-C] in the very best source rocks and about 2.0 H-to-C in bitumen and/or oil). Most shale-gas resource systems at a high thermal maturity have only small amounts or no GOC remaining and are dominated by the enhanced NGOC fraction. The decomposition of GOC generates all the petroleum, creates organic storage porosity, and both GOC and NGOC function in retention of generated petroleum that ultimately is cracked to gas in high-thermal-maturity shale-gas resource systems.

{| class="wikitable"

{| class="wikitable"

|+{{table number|1}}P90, P50, and P10 values for HI_o for a worldwide collection of marine source rocks.

|+{{table number|1.}}P90, P50, and P10 values for HI_o for a worldwide collection of marine source rocks.

|-

|-

!  || HI_o (mg HC/g TOC) || GOC% of TOC_o || NGOC% of TOC_o

!  || HI_o (mg HC/g TOC) || GOC% of TOC_o || NGOC% of TOC_o

{| class=wikitable

{| class=wikitable

|+{{table number|2}}Computation of original TOC from measured TOC and Rock-Eval data.

|+{{table number|2.}}Computation of original TOC from measured TOC and Rock-Eval data.

! Geochemical Description || Value || Derivation

! Geochemical Description || Value || Derivation

|-

|-

| S2_o (in boe/af) || 595 || boe/af <math>(\text{S}2_{\text{o}} \times 21.89)</math>

| S2_o (in boe/af) || 595 || boe/af <math>(\text{S}2_{\text{o}} \times 21.89)</math>

|}

|}

^{TOC = total organic carbon; HI = hydrogen index; subscript ‘‘o’’ = original value; subscript ‘‘pd’’ = present-day measured or computed value; TR = transformation ratio, the change in original HI, where TR = (HI_o􏰂HIpd)/HI_o; GOC = generative organic carbon (in weight percentage); NGOC = nongenerative organic carbon (in weight percentage); bkfree = bitumen- and kerogen-free TOC values; subscript ‘‘NGOCcorrection’’ = minor correction to TOCpd for added carbonaceous char from bitumen and/or oil cracking. S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields; boe/af = bbl of oil equivalent per acre-ft.}

^{TOC = total organic carbon; HI = hydrogen index; subscript ‘‘o’’ = original value; subscript ‘‘pd’’ = present-day measured or computed value; TR = transformation ratio, the change in original HI, where TR = (HI_o􏰂HIpd)/HI_o; GOC = generative organic carbon (in weight percentage); NGOC = nongenerative organic carbon (in weight percentage); bkfree = bitumen- and kerogen-free TOC values; subscript ‘‘NGOCcorrection’’ = minor correction to TOCpd for added carbonaceous char from bitumen and/or oil cracking. S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields; boe/af = bbl of oil equivalent per acre-ft.}

This nomograph provides a pragmatic method for estimating the elusive TOCo value and the original generation potential via determination of GOCo values when combined with either measured or estimated HI_o data or using a sensitivity analysis via P10, P50, and P90 HI_o values in the absence of other data. This is important because the total generation potential of the source rock can be estimated with these assumptions, and as such, the amount retained in the organic-rich shale can be estimated, that is, GIP, as well as the expelled amounts that may be recovered in a hybrid shale-gas resource system.

This nomograph provides a pragmatic method for estimating the elusive TOCo value and the original generation potential via determination of GOCo values when combined with either measured or estimated HI_o data or using a sensitivity analysis via P10, P50, and P90 HI_o values in the absence of other data. This is important because the total generation potential of the source rock can be estimated with these assumptions, and as such, the amount retained in the organic-rich shale can be estimated, that is, GIP, as well as the expelled amounts that may be recovered in a hybrid shale-gas resource system.

::<math>= 0.34 \text{or } 34% \text{ reactive organic carbon}</math>

::<math>= 0.34 \text{or } 34% \text{ reactive organic carbon}</math>

An important example of variable organofacies is provided by analog data for the Bossier and Haynesville shales in the area between the east Texas and north Louisiana salt basins. As only gas window maturity Bossier and Haynesville shale data are available, analog data are used, that is, immature Tithonian and Kimmeridgian source rocks from the deep-water Gulf of Mexico (Table 3).

