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Producible oil from shales or closely associated organic-lean intraformational lithofacies such as carbonates is referred to as a shale-oil resource system. Organic-rich mudstones, calcareous mudstones, or argillaceous lime mudstones are typically both the source for the petroleum and either a primary or secondary reservoir target, but optimum production can be derived from organic-lean juxtaposed carbonates, silts, or sands. Where organic-rich and organic-lean intervals are juxtaposed, the term hybrid shale-oil resource system is applied.

Producible oil from shales or closely associated organic-lean intraformational lithofacies such as carbonates is referred to as a shale-oil resource system. Organic-rich mudstones, calcareous mudstones, or argillaceous lime mudstones are typically both the source for the petroleum and either a primary or secondary reservoir target, but optimum production can be derived from organic-lean juxtaposed carbonates, silts, or sands. Where organic-rich and organic-lean intervals are juxtaposed, the term hybrid shale-oil resource system is applied.

These systems are classified as (1) organic-rich mudstones without open fractures, (2) organic-rich mudstones with open fractures, and (3) hybrid systems that have juxtaposed, continuous organic-rich and organic-lean intervals ([[:File:M97Ch1.2FG1.jpg|Figure 1]]). For example, the Bakken Formation production is accounted for by both open-fractured shale (e.g., Bicentennial field) and hybrid shale (e.g., Elm Coulee, Sanish, and Parshall fields), where organic-rich shales are juxtaposed to organic-lean intervals, such as the Middle Member (dolomitic sand) and Three Forks (carbonate). However, Barnett Shale oil is almost always from a tight mudstone with some related matrix porosity (EOG Resources, 2010). Monterey Shale-oil production is primarily from open-fractured shale in tectonically active areas of California. Various shale-oil resource systems are classified based on available data in Table 1. To suggest that these types are mutually exclusive is also incorrect because there can be a significant overlap in a single shale-oil resource system.

These systems are classified as (1) organic-rich mudstones without open fractures, (2) organic-rich mudstones with open fractures, and (3) hybrid systems that have juxtaposed, continuous organic-rich and organic-lean intervals ([[:File:M97Ch1.2FG1.jpg|Figure 1]]). For example, the Bakken Formation production is accounted for by both open-fractured shale (e.g., Bicentennial field) and hybrid shale (e.g., Elm Coulee, Sanish, and Parshall fields), where organic-rich shales are juxtaposed to organic-lean intervals, such as the Middle Member (dolomitic sand) and Three Forks (carbonate). However, Barnett Shale oil is almost always from a tight mudstone with some related matrix porosity.<ref name=EOGResources2010>EOG Resources, 2010,[http://wwgeochem.com/references/EOGMay2010Investorpresentation.pdf Investor presentation: EOG_2010], 223 p.</ref> Monterey Shale-oil production is primarily from open-fractured shale in tectonically active areas of California. Various shale-oil resource systems are classified based on available data in Table 1. To suggest that these types are mutually exclusive is also incorrect because there can be a significant overlap in a single shale-oil resource system.

[[File:M97Ch1.2FG1.jpg|thumb|500px|{{figure number|1}}Shale-oil resource systems. A simple classification scheme includes continuous (1) organic-rich mudstones with no open fractures (tight shale), (2) organic-rich mudstones with open fractures (fractured shale), and (3) organic-rich mudstones with juxtaposed organic-lean facies (hybrid shale).]]

[[File:M97Ch1.2FG1.jpg|thumb|500px|{{figure number|1}}Shale-oil resource systems. A simple classification scheme includes continuous (1) organic-rich mudstones with no open fractures (tight shale), (2) organic-rich mudstones with open fractures (fractured shale), and (3) organic-rich mudstones with juxtaposed organic-lean facies (hybrid shale).]]

A special, but separate, shale resource system is oil shale. It is preferred to refer to oil shale as a kerogen resource system or as kerogen oil as it does not contain sufficient amounts of free oil to produce, but must be heated to generate oil from kerogen either in the subsurface or after mining and retorting. This 2d part of chapter 1 will only discuss shale-oil resource systems that have already generated petroleum because of geologic heating processes.

