Tuesday, August 26, 2008

New Shale Gas Plays In Europe

How long will it take Europeans to catch on to the idea gas can be produced from thick and extensive organic rich shales? Are there capable drilling rigs available? Are there engineers with the knowledge to drill and complete horizontal wells? These are big questions. My guess is this gas will be produced, it is just a question of when.


Europeans Starting to Search for Shale Gas
By David Jolly
While American shale-gas recovery efforts are booming, Europe is just getting into the game.
The first hurdle is to learn just how much shale gas might be available for recovery. Europe has numerous sites of potential interest.

"There's a possibility that under our feet are the same kind of shale-gas deposits that you have in the United States," said Brian Horsfield, a professor of organic geochemistry at the GFZ German Research Center for Geosciences in Potsdam, Germany. "There are many of the same types of shale formations in Europe."

Working with institutions in France, the Netherlands and elsewhere, GFZ scientists will in January begin a six-year industry- financed study to map possible shale-gas sites in Europe. They will investigate the possibility of commercial recovery, using the Barnett shales around Fort Worth, Texas, as a yardstick. Their first project involves shale deposits in Sweden, the Netherlands and Germany, but there are other shale deposits in Austria, France, Poland and elsewhere.

New gas supplies would be welcome news to European Union officials, who have grown anxious over their increasing energy dependence on a resurgent Russia. Gazprom, the Russian state monopoly, already supplies more than a quarter of European natural gas needs.

"The Europeans have to hope that these shales will do for them what eastern shales have done for the U.S. gas supply, which is to boost the main supply that is coming from the Gulf of Mexico," said Don Hertzmark, an oil and gas consultant in Washington. "That would reduce the prices the Russians were able to charge the final consumers in Europe."

Companies are reticent about discussing their exploration activities, possibly because they fear land speculation could raise their costs. In Texas and Louisiana, mineral rights prices skyrocketed after the discovery of recoverable shale gas. Horsfield said the same land-rush mentality has begun to appear in Europe, with "huge interest, not just from locals, but also from as far away as Canada and Australia."

OMV, an Austrian energy company, has been conducting tests of gas shale in the Vienna Basin, an area that has provided hundreds of millions of barrels of oil since the 1930s. Ashiq Hussain, an OMV executive, was quoted in a March interview with Platts's International Gas Report as saying the gas deposits in the basin were "quite substantial," though he noted that the deposits lay far deeper than those of the Barnett shale in Texas. The deeper the gas deposits, the higher the market price of gas would need to be to make recovery economically feasible.
"We've started with projects on shale gas, but we're actually in the first phase of evaluation," said Christa Hanreich, an OMV spokeswoman.

Elsewhere, Royal Dutch Shell has obtained contracts to explore for gas in two sites in southern Sweden. And Lane Energy Poland is exploring in that country.
"Nobody even knew what we were talking about when we got started 18 months ago," said Kamlesh Parmar, director of Lane Energy Poland. The company was granted licenses in October to explore one million acres, or 405,000 hectares, in Poland's Baltic Basin region.
Despite the new enthusiasm, it will take years to develop Europe's gas resources, assuming doing so is economically feasible.

"It's at a very embryonic stage in comparison to the United States," said Alastair Syme, an energy-sector analyst at Merrill Lynch in London. "It's a story for the middle of the next decade, not for right now."

Originally published by The New York Times Media Group.
(c) 2008 International Herald Tribune. Provided by ProQuest LLC. All rights Reserved.

Friday, August 22, 2008

The Woodford Shale, A Major New Unconventional Oil And Gas Play

With the advent of new horizontal drilling and frac techniques, the Woodford Shale exhibits the potential to become a major new oil and gas play in the Midcontinent and West Texas areas of the Unitied States. Look at the numbers given for the potentially recoverable volumes of oil and gas. Can we "drill our way" out of America's dependence on foreign oil? GP


Reservoir characteristics and production potential of the Woodford Shale
With enough oil and gas to potentially become a major unconventional hydrocarbon reservoir, the Woodford is a viable play.

John B. Comer , Indiana Geological Survey, Bloomington, Indiana

The Woodford Shale is an attractive target for unconventional oil and gas development because it is a mature source rock that is widely distributed throughout the southern midcontinent, and because it locally produces oil and gas from naturally fractured intervals in conventionally completed wells. 1 In addition, drilled intervals yield oil shows from cuttings and cores, and produce a gas response on mudlogs, confirming that the Woodford Shale contains anomalously high oil and gas. Finally, the Woodford play that has developed in Oklahoma (279 wells drilled from 2004 to 2007 with cumulative production of nearly 64 Bcf gas and 66,538 bbl oil/condensate)2 confirms the commercial viability of the Woodford and provides incentive for additional exploration and development.

The following provides a regional overview of the oil and gas producing potential of the Woodford Shale in the US southern midcontinent. The article focuses on the Anadarko and Permian Basin depocenters and adjacent provinces, where organic-rich Woodford facies are thickest, and where conventional oil and gas production and infrastructure are extensive, Fig. 1. Of particular importance are source rock properties, especially Total Organic Carbon (TOC) and thermal maturity, and lithologic properties, especially silica content and type. Also, the geographic distribution of lithofacies, organic hydrogen content and thickness are important in deciding where to drill, and they allow volumes of oil-in-place and gas-in-place to be estimated. 3
Fig. 1 . Map showing geologic provinces with Woodford Shale in the (A) Anadarko Basin and (B) Permian Basin. 3

Hydrocarbon source rocks (> 0.5 weight percent TOC) are attractive targets for unconventional drilling because their hydrocarbons are indigenous and their hydrocarbon charge does not depend on the fortuitous and inefficient processes of expulsion from a fine-grained source bed, secondary migration through porous and permeable carrier beds, and accumulation in an adequately sealed reservoir.

Source rocks that contain the highest concentrations of organic hydrogen generate the most hydrocarbons. These are typically beds of lacustrine and marine origin that contain Type I and Type II kerogen and generate both oil and gas during thermal maturation.
Oil-to-rock correlation studies document that the Woodford Shale is a prolific oil source, 4-13 and estimates indicate that as much as 85% of the oil produced in central and southern Oklahoma originated in the Woodford. 13 The Woodford Shale contains high concentrations of marine organic matter, 14-19 with mean organic carbon concentrations of 4.9 percent weight for the Permian Basin (Texas and New Mexico), 5.7 percent weight for the Anadarko Basin (Oklahoma and Arkansas) and 5.2 percent weight for both regions combined, Fig. 2. Organic carbon concentrations range from less than 0.1 percent weight in some chert beds 15 to 35 percent weight in black shale, 18 and the organic matter is mostly oil-prone Type II kerogen. 1,14,15,18 Across the region, the Woodford Shale exhibits a wide range of thermal maturities from marginally immature to metamorphic (Ro = 0.37-4.89 %). 15,20

Fig. 2 . TOC concentrations (weight percent) and statistics for geologic provinces in the southern midcontinent. Mean organic carbon concentration exceeds 2.0 weight percent in each of the provinces listed.

The Woodford Shale is mostly Late Devonian, but ranges in age from Middle Devonian to Early Mississippian. 21-24 Age-equivalent strata include the Chattanooga Shale, Misener Sandstone, Sylamore Sandstone, the middle division of the Arkansas Novaculite, upper part of the Caballos Novaculite, Houy Formation, Percha Shale and the Sly Gap Formation. 21,24-30 These units were deposited over a major regional unconformity and represent diachronous onlapping sediments. 21,31-35 In the southern midcontinent, these units are the stratigraphic record of worldwide Late Devonian marine transgression. The Woodford is stratigraphically equivalent to several North American Devonian black shales with active and potential unconventional oil and gas production, including the Antrim Shale (Michigan Basin), Ohio Shale (Appalachian Basin), New Albany Shale (Illinois Basin), Bakken Shale (Williston Basin) and Exshaw Formation (Western Canada Basin).

The Woodford is identified primarily by high radioactivity on the gamma-ray log and by its stratigraphic position between carbonates, Fig. 3. The Woodford exhibits low sonic velocity, low resistivity and low neutron-induced radiation. Three subdivisions (the lower, middle and upper units) are commonly recognized in the Woodford, and can be correlated regionally based on well log signatures. 36 The lower unit immediately overlies the regional unconformity, has the lowest radioactivity, and contains more carbonate, silt and sand than the other two units. The middle unit has the highest radioactivity, is the most widespread lithofacies, and consists of black shale with high concentrations of organic carbon, abundant pyrite, resinous spores and parallel laminae. The upper unit has intermediate radioactivity and consists of black shale with few resinous spores and mostly parallel laminae.

Fig. 3 . Characteristic well logs for the Permian Basin and Anadarko Basin regions. (A) Permian Basin, Winkler County, Texas.36 (B) Anadarko Basin, Major County, Oklahoma. 37

The most widespread and characteristic Woodford Shale lithology is black shale. Other common lithologies include chert, siltstone, sandstone, dolostone and light-colored shale, with hybrid mixtures between them. 14,15,21-23,38 Optimum reservoir lithologies are siliceous and include the cherts, siltstones, cherty black shales and silty black shales that are dense and brittle and, when fractured, retain open fracture networks. Production potential is greatest where these lithologies are organic-rich, thermally mature and highly fractured. Naturally-fractured Woodford Shale reservoirs, which have produced hydrocarbons for many decades, are completed in organic-rich chert intervals. 1 Figure 4 displays photomicrographs of cherty black shale in a naturally-fractured Woodford reservoir with bitumen-filled fractures from an oil-producing zone. Figure 4A was taken at a depth of 3,056 ft and has 4.5% TOC, and Figure 4B was taken at 3,065 ft and has 7.8% TOC. The association of chert and fractures in producing reservoirs suggests that the best unconventional wells are likely to be completed in the cherty facies.

