EXCO To Open Haynesville Shale Field Office

Tuesday, June 23, 2009, 1:01pm CDT

Exco to open Haynesville Shale office

Dallas Business Journal (source)

Dallas-based oil and natural gas company Exco Resources Inc. (NYSE: XCO) will officially open a new field office in the Haynesville Shale on Friday and will break ground on a new Haynesville Shale gas gathering and treating facility in Louisiana to accommodate all of the work the company is doing in the gas-rich shale.

The new field office is in Grand Cane, La., about 30 miles south of Shreveport.

Exco Resources has nine horizontal wells and eight vertical wells drilled and completed in the Haynesville shale play, the company said Tuesday. Exco intends to complete 21 more horizontal wells by the end of this year.

“We are very excited about the success we have achieved in the Haynesville Shale and have committed over two-thirds of our 2009 drilling and completion budget to continue developing the 85,000 net acres we have in the play,” said Doug Miller, chairman and CEO of EXCO Resources. “In addition to our production and development plans, we are committed to spend over $100 million in 2009 on our midstream business to add treating capability and throughput capacity in excess of 500 million cubic feet of natural gas per day by early 2010 in our Haynesville shale area.”

The Woodford Shale, A Major New Play

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

Special Focus: NORTH AMERICAN OUTLOOK-UNCONVENTIONAL RESOURCES

(source)

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

SOURCE ROCK PROPERTIES
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.

STRATIGRAPHY
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).

WELL LOG CHARACTERISTICS
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

LITHOLOGY AND FACIES DISTRIBUTION
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
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
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

ESTIMATION OF RESOURCE POTENTIAL
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.

CONCLUSIONS
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.

ACKNOWLEDGEMENTS
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.

LITERATURE CITED
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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.

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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.
.
THE AUTHOR
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.

How Wells Are Drilled Horizontally

The following is a simplified but good explanation of how oil and gas wells start drilling vertically and are then gradually turned in a desired direction. They then "build angle" with 0 degrees being vertical and 90 degrees being horizontal. This ability to drill horizontally, then fracture the rocks, and hold the fractures open with propant (sand or glass beads), is what allows these low permeability shales to produce economic quantities of gas and oil.

The source of this article is here: http://www.energyindustryphotos.com/how_oil_and_gas_wells_are_drille.htm

Peter

How Oil And Gas Wells Are Drilled Horizontally

Today's oil companies now have the ability to drill wells sideways, to reach specific pockets of oil and gas or "targets" which may be beneath cities or environmentally sensitive area where a rig cannot be set up. Multiple wells can be drilled from one pad site on land or from an offshore platform, reducing costs and the environmental impact of oil and gas exploration.

Horizontal drilling techniques are also used to expose more surface area of oil bearing rock so that the overall production of the well is increased in either a new well or old well that has been producing for some time.

You may be asking yourself, how do you get heavy, rigid drill pipe to turn and go sideways? The truth is that when so much pipe is strung together it does flex, enabling the hole to be drilled at up to a 90 degree inclination in any direction and out to a thousand feet or more horizontally from the vertical hole. The assembly that does the drilling is made up of several parts. They include the following:

Mud Motor Illustration of a Mud Motor as Used In Horizontal Oil and Gas Wells

A directional assembly (parts that make up the drill string that the rig lowers into the hole to drill the well) consists of a "mud motor" which is a machine that contains a rotor and stator inside it which are turned by the force of the drilling fluid or "mud" that is pumped down the drill pipe. This motor turns the drill bit so instead of turning the entire length of drill pipe, the motor, which is bent at a certain angle, can remain in a fixed position drilling the hole in whatever direction the bend of the motor is aimed toward.

MWD MWD tool on the surface. (Is lowered into a special section of drill pipe or " Monel collar" which is non magnetic.