A special, but separate, shale resource system is oil shale. It is preferred to refer to oil shale as a kerogen resource system or as kerogen oil as it does not contain sufficient amounts of free oil to produce, but must be heated to generate oil from kerogen either in the subsurface or after mining and retorting. This 2d part of chapter 1 will only discuss shale-oil resource systems that have already generated petroleum because of geologic heating processes.

With the remarkable success in locating and producing shale-gas resource systems, an overabundance of gas has reduced its current economic value and there has been an exploration and development shift toward locating producible shale-oil resource systems. Recent announcements of the oil resource potential of several shale-oil resource systems have substantiated the volume of oil they contain, for example, 5.88253 times 107 m3 (370 million bbl of oil equivalent [BOE]) in the Barnett Shale, 1.430886 times 107 m3 (90 million BOE) in the Bakken Formation core area, and 1.430886 times 108 m3 (900 million BOE) in the Eagle Ford Shale (EOG Resources, 2010). However, the keys to unlocking these high volumes of oil are not fully understood or developed to date.

With the remarkable success in locating and producing shale-gas resource systems, an overabundance of gas has reduced its current economic value and there has been an exploration and development shift toward locating producible shale-oil resource systems. Recent announcements of the oil resource potential of several shale-oil resource systems have substantiated the volume of oil they contain, for example, 5.88253 times 107 m3 (370 million bbl of oil equivalent [BOE]) in the Barnett Shale, 1.430886 times 107 m3 (90 million BOE) in the Bakken Formation core area, and 1.430886 times 108 m3 (900 million BOE) in the Eagle Ford Shale.<ref name=EOGResources2010 /> However, the keys to unlocking these high volumes of oil are not fully understood or developed to date.

==Background==

==Background==

Most of the Barnett Shale oil has been recovered in vertical wells in the oil window parts of the basin, that is, western and northern parts of the Fort Worth Basin. The Barnett Shale is thinner in the west but thickens toward the northeast and is less mature in both locations, with vitrinite reflectance values of about 0.60% Roe in Brown County in the far southwestern part of the basin and about 0.85% Roe in the north-northeastern parts of the basin, for example, Clay, Montague, and Cooke counties, Texas. Oil produced from a well in the southwest, the Explo Oil 3-Mitcham, yielded a 36deg API from the Barnett Shale at 0.60% Roe. Typical of marine shale source rocks, oils are 35deg API and higher, even at low thermal maturities.

Most of the Barnett Shale oil has been recovered in vertical wells in the oil window parts of the basin, that is, western and northern parts of the Fort Worth Basin. The Barnett Shale is thinner in the west but thickens toward the northeast and is less mature in both locations, with vitrinite reflectance values of about 0.60% Roe in Brown County in the far southwestern part of the basin and about 0.85% Roe in the north-northeastern parts of the basin, for example, Clay, Montague, and Cooke counties, Texas. Oil produced from a well in the southwest, the Explo Oil 3-Mitcham, yielded a 36deg API from the Barnett Shale at 0.60% Roe. Typical of marine shale source rocks, oils are 35deg API and higher, even at low thermal maturities.

Recent production is from the Barnett Shale itself, that is, a mudstone-dominated system with high quartz content. A critical assessment of this mudstone oil reservoir suggests that the organic-rich mudstone with high clay and quartz content and low carbonate content inhibits production of oil because of its organic richness (5–8% TOC in these areas). Storage porosity is also minimal with oil in nanopores associated with organic matter and matrix porosity (EOG Resources, 2010). Although biogenic silica yields are abundant, averaging upward of 40%, the close association of this biogenic silica with organic matter tends to inhibit flow of oil due not only to low permeability, but also the sorption of more polar components of oil to organic matter. Barnett Shale black oil tends to have a much broader range of petroleum present, as shown by Jarvie et al. (2007), so both molecular size and the presence of polar compounds in the oil, as well as minimal porosity and especially low permeability in the shale, all combine to inhibit flow from this reservoir.

Recent production is from the Barnett Shale itself, that is, a mudstone-dominated system with high quartz content. A critical assessment of this mudstone oil reservoir suggests that the organic-rich mudstone with high clay and quartz content and low carbonate content inhibits production of oil because of its organic richness (5–8% TOC in these areas). Storage porosity is also minimal with oil in nanopores associated with organic matter and matrix porosity.<ref name=EOGResources2010 /> Although biogenic silica yields are abundant, averaging upward of 40%, the close association of this biogenic silica with organic matter tends to inhibit flow of oil due not only to low permeability, but also the sorption of more polar components of oil to organic matter. Barnett Shale black oil tends to have a much broader range of petroleum present, as shown by Jarvie et al. (2007), so both molecular size and the presence of polar compounds in the oil, as well as minimal porosity and especially low permeability in the shale, all combine to inhibit flow from this reservoir.