Fig. 4 . Photomicrographs of core from Texaco No. 1K Drummond, Marshall County, Oklahoma, 11-6S-6E, North Aylesworth field. 1 White elliptical bodies are recrystallized Radiolaria. Photographed in transmitted plane polarized light.

The Woodford facies distribution is the result of Late Devonian paleogeography and depositional processes. During the Late Devonian, the southern midcontinent lay along the western margin of North America in the warm dry tropics near 15° south latitude. 14,39 Woodford deposition began as sea level rose, drowning marine embayments in what are now the deepest parts of the Delaware, Val Verde, Anadarko and Arkoma Basins, and advancing over subaerially eroded, dissected terrane consisting of Ordovician to Middle Devonian carbonate rocks. The broad epeiric sea that formed had irregular bottom topography and scattered, low-relief land masses which supported little vegetation and few rivers.

Oceanic water from an area of coastal upwelling flowed into the expanding epeiric sea and maintained a normal marine biota in the upper levels of the water column. Net evaporation locally produced hypersaline brine, and strong density stratification developed that restricted vertical circulation and resulted in bottom waters depleted in oxygen. Pelagic debris from the thriving biomass settled to the anoxic sea floor where organic- and sulfide-rich mud accumulated. The slow, continuous settling of pelagic debris was interrupted periodically by frequent storms and occasional earthquakes that triggered turbid bottom flows that supplied silt and mud to proximal shelves and basin depocenters, and caused resedimentation throughout the epeiric sea.

This depositional model explains why quartz grains and chert have very different distributions. Quartz grains represent terrigenous detritus transported from exposed older sources. Chert is biogenic and represents siliceous microorganisms (mostly Radiolaria) that bloomed in the nutrient-rich, upwelled water of the ocean and recrystallized after deposition on the sea floor. Detrital quartz is most abundant in areas near land, especially along the northwestern shelf and in the northwestern part of the Anadarko Basin, and in basin depocenters where turbid bottom flows finally converged. Chert beds increase in abundance and thickness toward the open ocean and are common along the continental margin and in distal parts of the major cratonic basins (Delaware, Anadarko, Marietta, Ardmore and Arkoma). The most distal allochthonous beds in the central area and core area of the Ouachita Tectonic Belt are almost pure radiolarian chert. High concentrations of radiolarian chert coincide with high concentrations of organic carbon along distal highs, such as the Central Basin Platform, Pecos Arch and Nemaha Uplift, and along the craton margin in the Arbuckle Mountain Uplift, Marietta and Ardmore Basins, western Arkoma Basin and frontal zone of the Ouachita Tectonic Belt. Where thermally mature, the organic-rich cherts and cherty black shales in these areas are optimum exploration targets.

Thermal maturity follows Woodford structure, with the highest maturities in the deep basins and in orogenic belts, and the lowest maturities along structural highs, Fig. 5. 14,15,18,20,40-43 The Woodford Shale reaches its highest thermally maturity in the Anadarko, Delaware and Arkoma Basins where it is most deeply buried, and in the Ouachita Tectonic Belt where stratigraphically equivalent beds have been locally metamorphosed. Intermediate maturities occur in shelf settings, and the lowest maturities occur on structural highs such as the Central Basin Platform, Pecos Arch, Nemaha Uplift, Arbuckle Mountain Uplift and the frontal zone of the Ouachita Tectonic Belt. In deep basins, the Woodford Shale is in the gas generation window, whereas in the shelf and platform settings, the Woodford is in the oil generation window. 14,15

Fig. 5 . Map showing thermal maturity of Woodford Shale and age-equivalent units in (A) Anadarko and (B) Permian Basin regions. 3 Patterns are based on vitrinite reflectance (%Ro).

Potential production trends have been qualitatively ranked based on the probability that brittle or naturally fractured, thermally mature organic-rich beds of Woodford Shale are present in the subsurface, Fig. 6. The trends are designated as areas of probable, possible, local and poor success as follows. Probable success areas are those where organic-rich Woodford Shale is in the gas generation stage of thermally maturity and where large volumes of gas are likely to reside. Possible success areas are those where organic-rich Woodford beds are in the oil window and where the formation is shallow enough for economic drilling and for open fracture networks to persist. Local success areas are those in shelf settings where the Woodford Shale is relatively thin, but thermally mature and at a relatively shallow depth. Poor success areas are those where the formation is exposed at the surface or is shallow and unconfined, and where Woodford Shale or equivalent units have been metamorphosed or have very low organic carbon content.

Fig. 6 . Map showing hydrocarbon production potential and estimated volumes of oil-in-place and gas-in-place for Woodford Shale and age-equivalent units in the (A) Anadarko and (B) Permian Basin regions. 3

The resource potential estimations assume that oil and gas in the Woodford Shale are indigenous, and were calculated based on organic carbon concentration, organic hydrogen concentration, organic matter type, thermal maturity and facies volumes (thickness times area), Fig. 6. 3 While this is not an assessment of recoverable oil and gas, it does estimate total gas-in-place and oil-in-place through mass balance calculations based on the concentration of organic hydrogen in the source beds. 3 The data suggest that total in-place gas in the Woodford Shale is on the order of 830 Tcf and total in-place oil is on the order of 250 Bbbl in the southern midcontinent. These volumes include 130 Bbbl of oil-in-place in the Anadarko Basin region, and 230 Tcf of gas-in-place and 120 Bbbl of oil-in-place in the Permian Basin region.

In the Anadarko Basin region, the estimated gas potential is 600 Tcf in the area of probable success, an area that includes the Anadarko and Arkoma Basins. The estimated gas potential is 0.24 Tcf and the estimated oil potential is 70 Bbbl in the area of possible success, encompassing the Nemaha Uplift, Marietta and Ardmore Basins, Arbuckle Mountain Uplift, southern flank of the Anadarko Basin, and frontal zone of the Ouachita Tectonic Belt in Oklahoma. About 4.4 Tcf of gas-in-place and 60 Bbbl of oil-in-place are estimated for the area of local success, which includes most of the northern and central Oklahoma Platforms.

In the Permian Basin region, the estimated gas potential is 220 Tcf in the area of probable success, which includes the Delaware and Val Verde Basins. The estimated gas potential is 0.11 Tcf and the estimated oil potential is 35 Bbbl in the area of possible success, encompassing the Central Basin Platform and northern flank of the Pecos Arch. About 9 Tcf of gas-in-place and 84 Bbbl of oil-in-place are estimated for the area of local success, which encompasses much of the shelf and platform provinces and most of the Midland Basin.

Although estimates of the volume of undiscovered hydrocarbons are inherently problematic because of the assumptions that must be made to complete the calculations, the mass balance approach yields orders-of-magnitude for in-place oil and gas, and provide a consistent means to compare and rank different areas of interest as to their hydrocarbon production potential.

The Woodford Shale is a major unconventional energy resource with the potential for producing significant volumes of both oil and gas. Intuitively, its status as a world-class oil source rock indicates that the formation should contain large residual concentrations of hydrocarbons, and analytical data from numerous studies confirm this inference. The inherent inefficiency of hydrocarbon expulsion is the primary reason why source rocks like the Woodford retain large volumes of oil and gas and are attractive targets for unconventional exploration. Given the ubiquity and magnitude of oil and gas shows, local production from naturally fractured reservoirs, recent unconventional production from the Woodford Shale in Oklahoma, successes in unconventional resource recovery from analogous formations, and current oil and gas prices, the Woodford Shale in the southern midcontinent is a compelling exploration target.

Optimum locations for exploration are where organic-rich beds are currently in the oil or gas generation window. Optimum reservoir facies are those comprising brittle lithologies capable of maintaining open fracture networks. The best reservoirs are likely to be completed in mature organic-rich cherts and cherty black shales but other lithologies, such as sandstone, organic-rich siltstone, and silty black shale, can also be expected to produce locally. Areas having the greatest production potential and most prospective lithologies are the Anadarko Basin in Oklahoma, Marietta and Ardmore Basins in Oklahoma, Arkoma Basin in Oklahoma and Arkansas, frontal zone of the Ouachita Tectonic Belt, Delaware Basin in Texas and New Mexico, Central Basin Platform in Texas and New Mexico and the Val Verde and Midland Basins in Texas.

The author is indebted to Indiana Geological Survey colleagues Kimberly H. Sowder, Barbara T. Hill and Renee D. Stubenrauch, who drafted the figures and formatted the photographs for this article. Also, IGS staff scientists Margaret V. Ennis, Nancy R. Hasenmueller, Maria D. Mastalerz, and Charles W. Zuppann reviewed the article and offered constructive criticisms. IGS editor Deborah A. DeChurch proofread the manuscript. Publication is authorized by John C. Steinmetz, State Geologist and Director of the Indiana Geological Survey.

1 Comer, J. B. and H. H. Hinch, “Recognizing and quantifying expulsion of oil from the Woodford Formation and age-equivalent rocks in Oklahoma and Arkansas,” AAPG Bulletin, Vol. 71, No. 7, 1987, pp. 844-858.

