Changes

The % Roe data from Tmax suggest a consistent trend over the 240 ft (73 m) interval reported. The Tmax increases from about 435 to 450degC (815 to 842degF) or 0.67 to 0.95% Roe. This is indicative of a very high paleogeothermal gradient, suggesting a very high heat flux. Zones with low Tmax values are oil-saturated carbonates, and those Tmax values are derived from oil, not kerogen.

The % Roe data from Tmax suggest a consistent trend over the 240 ft (73 m) interval reported. The Tmax increases from about 435 to 450degC (815 to 842degF) or 0.67 to 0.95% Roe. This is indicative of a very high paleogeothermal gradient, suggesting a very high heat flux. Zones with low Tmax values are oil-saturated carbonates, and those Tmax values are derived from oil, not kerogen.

A key well completed in the Denver Basin in September 2009 was the EOG Resources 2-01H-Jake in Hereford field, Weld County, Colorado, that had an initial production (IP) flow rate of 254 m3 (1600 bbl) of oil. As of August 31, 2010, this well had produced 12,496 m3 (78,599 bbl) of oil, 1.34 times 106 m3 (47,334 mcf) of gas, and 3371 m3 (21,201 bbl) of water, with an average GOR for 11 months of production of 116.8 m3/m3 (656 scf/bbl) (IHS Energy News on Demand, 2010).

A key well completed in the Denver Basin in September 2009 was the EOG Resources 2-01H-Jake in Hereford field, Weld County, Colorado, that had an initial production (IP) flow rate of 254 m3 (1600 bbl) of oil. As of August 31, 2010, this well had produced 12,496 m3 (78,599 bbl) of oil, 1.34 times 106 m3 (47,334 mcf) of gas, and 3371 m3 (21,201 bbl) of water, with an average GOR for 11 months of production of 116.8 m3/m3 (656 scf/bbl).<ref name=IHSENOD2010>IHS Energy News on Demand, 2010, Details reported on horizontal discovery in Power River Basin, March 16, 2010, press release.</ref>

Niobrara Shale activity is ongoing in a number of other Rocky Mountain basins, as well as the Powder River, Wind River, Washakie, Sand Wash, Piceance, and Park basins.

Niobrara Shale activity is ongoing in a number of other Rocky Mountain basins, as well as the Powder River, Wind River, Washakie, Sand Wash, Piceance, and Park basins.

[[File:M97Ch1.2FG9.jpg|thumb|500px|{{figure number|9}}Geochemical log of Four Sevens 1-Scaling Ranch A, Clay County, Texas, Fort Worth Basin showing the oil crossover in the lower Barnett Shale with its lean carbonate content. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

[[File:M97Ch1.2FG9.jpg|thumb|500px|{{figure number|9}}Geochemical log of Four Sevens 1-Scaling Ranch A, Clay County, Texas, Fort Worth Basin showing the oil crossover in the lower Barnett Shale with its lean carbonate content. TOC = total organic carbon; S1 = Rock-Eval measured oil contents; S2 = Rock-Eval measured kerogen yields.]]

The Barnett Shale has produced limited amounts of oil since the 1980s. Certainly much conventional production in the Fort Worth Basin has been sourced by the Barnett Shale, as substantiated by Hill et al. (2007).

The Barnett Shale has produced limited amounts of oil since the 1980s. Certainly much conventional production in the Fort Worth Basin has been sourced by the Barnett Shale, as substantiated by Hill et al.<ref>Hill, R. J., D. M. Jarvie, R. M. Pollastro, M. Henry, and J. D. King, 2007, [http://archives.datapages.com/data/bulletns/2007/04apr/BLTN06014/BLTN06014.HTM Oil and gas geochemistry and petroleum systems of the Fort Worth Basin], AAPG Bulletin Special Issue: AAPG Bulletin, v. 91, no. 4, p. 445–473, doi:10.1306/11030606014.</ref>

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.

====Mowry Shale, Powder River Basin====

====Mowry Shale, Powder River Basin====

In the Powder River Basin, there has been success in producing oil from the Lower Cretaceous Mowry Shale (IHS Energy News on Demand, 2010). The EOG Resources 1-16H-Trans Am well was reported to have flowed 3.2 m3/day (20 bbl/day) of oil, 8.5 times 104 m3/day (30,000 ft3/day) of gas, and 51.7 m3/day (325 bbl/day) of water (IHS Energy News on Demand, 2010). After 6 months of production, the well had produced 1023 m3/day (6436 bbl/day) of oil, 4.02 times 105 m3/day (14.2 million ft3/day) of gas, and 310.5 m3/day (1953 bbl/day) of water. The horizontal length was about 1167.08 m (3829 ft) with 14 hydraulic fracturing stages completed. Stimulation of various zones ranged from 3.18 times 102 to 3.18 times 103 m3 (2000–20,000 bbl) of slick water, with about 2.1772 times 104 to 1.81437 times 105 kg (48,000–400,000 lb) of 841/420 mum (20/40 mesh) and 149 mum (100 mesh) sand (scout ticket). The Mowry Shale is at about 2621.28 m (8600 ft) in this area.