Before the recent surge in pursuit of shale-oil resource systems, a vertical well drilled by Four Sevens Oil Co. in Clay County, northwestern Fort Worth Basin, had an initial production of about 32 m3/day (200 bbl/day) (L. Brogdon, 2008, personal communication). A geochemical log of this well shows oil crossover in the lower half of the Barnett Shale with a very low carbonate content (Figure 9). The Pennsylvanian Marble Falls lies conformably on top of the Barnett Shale, with TOC values less than 1.00% and with high carbonate contents between 50 and 75 wt. %. Compare this carbonate with that of the Middle Member of the Bakken Formation, and it is readily apparent that both the TOC and oil saturation are low. Thus, it is not just a matter of low TOC values in carbonates providing the low threshold to oil saturation as indicated by OSI, but the necessity of emplaced oil. As the TOC increases into the upper Barnett Shale, the carbonate content decreases. The average carbonate content in the Barnett Shale is 11 wt. %. From vitrinite equivalency based on a Tmax of about 0.80% Roe and HIs in the 280 mg/g range or about 35% conversion, the Barnett Shale is in the main phase of oil generation in this locale.

Before the recent surge in pursuit of shale-oil resource systems, a vertical well drilled by Four Sevens Oil Co. in Clay County, northwestern Fort Worth Basin, had an initial production of about 32 m3/day (200 bbl/day) (L. Brogdon, 2008, personal communication). A geochemical log of this well shows oil crossover in the lower half of the Barnett Shale with a very low carbonate content (Figure 9). The Pennsylvanian Marble Falls lies conformably on top of the Barnett Shale, with TOC values less than 1.00% and with high carbonate contents between 50 and 75 wt. %. Compare this carbonate with that of the Middle Member of the Bakken Formation, and it is readily apparent that both the TOC and oil saturation are low. Thus, it is not just a matter of low TOC values in carbonates providing the low threshold to oil saturation as indicated by OSI, but the necessity of emplaced oil. As the TOC increases into the upper Barnett Shale, the carbonate content decreases. The average carbonate content in the Barnett Shale is 11 wt. %. From vitrinite equivalency based on a Tmax of about 0.80% Roe and HIs in the 280 mg/g range or about 35% conversion, the Barnett Shale is in the main phase of oil generation in this locale.

The presence of reasonable to high amounts of silica, in this case biogenically derived and associated with organic matter, does not impact shale-oil resource systems the way it does shale-gas resource systems at least in those successes to date. Comparison of the Bakken and Niobrara with the Barnett Shale-oil resource system oil rates and recoveries demonstrates the importance of carbonates in shale-oil resource systems.

The presence of reasonable to high amounts of silica, in this case biogenically derived and associated with organic matter, does not impact shale-oil resource systems the way it does shale-gas resource systems at least in those successes to date. Comparison of the Bakken and Niobrara with the Barnett Shale-oil resource system oil rates and recoveries demonstrates the importance of carbonates in shale-oil resource systems.

More recently, vertical wells drilled by EOG Resources have had IPs of 48, 103, 70, 159, and 72 m3/day (300, 650, 440, 1000, and 450 bbl/day) of oil flow, with gas flow of 2832, 11,327, 19,822, 56,634, and 19,822 m3/day (100, 400, 700, 2,000, and 700 mcf/day), respectively, which they refer to as their combo Barnett Shale play (EOG Resources, 2010). These wells are located in Cooke and Montague counties, Texas, in the north and northeastern areas of the Fort Worth Basin. As shown by their argon ion-milled scanning electron microscope micrographs from western Cooke County, virtually no organic porosity exists, but matrix porosity was 2 to 3%, with pore throats of 4000 to 7000 nm (EOG Resources, 2010) or about 100 times greater than those found in the core gas-producing areas of the Barnett Shale. In Cooke County, northeastern Fort Worth Basin toward the Muenster arch, the Barnett Shale thickens to more than 213.4 m (700 ft) and becomes enriched in carbonate. In this area, debris flows have been inferred from core observations (Bowker, 2008). However, in western Montague County, Texas, EOG Resources reports pore throats of 4 to 50 nm, thereby making a more challenging production area despite a high quartz content and being in the oil window.