2 Cardott, B. J., “Overview of Woodford gas-shale play of Oklahoma, US,” Oklahoma Geological Survey, http://www.ogs.ou.edu/pdf/AAPG08woodford.pdf, accessed May 28, 2008.

3 Comer, J. B., “Facies distribution and hydrocarbon production potential of Woodford Shale in the southern Midcontinent,” in Cardott, B. J., ed., Unconventional Energy Resources in the Southern Midcontinent, 2004 Symposium, Oklahoma Geological Survey, Circular 110, Norman, Okla., 2005, pp. 51-62.

4 Brenneman, M. C. and P. V. Smith, “The chemical relationships between crude oils and their source rocks,” in Weeks, L. G., ed., Habitat of Oil, American Association of Petroleum Geologists, Tulsa, Okla., 1958, pp. 818-849.

5 Welte, D. H., Hagemann, H. W., Hollerbach, A., Leythaeuser, D. and W. Stahl, “Correlation between petroleum and source rock,” Proceedings of the Ninth World Petroleum Congress, Vol. 2, 1975, pp. 179-191.

6 Lewan, M. D., Winters, J. C. and J. H. McDonald, “Generation of oil-like pyrolyzates from organic-rich shales,” Science, Vol. 203 No. 4383, 1979, pp. 897-899.

7 Winters, J. C., Williams, J. A. and M. D. Lewan, “A laboratory study of petroleum generation by hydrous pyrolysis,” in Bjoroy, M. et al., eds., Advances in Organic Geochemistry 1981, John Wiley, Chichester, United Kingdom, 1983, pp. 524-533.

8 Iztan, Y. H., “Geochemical correlation between crude oils from Misener reservoirs and potential source rocks in central and north-central Oklahoma,” Unpublished Master’s Thesis, University of Tulsa, 1985, p. 191.

9 Reber, J. J., “Correlation and biomarker characterization of Woodford-type oil and source rock, Aylesworth Field, Marshall County, Oklahoma,” Unpublished Master’s Thesis, University of Tulsa, 1988, p. 96.

10 Burruss, R. C. and J. R. Hatch, “Geochemistry of oils and hydrocarbon source rocks, greater Anadarko Basin: Evidence for multiple sources of oils and long-distance oil migration,” in Johnson, K. S., ed., Anadarko Basin Symposium, 1988, Oklahoma Geological Survey, Circular 90, Norman, Okla., 1989, pp. 53-64.

11 Philp, R. P., Jones, P. J., Lin, L. H., Michael, G. E. and C. A. Lewis, “An organic geochemical study of oils, source rocks, and tar sands in the Ardmore and Anadarko Basins,” in Johnson, K. S., ed., Anadarko Basin Symposium, 1988, Oklahoma Geological Survey, Circular 90, Norman, Okla., 1989, pp. 65-76.

12 Rice, D. D., Threlkeld, C. N. and A. K. Vuletich, “Characterization and origin of natural gases of the Anadarko Basin,” in Johnson, K. S., ed., Anadarko Basin Symposium, 1988, Oklahoma Geological Survey, Circular 90, Norman, Okla., 1989, pp. 47-52.

13 Jones, P. J. and R. P. Philp, “Oils and source rocks from Pauls Valley, Anadarko Basin, Oklahoma, US,” Applied Geochemistry, Vol. 5, No.4, 1990, pp. 429-448.
14 Comer, J. B., “Stratigraphic analysis of the Upper Devonian Woodford Formation, Permian Basin, West Texas and southeastern New Mexico,” Report of Investigations 201, Bureau of Economic Geology, Austin, Texas, 1991, p. 63.

15 Comer, J. B., “Organic geochemistry and paleogeography of Upper Devonian formations in Oklahoma and northwestern Arkansas,” in Johnson, K. S. and B. J. Cardott, eds., Source Rocks in the Southern Midcontinent, 1990 Symposium, Oklahoma Geological Survey, Circular 93, Norman, Okla., 1992, pp. 70-93.

16 Curiale, J. A., “Petroleum occurrences and source rock potential of the Ouachita Mountains, southeastern Oklahoma,” Oklahoma Geological Survey, Bulletin 135, Norman, Okla., 1983, p. 65.

17 Wang, H. D. and R. P. Philp, “Geochemical study of potential source rocks and crude oils in the Anadarko Basin, Okla.,” AAPG Bulletin, Vol. 81, No. 2, 1997, pp. 249-275.

18 Landis, C. R., Trabelsi, A. and G. Strathearn, “Hydrocarbon potential of selected Permian Basin shales as classified within the organic facies concept,” in Johnson, K. S. and B. J. Cardott, eds., Source Rocks in the Southern Midcontinent, 1990 Symposium, Oklahoma Geological Survey, Circular 93, Norman, Okla., 1992, pp. 229-247.

19 Sullivan, K. L., “Organic facies variation of the Woodford Shale in western Oklahoma,” Shale Shaker, Vol. 35, No. 4, 1985, pp. 76-89.

20 Cardott, B. J., “Thermal maturation of the Woodford Shale in the Anadarko Basin,” in Johnson, K. S., ed., Anadarko Basin Symposium, 1988, Oklahoma Geological Survey, Circular 90, Norman, Okla., 1989, pp. 32-46.

21 Amsden, T. W. et al., “Devonian of the southern midcontinent area, United States,” in Oswald, D. H., ed., International Symposium on the Devonian System, Alberta Society of Petroleum Geologists, Calgary, Canada, 1967, pp. 913-932.
22 Amsden, T. W., “Hunton Group (Late Ordovician, Silurian and Early Devonian) in the Arkoma Basin of Oklahoma,” Oklahoma Geological Survey, Bulletin 129, Norman, Okla., 1980, p. 136.

23 Amsden, T. W., “Hunton Group (Late Ordovician, Silurian, and Early Devonian) in the Anadarko Basin of Oklahoma,” Oklahoma Geological Survey, Bulletin 121, Norman, Okla., 1975, p. 214.

24 Hass, W. H. and J. W. Huddle, “Late Devonian and Early Mississippian age of the Woodford Shale in Oklahoma, as determined from conodonts,” US Geological Survey Professional Paper 525-D, 1965, pp. D125-D132.

25 Huffman, G. G., “Geology of the flanks of the Ozark uplift,” Oklahoma Geological Survey, Bulletin 77, 1958, p. 281.

26 Cloud, P. E., Barnes, V. E. and W. H. Hass, “Devonian-Mississippian transition in central Texas,” GSA Bulletin, Vol. 68, No. 7, 1957, pp. 807-816.

27 Graves, R. W., “Devonian conodonts from the Caballos Novaculite,” Journal of Paleontology, Vol. 26, No. 4, 1952, pp. 610-612.

28 Laudon, L. R. and A. L. Bowsher, “Mississippian formations of southwestern New Mexico,” GSA Bulletin, Vol. 60, No. 1, 1949, pp. 1-88.

29 King, P. B., King, R. E. and J. B. Knight, “Geology of the Hueco Mountains, El Paso and Hudspeth Counties, Texas,” Oil and Gas Investigations Preliminary Map 36, US Geological Survey, 1945.

30 Stevenson, F. V., “Devonian of New Mexico,” Journal of Geology, Vol. 53, No. 4, 1945, pp. 217-245.

31 Amsden, T. W. and G. Klapper, “Misener Sandstone (Middle-Upper Devonian), north-central Oklahoma,” AAPG Bulletin, Vol. 56, No. 12, 1972, pp. 2323-2334.

32 Galley, J. E., “Oil and geology in the Permian Basin of Texas and New Mexico,” in Weeks, L. G., ed., Habitat of Oil, American Association of Petroleum Geologists, Tulsa, Okla., 1958, pp. 395-446.

33 Ham, W. E., “Regional geology of the Arbuckle Mountains, Oklahoma,” in Ham, W. E., ed., Geology of the Arbuckle Mountains, Oklahoma Geological Survey, 1969, pp. 5-21.

34 Ham, W. E. and J. L. Wilson, “Paleozoic epeirogeny and orogeny in the central United States,” American Journal of Science, Vol. 265, No. 5, 1967, pp. 332-407.

35 Freeman, T. and D. Schumacher, “Qualitative pre-Sylamore (Devonian-Mississippian) physiography delineated by onlapping conodont zones, northern Arkansas,” GSA Bulletin, Vol. 80, No.11, 1969, pp. 2327-2334.

36 Ellison, S. P., “Subsurface Woodford black shale, west Texas and southeast New Mexico,” Report of Investigations 7, Bureau of Economic Geology, Austin, Texas, 1950, p. 20.

37 Hester, T. C., Schmoker, J. W. and H. L. Sahl, “Log-derived regional source-rock characteristics of the Woodford Shale, Anadarko Basin, Oklahoma,” US Geological Survey Bulletin 1866-D, 1990, pp. D1-D38.

38 Harlton, B. H., “The Harrisburg trough, Stevens and Carter Counties, Oklahoma,” in Hicks, I. C. et al., eds., Petroleum Geology of Southern Oklahoma, v. 1, American Association of Petroleum Geologists, Tulsa, Okla., 1956, pp. 135-143.

39 Heckel, P. H. and B. J. Witzke, “Devonian world palaeogeography determined from distribution of carbonates and related lithic palaeoclimatic indicators,” in House, M. R., Scrutton, C. T. and M. G. Bassett, eds., Special Papers in Palaeontology No. 23, The Devonian System: A Palaeontological Association International Symposium, Palaeontological Association, London, 1979, pp. 99-123.