An important example of variable organofacies is provided by analog data for the Bossier and Haynesville shales in the area between the east Texas and north Louisiana salt basins. As only gas window maturity Bossier and Haynesville shale data are available, analog data are used, that is, immature Tithonian and Kimmeridgian source rocks from the deep-water [[Gulf of Mexico]] (Table 3).

{| class=wikitable

{| class=wikitable

{| class=wikitable

{| class=wikitable

|-

|-

|+ {{table number|4}}Original hydrogen index, present-day TOC, original TOC, and P50-derived original TOC for top 10 shale-gas systems.

|+ {{table number|4.}}Original hydrogen index, present-day TOC, original TOC, and P50-derived original TOC for top 10 shale-gas systems.

|-

|-

! rowspan = 2 | Formation || rowspan = 2 | System or Series || rowspan = 2 | HI_o (mg/g) || rowspan = 2 | TOC_pd High (wt. %) || rowspan = 2 | TOC_pd Low (wt. %) || rowspan = 2 | TOC_pd Average (wt. %) || rowspan = 2 | Standard Deviation (wt. %) || rowspan = 2 | %GOC || rowspan = 2 | %NGOC || colspan = 3 | TOC_o Values || P50 (HI = 475)

! rowspan = 2 | Formation || rowspan = 2 | System or Series || rowspan = 2 | HI_o (mg/g) || rowspan = 2 | TOC_pd High (wt. %) || rowspan = 2 | TOC_pd Low (wt. %) || rowspan = 2 | TOC_pd Average (wt. %) || rowspan = 2 | Standard Deviation (wt. %) || rowspan = 2 | %GOC || rowspan = 2 | %NGOC || colspan = 3 | TOC_o Values || P50 (HI = 475)

{| class=wikitable

{| class=wikitable

|-

|-

|+ {{table number|5}}Available characteristics of the top 10 shale-gas resource systems in core-producing areas of each basin.

|+ {{table number|5.}}Available characteristics of the top 10 shale-gas resource systems in core-producing areas of each basin.

|-

|-

! Shale || Marcellus || Haynesville || Bossier || Barnett || Fayetteville || Muskwa || Woodford || Eagle Ford || Utica || Montney

! Shale || Marcellus || Haynesville || Bossier || Barnett || Fayetteville || Muskwa || Woodford || Eagle Ford || Utica || Montney

ExxonMobil has now drilled at least four wells in the lower Saxony Basin for shale-gas resources, but no results are in the public domain.

ExxonMobil has now drilled at least four wells in the lower Saxony Basin for shale-gas resources, but no results are in the public domain.

In Sweden and Denmark, the Skegerrak-Kattegat Basin contains the Cambrian–Ordovician Alum Shale, which has also been studied extensively.<ref>Lewan, M. D., and B. Buchardt, 1989, Irradiation of organic matter by uranium decay in the Alum Shale, Sweden: Geochemica et Cosmochimica Acta, v. 53, p. 1307–1322, doi:10.1016/0016-7037(89)90065-3.</ref><ref>Bharati, S., R. L. Patience, S. R. Larter, G. Standen, and I. J. F. Poplett, 1995, Elucidation of the Alum Shale kerogen structure using a multidisciplinary approach: Organic Geochemistry, v. 23, no. 11–12, p. 1043–1058, doi:10.1016/0146-6380(95)00089-5.</ref><ref> Buchardt, B., A. Thorshoj Nielsen, and N. Hemmingsen Schovsbo, 1997, Alun Skiferen i Skandinavien, Dansk Geologisk Forenings Nyheds: OG Informationsskirft, 32 p.</ref>. The Alum Shale is organic rich, with high TOC (11–22%) and HIo, yet generates primarily gas and condensate upon thermal conversion.<ref>Horsfield, B., S. Bharati, S. R. Larter, F. Leistner, R. Littke, H. J. Schenk, and H. Dypvik, 1992, On the atypical petroleum-generating characteristics of alginate in the Cambrian Alum Shale, in M. Schidlowski, S. Golubic, M. M. Kimerly, and P. A. Trudinger, eds., Early organic evolution: Implications for mineral and energy resources: Berlin, Springer-Verlag, p. 257–266.</ref> Compositional yield data derived from immature Alum Shale with an HI of 487 mg HC/g TOC show that strictly primary kerogen and bitumen and/or oil cracking yields about 60% gas, quite unusual for source rocks of comparable HIo values that typically only yield 20 to 30% gas (D. M. Jarvie, unpublished data). Shell Oil Company has now drilled at least two wells into the Alum Shale, but no results are available.