More recently, vertical wells drilled by EOG Resources have had IPs of 48, 103, 70, 159, and 72 m3/day (300, 650, 440, 1000, and 450 bbl/day) of oil flow, with gas flow of 2832, 11,327, 19,822, 56,634, and 19,822 m3/day (100, 400, 700, 2,000, and 700 mcf/day), respectively, which they refer to as their combo Barnett Shale play.<ref name=EOGResources2010 /> These wells are located in Cooke and Montague counties, Texas, in the north and northeastern areas of the Fort Worth Basin. As shown by their argon ion-milled scanning electron microscope micrographs from western Cooke County, virtually no organic porosity exists, but matrix porosity was 2 to 3%, with pore throats of 4000 to 7000 nm<ref name=EOGResources2010 /> or about 100 times greater than those found in the core gas-producing areas of the Barnett Shale. In Cooke County, northeastern Fort Worth Basin toward the Muenster arch, the Barnett Shale thickens to more than 213.4 m (700 ft) and becomes enriched in carbonate. In this area, debris flows have been inferred from core observations (Bowker, 2008). However, in western Montague County, Texas, EOG Resources reports pore throats of 4 to 50 nm, thereby making a more challenging production area despite a high quartz content and being in the oil window.

EOG Resources estimates that approximately 1.11 times 107 m3 (70 million bbl) of oil and 4.96 times 109 (175 billion ft3) of gas in place per 2.59 km2 (0.9 mi2) exist in their Barnett Shale acreage in eastern Montague and western Cooke counties, Texas (Darbonne, 2010). In the best oil-producing area of the Barnett Shale, EOG's average initial production rates are 39.7 to 159.0 m3 (250–1000 bbl) of oil, 20.7 m3 (130 bbl) of gas liquids per million ft3 of gas, and 2.83–5.66 times 104 (1–2 million ft3) of gas/day. They drill both vertical and horizontal wells with 0.081 km2 (20 ac) or tighter spacing on the former as the Barnett Shale is between 213.3 and 457.2 m (700–1500 ft) thick as it approaches the Muenster arch in the northeastern part of the Fort Worth Basin.

EOG Resources estimates that approximately 1.11 times 107 m3 (70 million bbl) of oil and 4.96 times 109 (175 billion ft3) of gas in place per 2.59 km2 (0.9 mi2) exist in their Barnett Shale acreage in eastern Montague and western Cooke counties, Texas (Darbonne, 2010). In the best oil-producing area of the Barnett Shale, EOG's average initial production rates are 39.7 to 159.0 m3 (250–1000 bbl) of oil, 20.7 m3 (130 bbl) of gas liquids per million ft3 of gas, and 2.83–5.66 times 104 (1–2 million ft3) of gas/day. They drill both vertical and horizontal wells with 0.081 km2 (20 ac) or tighter spacing on the former as the Barnett Shale is between 213.3 and 457.2 m (700–1500 ft) thick as it approaches the Muenster arch in the northeastern part of the Fort Worth Basin.

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The Upper Cretaceous Eagle Ford Shale is the source of Austin Chalk-produced oils (Grabowski, 1995) along a trend running from central northeastern Texas to south Texas counties bordering Mexico (no. 24 in Appendix immediately following this chapter, Figure 1, shale resource systems in North America). The Eagle Ford Shale averages about 3.7 to 4.5% TOC, with an original HI of about 414 mg HC/g TOC (Grabowski, 1995), although immature roadcuts in Val Verde County, Texas, have HI values more than 600 mg/g (D. M. Jarvie, unpublished data). Grabowski (1995) also estimates oil yields to be about 0.0515 m3/m3 (400 bbl/ac-ft), with values as high as 0.1547 m3/m3 (1200 bbl/ac-ft). EOG Resources currently estimates the Eagle Ford Shale play as having 1.43 times 108 m3 (900 million BOE) in their lease areas alone (EOG Resources, 2010).