40 Carr, J. L., “The thermal maturity of the Chattanooga Formation along a transect from the Ozark Uplift to the Arkoma Basin,” Shale Shaker, Vol. 38, No. 3, 1987, pp. 32-40.

41 Cardott, B. J. and M. W. Lambert, “Thermal maturation by vitrinite reflectance of Woodford Shale, Anadarko Basin, Oklahoma,” AAPG Bulletin, Vol. 69, No. 11, 1985, pp. 1982-1998.

42 Houseknecht, D. W., Hathon, L. A. and T. A. McGilvery, “Thermal maturity of Paleozoic strata in the Arkoma Basin,” in Johnson, K. S. and B. J. Cardott, eds., Source Rocks in the Southern Midcontinent, 1990 Symposium, Oklahoma Geological Survey Circular 93, Norman, Okla., 1992, pp. 122-132.

43 Houseknecht, D. W. and S. M. Matthews, “Thermal maturity of Carboniferous strata, Ouachita Mountains,” AAPG Bulletin, Vol. 69, No. 3, 1985, pp. 335-345.
John B. Comer is a Senior Scientist at the Indiana Geological Survey with an academic appointment at Indiana University. He earned a BA from Ohio Wesleyan University, an MS from The University of Wisconsin-Milwaukee and a PhD from The University of Texas at Austin, all in geology. During his 36-year career, he worked as a research scientist in the geochemistry group at the Amoco Production Company Research Center in Tulsa, an assistant and associate professor at Tulsa University and the Geochemistry Section Head at the Indiana Geological Survey. Dr. Comer has conducted research in organic, inorganic and environmental geochemistry, clastic sedimentation, sedimentary petrology and the deposition and diagenesis of organic-rich rocks. He is an active member of AAPG, SEPM and GSA and has authored more than 120 scholarly papers and technical reports in geology and geochemistry.

Wednesday, August 20, 2008

"Unconventional" Gas Plays

More information from the online "World Oil Magazine" on the "Shale Gas" plays in the United States. (source)


Unconventional plays grow in number after Barnett Shale blazed the way
The Haynesville and Marcellus are becoming exciting new gas plays, while activity in the Woodford and Fayetteville continues.
Katrina Boughal , Technical Editor
Unconventional gas plays in the US have been booming since technological advances increased production in the now-famous Barnett Shale. Horizontal drilling and fracture stimulation in the shale source rock, as opposed to the sandstone/limestone/dolomite reservoir rock, have proved to be successful not only in gas plays like the Barnett, Fayetteville and Woodford, but also in the Bakken-a primarily oil-rich formation.

Resources that were previously thought to be unrecoverable are now being reassessed and, in some cases, rediscovered. Many shale plays have been producing a small amount of gas for years (the Indiana and Kentucky New Albany Shale since the late 1880s), but with the Barnett example, they are becoming more successful. Hot plays in the industry include the Louisiana/Texas Haynesville and Bossier Shales, and the Marcellus of Pennsylvania/Appalachia. The Williston Basin Bakken Formation has also gained popularity after a recent reassessment by the USGS.

The fairly recent Haynesville gas play, having garnered attention over the past few months, is an Upper Jurassic formation overlain by the Cotton Valley Group, and lies over the Smackover Formation. The Haynesville is an ultra-low permeability shale, and is focused in northwest Louisiana and East Texas, particularly in Caddo, Bossier and DeSoto Parishes, but also to a lesser extent in Red River and Sabine Parishes, and Harrison and Panola Counties, Fig. 1. The Haynesville Shale underlies the Bossier Shale (part of the Cotton Valley Group), and they are sometimes referred to as the same unit or related units. 2 Deeper than most shale gas plays, the Haynesville is located at depths ranging between 11,000 and 13,000 ft. 3

Fig. 1 . Map of the Haynesville Shale play (shaded). 1
Chesapeake is a large participant in the Haynesville play, holding about 550,000 acres as of late June 2008, with plans to acquire more acreage. Chesapeake entered a joint venture with Plains Exploration and Production, and the companies plan to drill about 600 wells in the Haynesville in the next three years. Chesapeake is estimating a mid-point estimated ultimate reserve of 6.5 Bcf, and their initial horizontal production rates are encouraging for the play.
“The initial production rates on the eight horizontal wells we have completed have ranged from 5 to 15 MMcfd on restricted chokes at flowing casing pressures of up to 6,500 psi,” said Chesapeake CEO Aubrey K. McClendon. 4

Petrohawk is also an active participant with about 275,000 acres, and completed their first horizontal well in the Haynesville in late June 2008. The Elm Grove Plantation #63, drilled in Bossier Parish, encountered about 212 ft of Haynesville Shale, and produced at a rate of 16.8 MMcfd. Completion of Elm Grove Plantation #63 included 11 stages of fracture stimulation. Petrohawk is drilling three horizontal wells, and expects to be operating six rigs in the Haynesville by mid-September 2008. 5

Companies are scrambling to lease plots in the Haynesville, with Forest Oil announcing in late June 2008 a net holding of 90,000 acres in the area. 6 GMX Resources added 7,300 net acres in early July, bringing its total acreage to 27,500. 7 EnCana has about 325,000 acres in the Haynesville, and completed a horizontal well in February with an initial production rate of 8 MMcfd. 8

A few years ago the Fayetteville Shale experienced an upswing in interest somewhat akin to what the Haynesville is experiencing now. The Fayetteville of Arkansas is a Mississippian formation on the eastern end of the Arkoma Basin, with thicknesses varying between 50 and 300 ft and drilled at depths ranging from 2,000 to 6,000 ft. Thickness in the Fayetteville differs from east to west, at about 50 to 75 ft thick in western Arkansas to about 300 ft at the eastern edge of the Arkoma Basin. The formation is productive from its middle to base because the lower section is rich in organic material, with chert and siliceous interbedding. 9 The unit is thermally mature, and is differentiated from surrounding units by high radioactivity and resistivity signatures. 10

The Fayetteville is found in multiple eastern and central Arkansas counties, including Cleburne, Conway, Faulkner, Franklin, Jackson, St. Francis, Pope, Prairie, Van Buren, White and Woodruff Counties. The Fayetteville is about the same age and is seen as a geologic equivalent to the Barnett Shale near Fort Worth.

The Fayetteville followed the Barnett in production technology. As with other shale gas plays, the Fayetteville was previously known to be a gas-bearing formation, but only produced when horizontal drilling and fracture stimulation were introduced. 8 Some 460 of the over 500 producing wells in the Fayetteville are horizontal, and total production from the shale has reached, and likely exceeded, 52 Bcf. 11

Rig counts in the Arkansas Arkoma Basin have increased dramatically in the past two years. In August 2006, the rig count hovered at slightly over 20. In early July 2008, the count was at 59 operating rigs, with most located in Van Buren, White and Conway Counties. Southwestern Energy was operating 18 of the 59 rigs (about 31%) in the Arkansas Arkoma Basin during the first week of July 2008. 12 Southwestern, one of the most dominant players in the region, owns about 851,100 acres in the Fayetteville area, and has completed 557 wells in the play as of March 2008, of which about 88% were horizontal. During the company’s first quarter 2008, estimated 2007 production from the Fayetteville was 53.5 Bcf. 13

Chesapeake holds the largest land area in the play with 1.1 million acres, and in March 2008, had a net production of 130 MMcfd from the Fayetteville. Chesapeake had 12 rigs operating in March 2008, and plans to escalate drilling activity to 25 rigs in the play by early 2009. 14

In 2002, the USGS released an assessment of the undiscovered oil and gas in the Appalachian Basin Province. The Marcellus Shale was characterized as an individual assessment unit in the Appalachian Basin region that contained gas resources of about 1.9 Tcf. 15

The Marcellus had been fairly quiet until recently, when in late 2007 Range Resources announced horizontal well test rates from 1.4 MMcfd to 4.7 MMcfd. Shortly after, in January 2008, Pennsylvania State University and the University of New York at Fredonia released a report estimating recoverable reserves at 50 Tcf. Since then, The New York Times and USA Today have run stories on the Marcellus and the formation’s producing potential.