In Sweden and Denmark, the Skegerrak-Kattegat Basin contains the [[Cambrian]]–Ordovician Alum Shale, which has also been studied extensively.<ref>Lewan, M. D., and B. Buchardt, 1989, Irradiation of organic matter by uranium decay in the Alum Shale, Sweden: Geochemica et Cosmochimica Acta, v. 53, p. 1307–1322, doi:10.1016/0016-7037(89)90065-3.</ref><ref>Bharati, S., R. L. Patience, S. R. Larter, G. Standen, and I. J. F. Poplett, 1995, Elucidation of the Alum Shale kerogen structure using a multidisciplinary approach: Organic Geochemistry, v. 23, no. 11–12, p. 1043–1058, doi:10.1016/0146-6380(95)00089-5.</ref><ref> Buchardt, B., A. Thorshoj Nielsen, and N. Hemmingsen Schovsbo, 1997, Alun Skiferen i Skandinavien, Dansk Geologisk Forenings Nyheds: OG Informationsskirft, 32 p.</ref>. The Alum Shale is organic rich, with high TOC (11–22%) and HIo, yet generates primarily gas and condensate upon thermal conversion.<ref>Horsfield, B., S. Bharati, S. R. Larter, F. Leistner, R. Littke, H. J. Schenk, and H. Dypvik, 1992, On the atypical petroleum-generating characteristics of alginate in the Cambrian Alum Shale, in M. Schidlowski, S. Golubic, M. M. Kimerly, and P. A. Trudinger, eds., Early organic evolution: Implications for mineral and energy resources: Berlin, Springer-Verlag, p. 257–266.</ref> Compositional yield data derived from immature Alum Shale with an HI of 487 mg HC/g TOC show that strictly primary kerogen and bitumen and/or oil cracking yields about 60% gas, quite unusual for source rocks of comparable HIo values that typically only yield 20 to 30% gas (D. M. Jarvie, unpublished data). Shell Oil Company has now drilled at least two wells into the Alum Shale, but no results are available.

Data from Poland suggest a variety of shale-gas potential in various basins such as the Baltic, Lublin, and Carpathian. Shale-gas resource potential exists in the Silurian Graptolitic Shale. Comparing data from across Poland using two criteria for shale-gas prospectivity, organic richness, and level of conversion, TOCpd values range from 2 to 18%, some with gas window levels of conversion ([[:File:M97FG8.jpg|Figure 8]]). It is recently announced that the first shale stimulation in Europe has been completed on the 1-Markowolain well in the Lublin Basin. No gas flow data have been reported.

Data from Poland suggest a variety of shale-gas potential in various basins such as the Baltic, Lublin, and Carpathian. Shale-gas resource potential exists in the Silurian Graptolitic Shale. Comparing data from across Poland using two criteria for shale-gas prospectivity, organic richness, and level of conversion, TOCpd values range from 2 to 18%, some with gas window levels of conversion ([[:File:M97FG8.jpg|Figure 8]]). It is recently announced that the first shale stimulation in Europe has been completed on the 1-Markowolain well in the Lublin Basin. No gas flow data have been reported.

==References==

==References==

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{{reflist}}