Changes

Rock-Eval S1 or EOM yields alone have little meaning in assessing potential production because they do not account for the organic background. For example, coals might have an S1 value of 10 mg HC/g rock, but with a TOC of 50% or higher, the OSI is quite low, indicative of low oil saturation with a high expulsion or production threshold.

Rock-Eval S1 or EOM yields alone have little meaning in assessing potential production because they do not account for the organic background. For example, coals might have an S1 value of 10 mg HC/g rock, but with a TOC of 50% or higher, the OSI is quite low, indicative of low oil saturation with a high expulsion or production threshold.

An empirical value exceeding 100 mg oil/g TOC was used to identify potential reservoir intervals in a conventional reservoir in the Anadarko Basin<ref name=J&B1984 /> and similarly in vertical Monterey Formation wells.<ref name=Jrvetal1995>Jarvie, D. M., J. T. Senftle, W. Hughes, L. Dzou, J. J. Emme, and R. J. Elsinger, 1995, [http://wwgeochem.com/references/Jarvieetal1995Examplesandnewapplicationsinapplyingorganicgeochemistry.pdf Examples and new applications in applying organic geochemistry for detection and qualitative assessment of overlooked petroleum reservoirs], in J. O. Grimalt and C. Dorronsoro, eds., Organic geochemistry: Developments and applications to energy, climate, environment, and human history: 17th International Meeting on Organic Geochemistry, p. 380–382.</ref> Data from Sandvik et al.<ref name=Sndvk1992 /> and similarly by Pepper (1992) suggest organic matter retains a portion of generated petroleum cited by both authors to be about 10 g of liquids sorbed per 100 g organic matter, that is, 100 mg HC/g TOC. Thus, there is a resistance to oil flow until the sorption threshold is exceeded, that is, values of OSI greater than 100 mg hydrocarbons per g of TOC. As Rock-Eval S1 is not a live oil quantitation, but instead a variably preserved rock-oil system, there is certainly loss of light oil due to evaporation, sample handling, and preparation before analysis. Loss of S1 is often estimated to be 35% (Cooles et al., 1986), but it is highly dependent on organic richness, lithofacies, oil type (light or heavy), and sample preservation. Organic-lean rocks such as sands, silts, and carbonates as found in conventional reservoirs would have a much higher loss than organic-rich, low-permeability mudstones. Drying samples in an oven will certainly impact the free oil content in Rock-Eval S1. Oil-based mud systems preclude the use of the Rock-Eval S1 and OSI.

An empirical value exceeding 100 mg oil/g TOC was used to identify potential reservoir intervals in a conventional reservoir in the Anadarko Basin<ref name=J&B1984 /> and similarly in vertical Monterey Formation wells.<ref name=Jrvetal1995>Jarvie, D. M., J. T. Senftle, W. Hughes, L. Dzou, J. J. Emme, and R. J. Elsinger, 1995, [http://wwgeochem.com/references/Jarvieetal1995Examplesandnewapplicationsinapplyingorganicgeochemistry.pdf Examples and new applications in applying organic geochemistry for detection and qualitative assessment of overlooked petroleum reservoirs], in J. O. Grimalt and C. Dorronsoro, eds., Organic geochemistry: Developments and applications to energy, climate, environment, and human history: 17th International Meeting on Organic Geochemistry, p. 380–382.</ref> Data from Sandvik et al.<ref name=Sndvk1992 /> and similarly by Pepper<ref name=Ppper1992>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 organic matter retains a portion of generated petroleum cited by both authors to be about 10 g of liquids sorbed per 100 g organic matter, that is, 100 mg HC/g TOC. Thus, there is a resistance to oil flow until the sorption threshold is exceeded, that is, values of OSI greater than 100 mg hydrocarbons per g of TOC. As Rock-Eval S1 is not a live oil quantitation, but instead a variably preserved rock-oil system, there is certainly loss of light oil due to evaporation, sample handling, and preparation before analysis. Loss of S1 is often estimated to be 35% (Cooles et al., 1986), but it is highly dependent on organic richness, lithofacies, oil type (light or heavy), and sample preservation. Organic-lean rocks such as sands, silts, and carbonates as found in conventional reservoirs would have a much higher loss than organic-rich, low-permeability mudstones. Drying samples in an oven will certainly impact the free oil content in Rock-Eval S1. Oil-based mud systems preclude the use of the Rock-Eval S1 and OSI.

Although an oil crossover value of less than 100 mg HC/g TOC does not rule out the possibility of having producible oil, it does represent substantially higher risk based strictly on geochemical results. It may be that samples have been dried or more volatile liquids have evaporated, particularly in conventional reservoir lithofacies.

Although an oil crossover value of less than 100 mg HC/g TOC does not rule out the possibility of having producible oil, it does represent substantially higher risk based strictly on geochemical results. It may be that samples have been dried or more volatile liquids have evaporated, particularly in conventional reservoir lithofacies.