The Upper Cretaceous Eagle Ford Shale is the source of Austin Chalk-produced oils (Grabowski, 1995) along a trend running from central northeastern Texas to south Texas counties bordering Mexico (no. 24 in Appendix immediately following this chapter, Figure 1, shale resource systems in North America). The Eagle Ford Shale averages about 3.7 to 4.5% TOC, with an original HI of about 414 mg HC/g TOC (Grabowski, 1995), although immature roadcuts in Val Verde County, Texas, have HI values more than 600 mg/g (D. M. Jarvie, unpublished data). Grabowski (1995) also estimates oil yields to be about 0.0515 m3/m3 (400 bbl/ac-ft), with values as high as 0.1547 m3/m3 (1200 bbl/ac-ft). EOG Resources currently estimates the Eagle Ford Shale play as having 1.43 times 108 m3 (900 million BOE) in their lease areas alone.<ref name=EOGResources2010 />

A geochemical database of Eagle Ford Shale demonstrates that many samples show oil crossover (Jarvie, 2007) (Figure 10). A geochemical log of the Champlin Petroleum Co. 1-Mixon well in De Witt County, Texas, illustrates what is commonly seen in wells along the Austin Chalk trend (Figure 11). This mudstone shale-gas/shale-oil resource system contains about 60% carbonate content on average. Thus, the Eagle Ford may be more aptly described as a calcareous shale or argillaceous lime mudstone (J. A. Breyer, 2010, personal communication). The lean TOC interval from 2475 to 2510 m (8120–8235 ft) is the Austin Chalk, which shows intermittent oil crossover. The Austin Chalk is productive along this trend, and such productive zones are readily identifiable by the oil crossover effect. The Eagle Ford Shale is present below 2511.5 m (8240 ft), and the TOC increases to a high of just less than 6.00%, with carbonate contents remaining very high. Intermittent, but consistent, oil crossover occurs in various intervals of this well, for example, 2523.7 to 2542.0 m (8280–8340 ft) and especially 2546.6 to 2572.5 m (8355–8440 ft). This geochemical log is typical of almost all wells along this trend that are in the oil or early wet gas window.

A geochemical database of Eagle Ford Shale demonstrates that many samples show oil crossover (Jarvie, 2007) (Figure 10). A geochemical log of the Champlin Petroleum Co. 1-Mixon well in De Witt County, Texas, illustrates what is commonly seen in wells along the Austin Chalk trend (Figure 11). This mudstone shale-gas/shale-oil resource system contains about 60% carbonate content on average. Thus, the Eagle Ford may be more aptly described as a calcareous shale or argillaceous lime mudstone (J. A. Breyer, 2010, personal communication). The lean TOC interval from 2475 to 2510 m (8120–8235 ft) is the Austin Chalk, which shows intermittent oil crossover. The Austin Chalk is productive along this trend, and such productive zones are readily identifiable by the oil crossover effect. The Eagle Ford Shale is present below 2511.5 m (8240 ft), and the TOC increases to a high of just less than 6.00%, with carbonate contents remaining very high. Intermittent, but consistent, oil crossover occurs in various intervals of this well, for example, 2523.7 to 2542.0 m (8280–8340 ft) and especially 2546.6 to 2572.5 m (8355–8440 ft). This geochemical log is typical of almost all wells along this trend that are in the oil or early wet gas window.

* Dembicki Jr., H., and F. L. Pirkle, 1985, Regional source rock mapping using a source potential rating index: AAPG Bulletin, v. 69, no. 4, p. 567–581.

* Dembicki Jr., H., and F. L. Pirkle, 1985, Regional source rock mapping using a source potential rating index: AAPG Bulletin, v. 69, no. 4, p. 567–581.

* Durham, L. S., 2009, Learning curve continues: Elm Coulee idea opened new play: AAPG Explorer, August 2009: http://www.aapg.org/explorer/2009/08aug/findley0809.cfm (accessed November 12, 2010).

* Durham, L. S., 2009, Learning curve continues: Elm Coulee idea opened new play: AAPG Explorer, August 2009: http://www.aapg.org/explorer/2009/08aug/findley0809.cfm (accessed November 12, 2010).

* EOG Resources, 2010, Investor presentation: EOG_2010, 223 p.: http://wwgeochem.com/references/EOGMay2010Investorpresentation.pdf (accessed November 12, 2010).

*  

* 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.

* 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.

* 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.

* 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.