The Marcellus Shale is part of a large suite of rocks known as the Devonian shales, and stretches NE-SW about 600 mi across several Appalachian states, including New York, Pennsylvania and West Virginia, Fig. 2. 16 The naturally fractured, dry gas-producing Marcellus covers an area of about 54,000 square mi, 17 and ranges in thickness from 50 to 200 ft. Like the Fayetteville, the Marcellus thins from east to west, with 200-ft sections in northeastern Pennsylvania and 50-ft sections in northern West Virginia, Ohio, Pennsylvania and western New York. The formation depth ranges from 5,000 to 8,000 ft below sea level. 18

Fig. 2 . Map of the Marcellus and Devonian Shales. 16
The organic richness of the Marcellus, however, decreases generally from north in New York to south in West Virginia. The thermal maturity of the shale is an estimated 1.5 to 3% vitrinite reflectance (Ro). 18

As of April 2008, Range Resources held about 1.15 million acres of the Marcellus play, and had drilled 10 successful horizontal wells with initial production rates ranging from 2.6 to 5.8 MMcfd. 19 Other players in the Marcellus include Atlas Energy Resources and Chesapeake (largest lease holder with 1.2 million acres). Atlas, whose drilling plan is focused primarily in southwestern Pennsylvania, announced in February that it had 21 producing vertical wells, with 6 more due to be completed and producing shortly. 20

Marcellus players face the problem of minimal public information on the area, and have to resort to academic papers and regional geologic information due to the lack of log data. Oilfield services and equipment in the area are also somewhat scarce, with only four or six Appalachian rigs capable of drilling horizontal wells. 16

Activity in the Woodford Shale began in 2003-2004 as a vertical play, but quickly transitioned to horizontal wells after the Barnett became horizontally driven. 21
The Woodford Shale is located in Oklahoma on the western end of the Arkoma Basin, and ranges in age from Middle Devonian to Early Mississippian. The stratigraphic equivalent to the Bakken and Antrim Shales, the Woodford shows a wide range of thermal maturities from 0.7 to 4.89% Ro?. Although known to be a gas-producing formation, the Woodford may have the potential to produce oil as well, 22 and the silica-rich shale has provided a good environment for fracturing due to its brittle nature. 21

The Woodford has seen many players in the area including Newfield Exploration, Devon, Chesapeake and XTO Energy. Newfield has about 165,000 net acres in the Woodford, is looking to drill about 100 horizontal wells this year and had a gross production of 165 MMcfd as of February 2008.23 Drilling depths for Newfield have ranged from 6,000 to 13,000 ft, with lateral lengths to about 5,000 ft. 21 For a more in-depth discussion on the characteristics and production potential of the Woodford Shale, please see page 83.

No unconventional play article would be complete without a mention of the Barnett. The very well-known Barnett Shale is the gas play that introduced horizontal drilling and fracture stimulation techniques to the unconventional shale gas field, allowing other plays’ production potential to be realized. Indeed, every time a new shale gas play is discovered, it is compared to the Barnett, or is called the “next Barnett” or a “baby Barnett.”

The Mississippian Barnett in the Fort Worth Basin of Texas is about 6,500 to 8,000 ft deep, and thickens toward the northeast-from about 30 to 50 ft thick in the south to about 1,000 ft thick in the northeast. 24

At the end of 2007, the total number of Barnett producing wells over time was at about 8,960, with cumulative production of 3.69 Tcf and 11.6 million bbl of oil. The rate of production from 8,435 active Barnett wells in December 2007 was 3.524 Bcfd plus 7,477 bpd. From 2003 to 2007, horizontal wells have become the dominant well orientation. In 2003, about 21% of wells completed in the Barnett were horizontal; in 2007, about 94% were horizontal. 25

The Barnett continues as the giant that it has become in the past five years. The players list in the Barnett is exhaustive, with Devon, Chesapeake, XTO, Encana, EOG and others. Devon has drilled more than 1,300 wells in the Barnett since 2002, and produces nearly 600 MMcfd. 26

The April 2008 USGS assessment of the Bakken Formation in the Williston Basin has caused a flurry of activity in the area, particularly because of the undiscovered, technically recoverable oil resource estimation-between 3.0 and 4.3 billion bbl. The large increase in the Bakken’s recoverable resources (formerly estimated by the USGS at 151 million bbl in 1995) is due to the same factor that has lead to expanding shale gas plays: advances in horizontal drilling and hydraulic fracturing.

The Upper Devonian-Early Mississippian Bakken is a continuous, 200,000-sq mi formation composed of sandstone, siltstone and dolomite bounded by two shale layers. Average porosity in the Bakken is between 8% and 12%, and permeability ranges from 0.05 mD to 0.5 mD. The Bakken is about 2-mi deep, and has a net thickness of about 6 ft to 15 ft. Key players in the region include EOG Resources, Whiting Petroleum, Brigham Exploration, Hess, Newfield Exploration, XTO and Marathon. 27 For a more comprehensive view on the Bakken assessment, please see World Oil June 2008, page 83.

There are a multitude of unconventional shale plays being assessed, and the following are a few from various parts of the US.
Utica. Located in New York, northern Pennsylvania, Quebec and Ontario, the Utica Shale is an Upper Ordovician reservoir with typical low permeability, high organic content and varying thickness-the formation ranges from 150 to 1,000 ft across New York. The Utica’s close proximity to the Marcellus makes it interesting, but recently drilled Utica wells have “not responded well to the normal shale fracturing practices.” 28 Forest Oil has acquired 269,000 net acres of the Quebec Utica, and in April 2008, reported 1 MMcfd production rates from two 4,800-ft vertical wells. 29


This Devonian shale formation extends across a large part of the US, although the gas play is centered in southern Kentucky, eastern Tennessee and northern Alabama, Fig. 3. Sources cite the Chattanooga as being an equivalent to both the Marcellus and the Woodford Shales, all of which are Devonian formations. 30,31

Fig. 3 . Map of the Chattanooga Shale play (shaded). 30
The USGS reported in 2007 on the petroleum system of the Black Warrior Basin in Alabama and Mississippi that encompasses part of the Chattanooga Shale. The USGS report focused on the carbonates and sandstones, and discussed the Floyd and Chattanooga Shales as source rocks alone-no unconventional shale gas assessment was released. The Chattanooga is a Devonian-age shale that is separated from the Mississippian-age Floyd Shale by a thin layer of chert and limestone, and they are often referred in relation to each other. The Alabama Chattanooga play lies in the eastern Black Warrior Basin, and is a thin unit with a Total Organic Carbon (TOC) weight percent range of 2.4-12.7. 32 The Tennessee Chattanooga play is relatively shallow compared to other gas plays with depths ranging from 1,500 to 2,000 ft. 33

In 2007, CNX Gas Corp. drilled a horizontal well in Tennessee with an initial production rate of 3.9 MMcfd. 34 Atlas Energy Resources announced in June 2008 the successful drilling of four horizontal wells in the formation. 35

Floyd. In close contact with the Chattanooga Shale, the Floyd play is situated in the Black Warrior Basin of Mississippi and Alabama. The formation is primarily shale, but also contains clay, sandstone and limestone beds, with chert and large siderite modules. 32 Found at depths from about 4,000 ft to 9,000 ft below surface level, 36 the Floyd thickens toward the northeast, with a maximum thickness of about 600 ft, and has a TOC percent weight of about 1.8. The Floyd is believed to be the source rock for the conventional reservoirs in the area. 32 Carrizo Oil and Gas drilled a horizontal well in the Floyd in July 2007,37 and Murphy Oil drilled several wells in 2006. 38 With minimal news concerning the Floyd in 2008, play activity seems to have slowed down.

New Albany.

Found in the Illinois Basin, the New Albany Shale is a mostly Devonian-aged formation (the top few feet of the unit are Mississippian) that spans Kentucky, Indiana and, to a smaller extent, Illinois. The New Albany can be correlated with the Antrim Shale of Michigan and Indiana, and the Chattanooga Shale of Tennessee. 39 The New Albany gas play has been focused in Kentucky and southeastern Indiana. Formation thickness varies-the shale is about 100 to 140 ft thick in southeastern Indiana and almost 340 ft thick farther southwest in the Illinois Basin. 40 The USGS released a report in 2007 on the Illinois Basin that assessed the undiscovered, technically recoverable gas resources of the New Albany Shale at 3.79 Tcf. 41 Aurora Oil and Gas reported an average production of 424 Mcfd from their New Albany holdings in the first quarter 2008. 42 CNX Gas drilled six wells in the New Albany in 2007 to determine reservoir information and future drilling locations. 34

As the Barnett proves to be continually successful, shale plays, oil and gas, are looking to be important in the future.
There are already whispers of the Haynesville being the next Barnett, and although those rumors have been heard before about other plays, expect to hear about the Haynesville, and the Bakken and Marcellus, in the months to come.

1 “Core leasing area: Haynesville Shale map,” Haynesville Shale Map, http://haynesvilleshalemap.com/, accessed July 7, 2008.

2 Welborn, V., “What is the Haynesville Shale?” Shreveport Times , July 7, 2008.

3 “Shale gas fever drives land drilling in US,” Platts Oilgram News , July 4, 2008, pg. 6.

4 “Chesapeake and PXP announce Haynesville Shale joint venture,” Yahoo Financial News, July 1, 2008, http://bix.yahoo.com/bw/080701/20080701006524.html, accessed July 8, 2007.

5 “Petrohawk Energy Corporation reports Haynesville Shale result and leasehold update,” Fox Business, June 30, 2008, http://www.foxbusiness.com/story/markets/industries/energy/petrohawk-energy-corporation-reports-haynesville-shale-result-leasehold-update/, accessed July 8, 2008.

6 “Forest Oil increases holdings in E. Texas, N. La,” Forbes.com, June 30, 2008, http://www.forbes.com/feeds/ap/2008/06/30/ap5169765.html, accessed July 10, 2008.

7 “GMX Resources Inc. announces Haynesville/Bossier Shale drilling to begin 3Q08,” Prime Newswire, July 7, 2008, http://www.primenewswire.com/newsroom/news.html?d=145868, accessed July 10, 2008.

8 Fuquay, J., “Chesapeake, EnCana, boost activity in Louisiana gas shale,” Star-Telegram , June 16, 2008.

9 Brown, D., “Barnett may have Arkansas cousin,” AAPG Explorer , Feb. 2006.

10 “The Fayetteville Shale play: A geologic overview,” Arkansas Business.com, Aug. 27, 2007, http://www.arkansasbusiness.com/article.aspx?aID=99154, accessed July 8, 2008.