Potentially recoverable oil is still in the range of 0.0116 m3/m3 (90 bbl/ac-ft) or 2.09 times 106 m3/km2 (34 million bbl/mi2). The OIP value is estimated to average approximately 2.93 times 107 m3/km2 (184 million bbl/mi2) based on total oil yields from Rock-Eval data. This is not corrected upward for any potential hydrocarbon losses caused by evaporation and sample handling.

Potentially recoverable oil is still in the range of 0.0116 m3/m3 (90 bbl/ac-ft) or 2.09 times 106 m3/km2 (34 million bbl/mi2). The OIP value is estimated to average approximately 2.93 times 107 m3/km2 (184 million bbl/mi2) based on total oil yields from Rock-Eval data. This is not corrected upward for any potential hydrocarbon losses caused by evaporation and sample handling.

It is also obvious from this log that the thermal maturity is quite low with an equivalent percentage vitrinite reflectivity in oil (% Roe) of 0.37. This is likely lower than would be measured on extracted rock because of the presence of oil; however, the Monterey Shale in California is known to generate oil at lower thermal maturities than indicated by Tmax or Ro values (<ref name=Jrv1991>Jarvie, D. M., 1991, Factors affecting Rock-Eval-derived kinetic parameters: Chemical Geology, v. 93, p. 79–99, doi:10.1016/0009-2541(91)90065-Y.</ref>; Pepper and Corvi, 1995). The Tmax values of 410 to 425degC (770 to 797degF) represent about 20 to 50% conversion of high-oxygen, high-sulfur Monterey Shale to petroleum.<ref name=J&L2001>Jarvie, D. M., and L. L. Lundell, 2001, [http://www.wwgeochem.com/resources/Monterey+Paper+-+Chap+15+Jarvie+and+Lundell+2001.pdf Chapter 15: Amount, type, and kinetics of thermal transformation of organic matter in the Miocene Monterey Formation], in C. M. Isaacs and J. Rullkotter, eds., The Monterey Formation: From rocks to molecules: New York, Columbia University Press, p. 268–295.</ref>

It is also obvious from this log that the thermal maturity is quite low with an equivalent percentage vitrinite reflectivity in oil (% Roe) of 0.37. This is likely lower than would be measured on extracted rock because of the presence of oil; however, the Monterey Shale in California is known to generate oil at lower thermal maturities than indicated by Tmax or Ro values.<ref name=Jrv1991>Jarvie, D. M., 1991, Factors affecting Rock-Eval-derived kinetic parameters: Chemical Geology, v. 93, p. 79–99, doi:10.1016/0009-2541(91)90065-Y.</ref><ref>Pepper, A. S., and P. J. Corvi, 1995, Simple models of petroleum formation. Part I: Oil and gas generation from kerogen: Marine and Petroleum Geology, v. 12, p. 291–320.</ref> The Tmax values of 410 to 425degC (770 to 797degF) represent about 20 to 50% conversion of high-oxygen, high-sulfur Monterey Shale to petroleum.<ref name=J&L2001>Jarvie, D. M., and L. L. Lundell, 2001, [http://www.wwgeochem.com/resources/Monterey+Paper+-+Chap+15+Jarvie+and+Lundell+2001.pdf Chapter 15: Amount, type, and kinetics of thermal transformation of organic matter in the Miocene Monterey Formation], in C. M. Isaacs and J. Rullkotter, eds., The Monterey Formation: From rocks to molecules: New York, Columbia University Press, p. 268–295.</ref>

===Devonian Bakken Formation, Williston Basin===

===Devonian Bakken Formation, Williston Basin===

Production from fractured upper Bakken Shale has been ongoing since the 1980s from several fields in North Dakota including fields such as Bicentennial, Elkhorn Ranch, Buckhorn, Rough Rider, Demores, and Pierre Creek. Production reported by the North Dakota Geological Survey (2010) for fractured upper Bakken Shale is approximately 3,714,699 m3 (23 million bbl), with an average GOR from all upper Bakken Shale production of about 426 m3/m3 (2395 scf/bbl).

Production from fractured upper Bakken Shale has been ongoing since the 1980s from several fields in North Dakota including fields such as Bicentennial, Elkhorn Ranch, Buckhorn, Rough Rider, Demores, and Pierre Creek. Production reported by the North Dakota Geological Survey (2010) for fractured upper Bakken Shale is approximately 3,714,699 m3 (23 million bbl), with an average GOR from all upper Bakken Shale production of about 426 m3/m3 (2395 scf/bbl).