In the Powder River Basin, there has been success in producing oil from the Lower Cretaceous Mowry Shale.<ref name=IHSENOD2010 /> The EOG Resources 1-16H-Trans Am well was reported to have flowed 3.2 m3/day (20 bbl/day) of oil, 8.5 times 104 m3/day (30,000 ft3/day) of gas, and 51.7 m3/day (325 bbl/day) of water.<ref name=IHSENOD2010 /> After 6 months of production, the well had produced 1023 m3/day (6436 bbl/day) of oil, 4.02 times 105 m3/day (14.2 million ft3/day) of gas, and 310.5 m3/day (1953 bbl/day) of water. The horizontal length was about 1167.08 m (3829 ft) with 14 hydraulic fracturing stages completed. Stimulation of various zones ranged from 3.18 times 102 to 3.18 times 103 m3 (2000–20,000 bbl) of slick water, with about 2.1772 times 104 to 1.81437 times 105 kg (48,000–400,000 lb) of 841/420 mum (20/40 mesh) and 149 mum (100 mesh) sand (scout ticket). The Mowry Shale is at about 2621.28 m (8600 ft) in this area.

The present-day TOC (TOCpd) values for the Mowry Shale only average 1.95%, with an estimated original TOC (TOCo) of 2.43%. The original hydrogen index (HIo) values average about 183 mg HC/g TOC, with a range from 128 to 400 mg/g. Based on the expulsion curves of Pepper<ref name=Ppper1992 /> based on original hydrogen index (HIo) values, such a system will expel between 0 and 50% of its generated products and, therefore, should retain a high percentage of generated products. At higher thermal maturities, peak to late oil window, the oil quality should be condensate-like in terms of API gravity. Oil crossover effect is noted in various intervals in Mowry Shale wells, but also in the underlying Muddy Formation sands that are produced as conventional reservoirs.

The present-day TOC (TOCpd) values for the Mowry Shale only average 1.95%, with an estimated original TOC (TOCo) of 2.43%. The original hydrogen index (HIo) values average about 183 mg HC/g TOC, with a range from 128 to 400 mg/g. Based on the expulsion curves of Pepper<ref name=Ppper1992 /> based on original hydrogen index (HIo) values, such a system will expel between 0 and 50% of its generated products and, therefore, should retain a high percentage of generated products. At higher thermal maturities, peak to late oil window, the oil quality should be condensate-like in terms of API gravity. Oil crossover effect is noted in various intervals in Mowry Shale wells, but also in the underlying Muddy Formation sands that are produced as conventional reservoirs.

A short horizontal well drilled by Columbia Gas Development Corp. in 1991, the 27-1-Kane Springs Federal, flowed 145 m3 (914 bbl) of oil and 8200 m3 (290 mcf) of gas over the Cane Creek Shale interval from 2267 to 2512 m (7438–8240 ft), with a pressure gradient of 19.2 kPa/m (0.85 psi/ft) (Chidsey et al., 2004).

A short horizontal well drilled by Columbia Gas Development Corp. in 1991, the 27-1-Kane Springs Federal, flowed 145 m3 (914 bbl) of oil and 8200 m3 (290 mcf) of gas over the Cane Creek Shale interval from 2267 to 2512 m (7438–8240 ft), with a pressure gradient of 19.2 kPa/m (0.85 psi/ft) (Chidsey et al., 2004).

A well drilled in 2009 by Whiting Oil amp Gas Corp., the 43-18H-Threemile in San Juan County, Utah, in the Cane Creek Shale was reported to have 8 to 13% porosity, 10 to 50 microdarcys permeability, and 20 to 35% water saturation; and was highly overpressured with a pressure gradient of 21.218 kPa/m (0.938 psi/ft) (Rasmussen et al., 2010). The well was completed with an uncemented liner and swell packers with 11-stage stimulation every 152.4 m (500 ft), each with 49,895.16 kg (110,000 lb) of proppant and 318 m3 (2000 bbl) of gel (Rasmussen et al., 2010). The scout ticket shows an initial flow rate of 1.145 m3/day (72 bbl/day) of oil, 1080 m3/day (38 mcf/day) of gas, and 31.16 m3/day (196 bbl/day) of water, but the well has since produced 1722 m3 (10,832 bbl) of oil, 5.16 times 104 m3 (1821 mcf) of gas, and 8863 m3 (55,745 bbl) of water, with a maximum GOR of 134.83 m3/m3 (757 scf/bbl) (IHS Energy News on Demand, 2010).