11 Shelby, P., “Fayetteville Shale play of North-Central Arkansas: A project update,” presented at the AAPG Annual Convention, San Antonio, Texas, April 20-23, 2008.

12 “Baker Hughes US rig count- Summary report,” Baker Hughes- Investor relations- Rig counts,, accessed July 11, 2008.

13 “Fayetteville Shale play,” Southwestern Energy Company, http://www.swn.com/operations/fayetteville.shale.asp, accessed July 8, 2008.

14 “Chesapeake reports Haynesville Shale discovery in Louisiana and announces CapEx increase,” OilVoice, March 24, 2008, http://www.oilvoice.com/n/Chesapeake_Reports_Haynesville_Shale_Discovery_in_Louisiana_and_Announces_CapEx_Increase/92f01da5.aspx, accessed July 11, 2008.

15 US Department of the Interior, US Geological Society, “Assessment of undiscovered oil and gas resources of the Appalachian Basin Province, 2002,” USGS Fact Sheet FS-009-03, February 2003.

16 Durham, L. S., “Another shale making seismic waves,” AAPG Explorer, March 2008.

17 Mayhood, K., “Low down, rich and stingy,” The Columbus Dispatch , March 11, 2008.

18 Milici, R. C. and C. S. Swezey, “Assessment of Appalachian Basin oil and gas resources: Devonian Shale- Middle and Upper Paleozoic total petroleum system,” Open file report series 2006-1237, USGS Reston, Virginia, 2006, pp.38-39.

19 “Range announces record first quarter results,” OilVoice, April 24, 2008, http://www.oilvoice.com/n/Range_Announces_Record_First_Quarter_Results/4c59a7ac.aspx, accessed July 11, 2008.

20 “Atlas Energy Resources, LLC increases estimated reserve potential from Marcellus Shale to between 4 and 6 Tcf,” Reuters, Feb. 21, 2008, http://www.reuters.com/article/pressRelease/idUS127932+21-Feb-2008+MW20080221, accessed July 14, 2008.

21 Brown, D., “Big potential boost the Woodford,” AAPG Explorer , July 2008.

22 Comer, J. B., “Reservoir characteristics and production potential of the Woodford Shale,” World Oil , August 2008, pp. 83.

23 “Newfield Exploration announces 2008 capital program,” Reuters, Feb. 4, 2008, http://www.reuters.com/article/pressRelease/idUS139442+04-Feb-2008+PRN20080204, accessed July 11, 2008.

24 Hayden, J. and D. Pursell, “The Barnett Shale: Visitors guide to the hottest gas play in the US,” Tudor Pickering, Oct. 2005, http://www.tudorpickering.com/pdfs/TheBarnettShaleReport.pdf, accessed July 10, 2008.

25 “Number of vertical and horizontal producer wells in the Barnett Shale as of Jan. 1, 2008,” Powell Barnett Shale Newsletter , March 27, 2008, http://www.barnetshalenews.com/documents/VHchart%201-1-08.pdf, accessed July 10, 2008.

26 “Operations- Barnett Shale,” Devon Energy, http://www.devonenergy.com/Operation/FeatuerStories/Pages/barnett_shale.aspx, accessed July 10, 2008.

27 Cohen, D. M., “USGS names Bakken play the largest oil accumulation in the Lower 48,” World Oil , June 2008, pp. 83-84.

28 Paktinat, J., Pinkhouse, J., Fontaine, J., Lash, G. and G. Penny, “Investigation of methods to improve Utica Shale hydraulic fracturing in the Appalachian Basin,” presented at the AAPG Annual Convention, San Antonio, Texas, April 20-23, 2008.

29 “Forest Oil announces significant gas discovery in Utica Shale…” Reuters, April 1, 2008, http://www.reuters.com/article/pressRelease/idUS134787+01-Apr-2008+BW20080401, accessed July 11, 2008.

30 “Chattanooga Shale natural gas field,” Oil Shale Gas, http://www.oilshalegas.com/chattanoogashale.com, accessed July 9, 2008.

31 “AMI Project,” Irvine Energy PLC, http://www.irvineenergy.com/projects/index.htm, accessed July 9, 2008.

32 USGS Black Warrior Basin Province assessment team, “Geologic assessment of undiscovered oil and gas resources of the Black Warrior Basin Province, Alabama and Mississippi,” Hatch, J. R. and M. J. Pawlewicz, compilers, USGS Digital Data Series DDS-69-I, 2007, 76 p.

33 “Domestic Energy announces Appalachian Shale plan,” Reuters, April 28, 2008, http://www.reuters.com/article/preeRelease/idUS139048+28-Apr-2008+MW20080428, accessed July 9, 2008.

34 “CNX Gas reports fourth quarter and full year 2007 results,” Reuters, Jan. 29, 2008, http://www.reuters.com/article/pressRelease/idUS140410+29-Jan-2008+PRN20080129, accessed July 11, 2008.

35 “Atlas Energy announces four successful horizontal wells in Tennessee’s Chattanooga Shale, and a net acreage position of 105,000 acres in the play,” OilVoice, June 21, 2008, http://www.oilvoice.com/n/Atlas_Energy_Announces_Four_Successful_Horizontal_Wells_in_Tennessees_Chattanooga_Shale/9fc6bbe0.aspx, accessed July 9, 2008.

36 “Floyd Shale potential of the Black Warrior Basin: Executive summary,” Mississippi Geological Society eBulletin , Vol. 55, No. 7, March 2007.

37 “Carrizo Oil & Gas, Inc. announces record production and third quarter 2007 financial results,” Carrizo Oil & Gas, Nov. 8, 2007, http://carrizo.mediaroom.com/index.php?s=43&iten=154, accessed July 10, 2008.

38 Edmonds, C., “New shales may be ready to deliver,” The Street, Feb. 22, 2007, http://www.thestreet.com/story/10340267/1/new-shales-may-be-ready-to-deliver.html, accessed July 10, 2008.

39 “New Albany Shale,” Indiana Geological Survey, http://igs.indiana.edu/Geology/structure/compendium/html/comp82hw.cfm, accessed July 9, 2008.

40 Comer, J. B., Hasenmueller, N. R., Mastalerz, M. D., Rupp, J. A., Shaffer, N. R. and C. W. Zuppann, “The New Albany Shale gas play in southern Indiana,” presented at AAPG Eastern Section Meeting, Buffalo, N.Y., Oct. 8-11, 2006.

41 US Department of the Interior, US Geological Survey, “Assessment of undiscovered oil and gas resources of the Illinois Basin, 2007,” USGS Fact Sheet 2007-3058, August 2007.

42 “Aurora Oil & Gas Corp. announces first quarter 2008 results,” Reuters, May 9, 2008, http://www.reuters.com/article/pressRelease/idUS248894+09-May-2008+PRN20080509, accessed July 11, 2008.

Thursday, August 14, 2008

Geology And Resources Of Some Oil Shales

In my first job as a geologist, I worked with John Dyni doing field and laboratory work studying the oil shale in Colorado and Utah for the USGS. I'm not sure if anyone knows when, and to what degree these oil shale deposits will be economically feasible to develop. There are many questions that must be addressed, such as environmental damage, water usage, etc. The following article is a good summary about oil shales of the world.

Geology and Resources of Some World Oil-Shale Deposits
Reprint of: USGS Scientific Investigations Report 2005-5294
By John R. Dyni
Oil shale is commonly defined as a fine-grained sedimentary rock containing organic matter that yields substantial amounts of oil and combustible gas upon destructive distillation. Most of the organic matter is insoluble in ordinary organic solvents; therefore, it must be decomposed by heating to release such materials. Underlying most definitions of oil shale is its potential for the economic recovery of energy, including shale oil and combustible gas, as well as a number of byproducts. A deposit of oil shale having economic potential is generally one that is at or near enough to the surface to be developed by open-pit or conventional underground mining or by in-situ methods.

Oil shales range widely in organic content and oil yield. Commercial grades of oil shale, as determined by their yield of shale oil, ranges from about 100 to 200 liters per metric ton (l/t) of rock. The U.S. Geological Survey has used a lower limit of about 40 l/t for classification of Federal oil-shale lands. Others have suggested a limit as low as 25 l/t.Deposits of oil shale are in many parts of the world. These deposits, which range from Cambrian to Tertiary age, may occur as minor accumulations of little or no economic value or giant deposits that occupy thousands of square kilometers and reach thicknesses of 700 m or more.

Oil shales were deposited in a variety of depositional environments, including fresh-water to highly saline lakes, epicontinental marine basins and subtidal shelves, and in limnic and coastal swamps, commonly in association with deposits of coal.In terms of mineral and elemental content, oil shale differs from coal in several distinct ways. Oil shales typically contain much larger amounts of inert mineral matter (60–90 percent) than coals, which have been defined as containing less than 40 percent mineral matter.

The organic matter of oil shale, which is the source of liquid and gaseous hydrocarbons, typically has a higher hydrogen and lower oxygen content than that of lignite and bituminous coal.In general, the precursors of the organic matter in oil shale and coal also differ. Much of the organic matter in oil shale is of algal origin, but may also include remains of vascular land plants that more commonly compose much of the organic matter in coal. The origin of some of the organic matter in oil shale is obscure because of the lack of recognizable biologic structures that would help identify the precursor organisms. Such materials may be of bacterial origin or the product of bacterial degradation of algae or other organic matter.