An independent geologist, Dick Findley, proposed the idea of producible oil in the Middle Member of the Bakken Formation in 1995, leading to the discovery of the giant Elm Coulee field in eastern Montana in 1996 with the first horizontal well drilled in 2000 (Durham, 2009). Taking Findley's idea, independent geologist Michael S. Johnson extrapolated the idea into Mountrail County, North Dakota, which is located on the eastern flank of the oil window based on various investigators (Meissner, 1978; Dembicki and Pirkle, 1985). Although the same facies of the Middle Member as found in Elm Coulee did not extend that far east, the Middle Member was still charged with oil as shown by the discovery well, the 1-36H-Parshall well that flowed 73.6 m3 (463 bbl/day) of 42deg API oil and 3624.5 m3/day (128 mcf/day) with a GOR of 49 m3/m3 (276 scf/bbl). The next well, the 2-36H-Parshall, flowed 140 m3 (883 bbl/day) of oil and 7079 m3 (250 mcf/day) of gas, yielding a GOR of 50.4 m3/m3 (283 scf/bbl). Recent production from Parshall and Sanish fields typically ranges from 318 to 636 m3 (2000–4000 bbl/day) using very long laterals (as much as 3044 m; ~10,000 ft).

An independent geologist, Dick Findley, proposed the idea of producible oil in the Middle Member of the Bakken Formation in 1995, leading to the discovery of the giant Elm Coulee field in eastern Montana in 1996 with the first horizontal well drilled in 2000 (Durham, 2009). Taking Findley's idea, independent geologist Michael S. Johnson extrapolated the idea into Mountrail County, North Dakota, which is located on the eastern flank of the oil window based on various investigators.<ref>Meissner, F. F., 1978, Petroleum geology of the Bakken Formation, Williston Basin, North Dakota and Montana, in D. Estelle and R. Miller, eds., The economic geology of the Williston Basin, 1978 Williston Basin Symposium: Billings, Montana, Montana Geological Society, p. 207–230.</ref><ref>Dembicki Jr., H., and F. L. Pirkle, 1985, [http://archives.datapages.com/data/bulletns/1984-85/data/pg/0069/0004/0550/0567.htm Regional source rock mapping using a source potential rating index]: AAPG Bulletin, v. 69, no. 4, p. 567–581.</ref> Although the same facies of the Middle Member as found in Elm Coulee did not extend that far east, the Middle Member was still charged with oil as shown by the discovery well, the 1-36H-Parshall well that flowed 73.6 m3 (463 bbl/day) of 42deg API oil and 3624.5 m3/day (128 mcf/day) with a GOR of 49 m3/m3 (276 scf/bbl). The next well, the 2-36H-Parshall, flowed 140 m3 (883 bbl/day) of oil and 7079 m3 (250 mcf/day) of gas, yielding a GOR of 50.4 m3/m3 (283 scf/bbl). Recent production from Parshall and Sanish fields typically ranges from 318 to 636 m3 (2000–4000 bbl/day) using very long laterals (as much as 3044 m; ~10,000 ft).

The Parshall field has proven to be a major field covering more than 3840 km2 (950,000 ac). The North Dakota Department of Mineral Resources projects estimated recoverable oil at 3.331 times 108 m3 (2.1 billion bbl), representing less than 1.5% of OIP (Johnson, 2009).

The Parshall field has proven to be a major field covering more than 3840 km2 (950,000 ac). The North Dakota Department of Mineral Resources projects estimated recoverable oil at 3.331 times 108 m3 (2.1 billion bbl), representing less than 1.5% of OIP (Johnson, 2009).

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 (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.

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 (1992) 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 geochemical log of the Home Petroleum 2-Phoenix Unit in Johnson County, Wyoming, shows oil crossover in the Mowry Shale at 3478.51 m (11,412.4 ft) (Figure 13). The oil yield is reasonably high in this interval of 17.7 m (58 ft). This computes to about 2.385 times 105 m3/2.589988 km2 (1,500,000 bbl/mi2) using unadjusted S1 values.

A geochemical log of the Home Petroleum 2-Phoenix Unit in Johnson County, Wyoming, shows oil crossover in the Mowry Shale at 3478.51 m (11,412.4 ft) (Figure 13). The oil yield is reasonably high in this interval of 17.7 m (58 ft). This computes to about 2.385 times 105 m3/2.589988 km2 (1,500,000 bbl/mi2) using unadjusted S1 values.

* 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, doi:10.1016/0146-6380(86)90026-4.

* 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, doi:10.1016/0146-6380(86)90026-4.

* Darbonne, N., 2010, EOG's Mark Papa: Barnett combo one of the “richest oil deposits we've ever encountered”: Oil and Gas Investor, February 2010: http://www.oilandgasinvestor.com/Headlines/2010/2/item53192.php (accessed March 27, 2010).

* Darbonne, N., 2010, EOG's Mark Papa: Barnett combo one of the “richest oil deposits we've ever encountered”: Oil and Gas Investor, February 2010: http://www.oilandgasinvestor.com/Headlines/2010/2/item53192.php (accessed March 27, 2010).