A well drilled in 2009 by Whiting Oil amp Gas Corp., the 43-18H-Threemile in San Juan County, Utah, in the Cane Creek Shale was reported to have 8 to 13% porosity, 10 to 50 microdarcys permeability, and 20 to 35% water saturation; and was highly overpressured with a pressure gradient of 21.218 kPa/m (0.938 psi/ft) (Rasmussen et al., 2010). The well was completed with an uncemented liner and swell packers with 11-stage stimulation every 152.4 m (500 ft), each with 49,895.16 kg (110,000 lb) of proppant and 318 m3 (2000 bbl) of gel (Rasmussen et al., 2010). The scout ticket shows an initial flow rate of 1.145 m3/day (72 bbl/day) of oil, 1080 m3/day (38 mcf/day) of gas, and 31.16 m3/day (196 bbl/day) of water, but the well has since produced 1722 m3 (10,832 bbl) of oil, 5.16 times 104 m3 (1821 mcf) of gas, and 8863 m3 (55,745 bbl) of water, with a maximum GOR of 134.83 m3/m3 (757 scf/bbl).<ref name=IHSENOD2010 />

An example of the Pennsylvanian Cane Creek section is provided by a geochemical log of the Mobil Oil Corp. 12-3-Jakeys Ridge well ([[:File:M97Ch1.2FG15.jpg|Figure 15]]). These data illustrate the high organic carbon content throughout this 755.9 m (5760.81 ft) interval of the Cane Creek Shale, with an overall average of 7.67%. However, four distinct intervals are present, with average TOC values over the uppermost interval of 67 m (219.81 ft) with 1.34%, 146.3 m (479.98 ft) of 4.91%, 231.7 m (701.11 ft) of 13.49%, and 42.7 m (140.09 ft) of 6.61%. Although extremely high oil contents (S1) are present in the organic-rich interval, the values only exceed 100 mg/g at 2315.5 m (7596.76 ft), whereas the uppermost lean zone in this well has the highest OSI values averaging 120 mg/g over 67 m (219.81 ft). Thermal maturity is middle oil window based on the % Roe from Tmax measurements. The present-day hydrogen index (HIpd) values are low given this level of thermal maturity, suggesting either high-level conversion at this thermal maturity or lower than expected HIo values. The HIo values are estimated to have been 123, 265, 475, and 356 mg/g for the four different organic richness zones previously described.

An example of the Pennsylvanian Cane Creek section is provided by a geochemical log of the Mobil Oil Corp. 12-3-Jakeys Ridge well ([[:File:M97Ch1.2FG15.jpg|Figure 15]]). These data illustrate the high organic carbon content throughout this 755.9 m (5760.81 ft) interval of the Cane Creek Shale, with an overall average of 7.67%. However, four distinct intervals are present, with average TOC values over the uppermost interval of 67 m (219.81 ft) with 1.34%, 146.3 m (479.98 ft) of 4.91%, 231.7 m (701.11 ft) of 13.49%, and 42.7 m (140.09 ft) of 6.61%. Although extremely high oil contents (S1) are present in the organic-rich interval, the values only exceed 100 mg/g at 2315.5 m (7596.76 ft), whereas the uppermost lean zone in this well has the highest OSI values averaging 120 mg/g over 67 m (219.81 ft). Thermal maturity is middle oil window based on the % Roe from Tmax measurements. The present-day hydrogen index (HIpd) values are low given this level of thermal maturity, suggesting either high-level conversion at this thermal maturity or lower than expected HIo values. The HIo values are estimated to have been 123, 265, 475, and 356 mg/g for the four different organic richness zones previously described.

* Francis, D., 2007, Reservoir analysis of Whangai Formation and Waipawa Black Shale: GNS New Zealand Government report, 11 p.

* Francis, D., 2007, Reservoir analysis of Whangai Formation and Waipawa Black Shale: GNS New Zealand Government report, 11 p.

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* Hill, R. J., D. M. Jarvie, R. M. Pollastro, M. Henry, and J. D. King, 2007, Oil and gas geochemistry and petroleum systems of the Fort Worth Basin, AAPG Bulletin Special Issue: AAPG Bulletin, v. 94, no. 4, p. 445–473, doi:10.1306/11030606014.

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* IHS Energy News on Demand, 2010, Details reported on horizontal discovery in Power River Basin, March 16, 2010, press release.

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* John, C., B. L. Jones, J. E. Moncrief, R. Bourgeois, and B. J. Harder, 1997, An unproven unconventional seven-billion barrel oil resource: The Tuscaloosa Marine Shale: http://www.lgs.lsu.edu/deploy/uploads/Tuscaloosa%20Marine%20Shale.pdf (accessed November 12, 2010).

* John, C., B. L. Jones, J. E. Moncrief, R. Bourgeois, and B. J. Harder, 1997, An unproven unconventional seven-billion barrel oil resource: The Tuscaloosa Marine Shale: http://www.lgs.lsu.edu/deploy/uploads/Tuscaloosa%20Marine%20Shale.pdf (accessed November 12, 2010).