The mineral component of some oil shales is composed of carbonates including calcite, dolomite, and siderite, with lesser amounts of aluminosilicates. For other oil shales, the reverse is true—silicates including quartz, feldspar, and clay minerals are dominant and carbonates are a minor component. Many oil-shale deposits contain small, but ubiquitous, amounts of sulfides including pyrite and marcasite, indicating that the sediments probably accumulated in dysaerobic to anoxic waters that prevented the destruction of the organic matter by burrowing organisms and oxidation.

Although shale oil in today’s (2004) world market is not competitive with petroleum, natural gas, or coal, it is used in several countries that possess easily exploitable deposits of oil shale but lack other fossil fuel resources. Some oil-shale deposits contain minerals and metals that add byproduct value such as alum [KAl(SO4)2•12H2O], nahcolite (NaHCO3), dawsonite [NaAl(OH)2CO3], sulfur, ammonium sulfate, vanadium, zinc, copper, and uranium.The gross heating value of oil shales on a dry-weight basis ranges from about 500 to 4,000 kilocalories per kilogram (kcal/kg) of rock. The high-grade kukersite oil shale of Estonia, which fuels several electric power plants, has a heating value of about 2,000 to 2,200 kcal/kg. By comparison, the heating value of lignitic coal ranges from 3,500 to 4,600 kcal/kg on a dry, mineral-free basis (American Society for Testing Materials, 1966).

Tectonic events and volcanism have altered some deposits. Structural deformation may impair the mining of an oil-shale deposit, whereas igneous intrusions may have thermally degraded the organic matter. Thermal alteration of this type may be restricted to a small part of the deposit, or it may be widespread making most of the deposit unfit for recovery of shale oil.

The purpose of this report is to (1) discuss the geology and summarize the resources of selected deposits of oil shale in varied geologic settings from different parts of the world and (2) present new information on selected deposits developed since 1990 (Russell, 1990).

Recoverable Resources
The commercial development of an oil-shale deposit depends upon many factors. The geologic setting and the physical and chemical characteristics of the resource are of primary importance. Roads, railroads, power lines, water, and available labor are among the factors to be considered in determining the viability of an oil-shale operation. Oil-shale lands that could be mined may be preempted by present land usage such as population centers, parks, and wildlife refuges.

Development of new in-situ mining and processing technologies may allow an oil-shale operation in previously restricted areas without causing damage to the surface or posing problems of air and water pollution.The availability and price of petroleum ultimately effect the viability of a large-scale oil-shale industry. Today, few, if any deposits can be economically mined and processed for shale oil in competition with petroleum. Nevertheless, some countries with oil-shale resources, but lack petroleum reserves, find it expedient to operate an oil-shale industry. As supplies of petroleum diminish in future years and costs for petroleum increase, greater use of oil shale for the production of electric power, transportation fuels, petrochemicals, and other industrial products seems likely.

Determining Grade of Oil Shale
The grade of oil shale has been determined by many different methods with the results expressed in a variety of units. The heating value of the oil shale may be determined using a calorimeter. Values obtained by this method are reported in English or metric units, such as British thermal units (Btu) per pound of oil shale, calories per gram (cal/gm) of rock, kilocalories per kilogram (kcal/kg) of rock, megajoules per kilogram (MJ/kg) of rock, and other units. The heating value is useful for determining the quality of an oil shale that is burned directly in a power plant to produce electricity. Although the heating value of a given oil shale is a useful and fundamental property of the rock, it does not provide information on the amounts of shale oil or combustible gas that would be yielded by retorting (destructive distillation).

The grade of oil shale can be determined by measuring the yield of oil of a shale sample in a laboratory retort. This is perhaps the most common type of analysis that is currently used to evaluate an oil-shale resource. The method commonly used in the United States is called the “modified Fischer assay,” first developed in Germany, then adapted by the U.S. Bureau of Mines for analyzing oil shale of the Green River Formation in the western United States (Stanfield and Frost, 1949). The technique was subsequently standardized as the American Society for Testing and Materials Method D-3904-80 (1984). Some laboratories have further modified the Fischer assay method to better evaluate different types of oil shale and different methods of oil-shale processing.The standardized Fischer assay method consists of heating a 100-gram sample crushed to –8 mesh (2.38-mm mesh) screen in a small aluminum retort to 500ºC at a rate of 12ºC per minute and held at that temperature for 40 minutes. The distilled vapors of oil, gas, and water are passed through a condenser cooled with ice water into a graduated centrifuge tube. The oil and water are then separated by centrifuging. The quantities reported are the weight percentages of shale oil (and its specific gravity), water, shale residue, and “gas plus loss” by difference.

The Fischer assay method does not determine the total available energy in an oil shale. When oil shale is retorted, the organic matter decomposes into oil, gas, and a residuum of carbon char remaining in the retorted shale. The amounts of individual gases—chiefly hydrocarbons, hydrogen, and carbon dioxide—are not normally determined but are reported collectively as “gas plus loss,” which is the difference of 100 weight percent minus the sum of the weights of oil, water, and spent shale.

Some oil shales may have a greater energy potential than that reported by the Fischer assay method depending on the components of the “gas plus loss.”The Fischer assay method also does not necessarily indicate the maximum amount of oil that can be produced by a given oil shale. Other retorting methods, such as the Tosco II process, are known to yield in excess of 100 percent of the yield reported by Fischer assay. In fact, special methods of retorting, such as the Hytort process, can increase oil yields of some oil shales by as much as three to four times the yield obtained by the Fischer assay method (Schora and others, 1983; Dyni and others, 1990).

At best, the Fischer assay method only approximates the energy potential of an oil-shale deposit.Newer techniques for evaluating oil-shale resources include the Rock-Eval and the “material-balance” Fischer assay methods. Both give more complete information about the grade of oil shale, but are not widely used. The modified Fischer assay, or close variations thereof, is still the major source of information for most deposits.It would be useful to develop a simple and reliable assay method for determining the energy potential of an oil shale that would include the total heat energy and the amounts of oil, water, combustible gases including hydrogen, and char in sample residue.

Origin of Organic Matter
Organic matter in oil shale includes the remains of algae, spores, pollen, plant cuticle and corky fragments of herbaceous and woody plants, and other cellular remains of lacustrine, marine, and land plants. These materials are composed chiefly of carbon, hydrogen, oxygen, nitrogen, and sulfur. Some organic matter retains enough biological structures so that specific types can be identified as to genus and even species. In some oil shales, the organic matter is unstructured and is best described as amorphous (bituminite). The origin of this amorphous material is not well known, but it is likely a mixture of degraded algal or bacterial remains. Small amounts of plant resins and waxes also contribute to the organic matter.

Fossil shell and bone fragments composed of phosphatic and carbonate minerals, although of organic origin, are excluded from the definition of organic matter used herein and are considered to be part of the mineral matrix of the oil shale.Most of the organic matter in oil shales is derived from various types of marine and lacustrine algae. It may also include varied admixtures of biologically higher forms of plant debris that depend on the depositional environment and geographic position. Bacterial remains can be volumetrically important in many oil shales, but they are difficult to identify.

Most of the organic matter in oil shale is insoluble in ordinary organic solvents, whereas some is bitumen that is soluble in certain organic solvents. Solid hydrocarbons, including gilsonite, wurtzilite, grahamite, ozokerite, and albertite, are present as veins or pods in some oil shales. These hydrocarbons have somewhat varied chemical and physical characteristics, and several have been mined commercially.

Thermal Maturity of Organic Matter
The thermal maturity of an oil shale refers to the degree to which the organic matter has been altered by geothermal heating. If the oil shale is heated to a high enough temperature, as may be the case if the oil shale were deeply buried, the organic matter may thermally decompose to form oil and gas. Under such circumstances, oil shales can be source rocks for petroleum and natural gas.

The Green River oil shale, for example, is presumed to be the source of the oil in the Red Wash field in northeastern Utah. On the other hand, oil-shale deposits that have economic potential for their shale-oil and gas yields are geothermally immature and have not been subjected to excessive heating. Such deposits are generally close enough to the surface to be mined by open-pit, underground mining, or by in-situ methods.

The degree of thermal maturity of an oil shale can be determined in the laboratory by several methods. One technique is to observe the changes in color of the organic matter in samples collected from varied depths in a borehole. Assuming that the organic matter is subjected to geothermal heating as a function of depth, the colors of certain types of organic matter change from lighter to darker colors. These color differences can be noted by a petrographer and measured using photometric techniques.

Geothermal maturity of organic matter in oil shale is also determined by the reflectance of vitrinite (a common constituent of coal derived from vascular land plants), if present in the rock. Vitrinite reflectance is commonly used by petroleum explorationists to determine the degree of geothermal alteration of petroleum source rocks in a sedimentary basin. A scale of vitrinite reflectances has been developed that indicates when the organic matter in a sedimentary rock has reached temperatures high enough to generate oil and gas. However, this method can pose a problem with respect to oil shale, because the reflectance of vitrinite may be depressed by the presence of lipid-rich organic matter.Vitrinite may be difficult to recognize in oil shale because it resembles other organic material of algal origin and may not have the same reflectance response as vitrinite, thereby leading to erroneous conclusions. For this reason, it may be necessary to measure vitrinite reflectance from laterally equivalent vitrinite-bearing rocks that lack the algal material.In areas where the rocks have been subjected to complex folding and faulting or have been intruded by igneous rocks, the geothermal maturity of the oil shale should be evaluated for proper determination of the economic potential of the deposit.