* 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.

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* 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).

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* Mango, F. D., 1997, The light hydrocarbons in petroleum: A critical review: Organic Geochemistry, v. 26, no. 7/8, p. 417–440.

* Mango, F. D., 1997, The light hydrocarbons in petroleum: A critical review: Organic Geochemistry, v. 26, no. 7/8, p. 417–440.

* Mango, F. D., and D. M. Jarvie, 2001, GOR from oil composition (abs.): 20th International Meeting on Organic Geochemistry, Nancy, France, September 10–14, 2001, v. 1, p. 406–407: http://wwgeochem.com/references/MangoandJarvie2001GORfromoilcomposition.pdf (accessed November 12, 2010).

* Mango, F. D., and D. M. Jarvie, 2001, GOR from oil composition (abs.): 20th International Meeting on Organic Geochemistry, Nancy, France, September 10–14, 2001, v. 1, p. 406–407: http://wwgeochem.com/references/MangoandJarvie2001GORfromoilcomposition.pdf (accessed November 12, 2010).

* Meissner, F. F., 1978, Petroleum geology of the Bakken Formation, Williston Basin, North Dakota and Montana, in D. Estelle and R. Miller, eds., The economic geology of the Williston Basin, 1978 Williston Basin Symposium: Billings, Montana, Montana Geological Society, p. 207–230.

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* Miranda, R. M., and C. C. Walters, 1992, Geochemical variations in sedimentary matter within a “homogeneous” shale core (Tuscaloosa Formation, Upper Cretaceous, Mississippi: Organic Geochemistry, v. 18, no. 6, p. 899–911, doi:10.1016/0146-6380(92)90057-5.

* Miranda, R. M., and C. C. Walters, 1992, Geochemical variations in sedimentary matter within a “homogeneous” shale core (Tuscaloosa Formation, Upper Cretaceous, Mississippi: Organic Geochemistry, v. 18, no. 6, p. 899–911, doi:10.1016/0146-6380(92)90057-5.

* North Dakota Geological Survey, 2008, Bakken TOCs: https://www.dmr.nd.gov/ndgs/bakken/bakkenthree.asp (accessed May 10, 2009).

* North Dakota Geological Survey, 2008, Bakken TOCs: https://www.dmr.nd.gov/ndgs/bakken/bakkenthree.asp (accessed May 10, 2009).

* Oil amp Gas Journal, 2010b, Pioneer to pursue oil in Lower Wolfcamp shale: http://www.ogj.com/index/article-display/0885614732/articles/oil-gas-journal/explorationdevelopment-2/2010/10/pioneer-to_pursue.html (accessed November 12, 2010).

* Oil amp Gas Journal, 2010b, Pioneer to pursue oil in Lower Wolfcamp shale: http://www.ogj.com/index/article-display/0885614732/articles/oil-gas-journal/explorationdevelopment-2/2010/10/pioneer-to_pursue.html (accessed November 12, 2010).

* Oil amp Gas Journal, 2010c, Whiting Petroleum's sweet spot is most prolific part of the Bakken: http://www.pennenergy.com/index/petroleum/display/6670774195/articles/oil-gas-financial-journal/volume-6/Issue_7/Features/Whiting_Petroleum_s__sweet_spot__is_most_prolific_part_of_the_Bakken.html (accessed November 12, 2010).

* Oil amp Gas Journal, 2010c, Whiting Petroleum's sweet spot is most prolific part of the Bakken: http://www.pennenergy.com/index/petroleum/display/6670774195/articles/oil-gas-financial-journal/volume-6/Issue_7/Features/Whiting_Petroleum_s__sweet_spot__is_most_prolific_part_of_the_Bakken.html (accessed November 12, 2010).

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* Rasmussen, L., T. Smith, L. Canter, M. Sonnenfeld, and J. Forster, 2010, Analysis of a long Cane Creek horizontal: New insight into an unconventional tight oil resource play, Paradox Basin, Utah (abs.): AAPG Rocky Mountain Section meeting, Durango, Colorado, June 13–16, 2010, AAPG Search and Discovery 90106: http://www.searchanddiscovery.net/abstracts/pdf/2010/rms/abstracts/ndx_rasmussen03.pdf (accessed November 12, 2010).

* Rasmussen, L., T. Smith, L. Canter, M. Sonnenfeld, and J. Forster, 2010, Analysis of a long Cane Creek horizontal: New insight into an unconventional tight oil resource play, Paradox Basin, Utah (abs.): AAPG Rocky Mountain Section meeting, Durango, Colorado, June 13–16, 2010, AAPG Search and Discovery 90106: http://www.searchanddiscovery.net/abstracts/pdf/2010/rms/abstracts/ndx_rasmussen03.pdf (accessed November 12, 2010).