Classification of Oil Shale
Oil shale has received many different names over the years, such as cannel coal, boghead coal, alum shale, stellarite, albertite, kerosene shale, bituminite, gas coal, algal coal, wollongite, schistes bitumineux, torbanite, and kukersite. Some of these names are still used for certain types of oil shale. Recently, however, attempts have been made to systematically classify the many different types of oil shale on the basis of the depositional environment of the deposit, the petrographic character of the organic matter, and the precursor organisms from which the organic matter was derived.

A useful classification of oil shales was developed by A.C. Hutton (1987, 1988, 1991), who pioneered the use of blue/ultraviolet fluorescent microscopy in the study of oil-shale deposits of Australia. Adapting petrographic terms from coal terminology, Hutton developed a classification of oil shale based primarily on the origin of the organic matter. His classification has proved to be useful for correlating different kinds of organic matter in oil shale with the chemistry of the hydrocarbons derived from oil shale.

Hutton (1991) visualized oil shale as one of three broad groups of organic-rich sedimentary rocks: (1) humic coal and carbonaceous shale, (2) bitumen-impregnated rock, and (3) oil shale. He then divided oil shale into three groups based upon their environments of deposition — terrestrial, lacustrine, and marine (fig. 1).Terrestrial oil shales include those composed of lipid-rich organic matter such as resin spores, waxy cuticles, and corky tissue of roots, and stems of vascular terrestrial plants commonly found in coal-forming swamps and bogs. Lacustrine oil shales include lipid-rich organic matter derived from algae that lived in freshwater, brackish, or saline lakes. Marine oil shales are composed of lipid-rich organic matter derived from marine algae, acritarchs (unicellular organisms of questionable origin), and marine dinoflagellates.

Several quantitatively important petrographic components of the organic matter in oil shale—telalginite, lamalginite, and bituminite—are adapted from coal petrography. Telalginite is organic matter derived from large colonial or thick-walled unicellular algae, typified by genera such as Botryococcus. Lamalginite includes thin-walled colonial or unicellular algae that occurs as laminae with little or no recognizable biologic structures. Telalginite and lamalginite fluoresce brightly in shades of yellow under blue/ultraviolet light.

Bituminite, on the other hand, is largely amorphous, lacks recognizable biologic structures, and weakly fluoresces under blue light. It commonly occurs as an organic groundmass with fine-grained mineral matter. The material has not been fully characterized with respect to its composition or origin, but it is commonly an important component of marine oil shales. Coaly materials including vitrinite and inertinite are rare to abundant components of oil shale; both are derived from humic matter of land plants and have moderate and high reflectance, respectively, under the microscope.

Within his three-fold grouping of oil shales (terrestrial, lacustrine, and marine), Hutton (1991) recognized six specific oil-shale types: cannel coal, lamosite, marinite, torbanite, tasmanite, and kukersite. The most abundant and largest deposits are marinites and lamosites.Cannel coal is brown to black oil shale composed of resins, spores, waxes, and cutinaceous and corky materials derived from terrestrial vascular plants together with varied amounts of vitrinite and inertinite.

Cannel coals originate in oxygen-deficient ponds or shallow lakes in peat-forming swamps and bogs (Stach and others, 1975, p. 236–237).Lamosite is pale- and grayish-brown and dark gray to black oil shale in which the chief organic constituent is lamalginite derived from lacustrine planktonic algae. Other minor components in lamosite include vitrinite, inertinite, telalginite, and bitumen.

The Green River oil-shale deposits in western United States and a number of the Tertiary lacustrine deposits in eastern Queensland, Australia, are lamosites.Marinite is a gray to dark gray to black oil shale of marine origin in which the chief organic components are lamalginite and bituminite derived chiefly from marine phytoplankton. Marinite may also contain small amounts of bitumen, telalginite, and vitrinite. Marinites are deposited typically in epeiric seas such as on broad shallow marine shelves or inland seas where wave action is restricted and currents are minimal.

The Devonian–Mississippian oil shales of eastern United States are typical marinites. Such deposits are generally widespread covering hundreds to thousands of square kilometers, but they are relatively thin, often less than about 100 m.Torbanite, tasmanite, and kukersite are related to specific kinds of algae from which the organic matter was derived; the names are based on local geographic features. Torbanite, named after Torbane Hill in Scotland, is a black oil shale whose organic matter is composed mainly of telalginite derived largely from lipid-rich Botryococcus and related algal forms found in fresh- to brackish-water lakes. It also contains small amounts of vitrinite and inertinite. The deposits are commonly small, but can be extremely high grade. Tasmanite, named from oil-shale deposits in Tasmania, is a brown to black oil shale. The organic matter consists of telalginite derived chiefly from unicellular tasmanitid algae of marine origin and lesser amounts of vitrinite, lamalginite, and inertinite. Kukersite, which takes its name from Kukruse Manor near the town of Kohtla-Järve, Estonia, is a light brown marine oil shale. Its principal organic component is telalginite derived from the green alga, Gloeocapsomorpha prisca. The Estonian oil-shale deposit in northern Estonia along the southern coast of the Gulf of Finland and its eastern extension into Russia, the Leningrad deposit, are kukersites.

Evaluation of Oil-Shale Resources
Relatively little is known about many of the world’s deposits of oil shale and much exploratory drilling and analytical work need to be done. Early attempts to determine the total size of world oil-shale resources were based on few facts, and estimating the grade and quantity of many of these resources were speculative, at best. The situation today has not greatly improved, although much information has been published in the past decade or so, notably for deposits in Australia, Canada, Estonia, Israel, and the United States.

Evaluation of world oil-shale resources is especially difficult because of the wide variety of analytical units that are reported. The grade of a deposit is variously expressed in U.S. or Imperial gallons of shale oil per short ton (gpt) of rock, liters of shale oil per metric ton (l/t) of rock, barrels, short or metric tons of shale oil, kilocalories per kilogram (kcal/kg) of oil shale, or gigajoules (GJ) per unit weight of oil shale. To bring some uniformity into this assessment, oil-shale resources in this report are given in both metric tons of shale oil and in equivalent U.S. barrels of shale oil, and the grade of oil shale, where known, is expressed in liters of shale oil per metric ton (l/t) of rock. If the size of the resource is expressed only in volumetric units (barrels, liters, cubic meters, and so on), the density of the shale oil must be known or estimated to convert these values to metric tons. Most oil shales produce shale oil that ranges in density from about 0.85 to 0.97 by the modified Fischer assay method. In cases where the density of the shale oil is unknown, a value of 0.910 is assumed for estimating resources.

Byproducts may add considerable value to some oil-shale deposits. Uranium, vanadium, zinc, alumina, phosphate, sodium carbonate minerals, ammonium sulfate, and sulfur are some of the potential byproducts. The spent shale after retorting is used to manufacture cement, notably in Germany and China. The heat energy obtained by the combustion of the organic matter in oil shale can be used in the cement-making process. Other products that can be made from oil shale include specialty carbon fibers, adsorbent carbons, carbon black, bricks, construction and decorative blocks, soil additives, fertilizers, rock wool insulating material, and glass. Most of these uses are still small or in experimental stages, but the economic potential is large.

This appraisal of world oil-shale resources is far from complete. Many deposits are not reviewed because data or publications are unavailable. Resource data for deeply buried deposits, such as a large part of the Devonian oil-shale deposits in eastern United States, are omitted, because they are not likely to be developed in the foreseeable future.

(Wrong! The Devonian "oil shales" , like the Barnett and the Marcellus Shales are producing gas through new technology, search this blog for more information. Peter)

Thus, the total resource numbers reported herein should be regarded as conservative estimates. This review focuses on the larger deposits of oil shale that are being mined or have the best potential for development because of their size and grade.

United States of America Oil Shale
Figure 16. Areas underlain by the Green River Formation in Colorado, Utah, and Wyoming, United States. Figure 18. Paleogeographic map showing shoreline of the Late Devonian sea in eastern United States and major areas of surface-mineable Devonian oil shale. After Conant and Swanson (1961, their fig. 13) and Matthews and others (1980, their fig. 5).

Australia Oil Shale
Figure 2. Deposits of oil shale in Australia. From Crisp and others (1987, their fig. 1). Area of Toolebuc oil shale from Cook and Sherwood (1989, their fig. 2).

Brazil Oil Shale
Figure 3. Deposits of oil shale in Brazil. From Padula (1969, his fig. 1).
Canada Oil Shale
Figure 5. Oil-shale deposits in Canada. Adapted from Macauley (1981).
Estonia and Sweden Oil Shale
Figure 8. Location of the kukersite deposits in northern Estonia and Russia. Adapted from Kattai and Lokk (1998, their fig. 1) and Bauert (1994, his fig. 3).Figure 14. Map showing areas of Alum Shale in Sweden. Adapted from Andersson and others (1985, their fig. 3). Areas in blue are lakes.

Israel and Jordan Oil Shale
Figure 10. Deposits of oil shale in Israel. From Minster (1994, his fig. 1).Figure 11. Oil-shale deposits in Jordan. Adapted from Jaber and others (1997, their fig. 1) and Hamarneh (1998, his figure on p. 4).

Morocco Oil Shale
Figure 12. Oil-shale deposits in Morocco. From Bouchta (1984, his fig. 1).

China, Russia, Syria, Thailand and Turkey
Other countries with oil shales.