A probe full of instruments is placed inside a nonmagnetic length of drill pipe just above the mud motor to show the driller on the surface which direction he is drilling in and at what angle or inclination he is heading. This instrument is an MWD or "Measure While Drilling" probe. It typically consists of instruments that measure inclination utilizing accelerometers, and instruments that measure azimuth or compass heading using magnetometers. This information is sent via a series of pressure pulses in the column of drilling fluid flowing down to the bit from pumps on the surface. At the surface a device called a transducer picks up these increases in pressure (similar to Morse code signals) and they are decoded by surface equipment in the MWD company's mobile lab that is placed on deck of the offshore rig, or near a the rig on land. This equipment is connected to a display on the rig floor where the driller can see which way the bent motor is sliding.

The directional driller can then turn the entire length of drill pipe ever so slightly in the direction he wants the well to go and the motor which is being turned by the flow of drilling mud coming down the drill pipe causes the bit to chew away at the rock and drill ahead. MWD equipment can also be combined with sensors that record gamma rays given off from the rock formations below, instruments that measure resistivity and conductivity, etc. This is known as "logging while drilling" or LWD. It enables the oil company geologists to see if they are staying in, or have reached, the oil or gas bearing zones in real time instead of having to pull all the drill pipe out of the hole and run a wireline based logging tool down the hole.

Enhanced Recovery

The ability of oil companies to drill horizontally is being used in fields that have been depleted to the point where very little oil or gas is flowing into the original vertical well and to drill multiple horizontal wells from the same offshore platform to a pocket of oil or gas as seen in the illustration below. See What is Enhanced Oil Recovery?

Illustration of an Offshore Horizontal Oil Well from a Drilling Platform

In a well that was originally drilled vertically in the past and is not producing as much as it once was, a "re-entry" will be done whereby a device called a whipstock is lowered and fixed at a certain depth.

A special bit or "mill" is used at the end of the regular drill pipe, deflected into the side of the casing by the whipstock to cut a hole in the heavy metal casing and out the side of the well. This is done somewhere just above the productive formation. Then, after this "window" has been cut the rig will pull the milling bit out of the hole and then lower the directional assembly consisting of the mud motor and MWD equipment down into the hole and begin to drill a horizontal hole. Horizontal drilling techniques are being used in a variety of rock formations including the Barnett Shale of Texas - Oklahoma, and the Bakken Formation in North Dakota and Canada. In the Barnett Shale and Marcellus Formation for example, horizontal wells can extract the very low volume of gas given off by the dense shale. In the past such formations of low porosity had been passed over and considered not economically viable with vertical wells. Now large areas of the United States are being opened up to natural gas exploration in shale and limestone formations of low porosity. These dense formations are drilled with horizontal drilling methods and then "fracked" with high pressure water to create more fissures that will allow gas to escape from the rock into the wellbore. Coal bed methane, or natural gas can be extracted from coal seams too deep to mine using horizontal drilling techniques.

Recent Advances In Technology

New techniques to drill wells horizontally are being developed all the time. One such technique is called "Rotary Steerable". With this system the entire drill string can be rotated, enabling faster penetration and quicker drilling of the well. It utilizes the same components, MWD and a mud motor, but it is a very specialized type of mud motor that has kick pads that orient the drill bit in the right angled direction instead of using a bent mud motor.

Leaders in the industry include companies such as Weatherford, Halliburton (Sperry Sun), Pathfinder Energy Services, Schlumberger and Baker Hughes.

The YouTube video below, while without sound, illustrates the drilling of a hypothetical horizontal well. It shows first the drilling of a horizontal hole, drilling the "curve" of the well with directional equipment, pulling out to cement in a "liner" or casing to protect the upper layers of the well bore, then drilling out of this casing again into rock horizontally and finally set the production casing. (click on the following link to see the video on youtube)

http://www.youtube.com/watch?v=Y37XbMEDnXc&eurl=http%3A%2F%2Fwww%2Eenergyindustryphotos%2Ecom%2Fhow%5Foil%5Fand%5Fgas%5Fwells%5Fare%5Fdrille%2Ehtm&feature=player_embedded

While these explanations are simplified I hope that they give the reader some idea of how this technology works. As the world requires more and more oil and gas new advances in drilling technology are being developed to work in deeper holes, hotter temperature zones and pressures.

Basics Of Horizontal Drilling

For more information on how oil wells are drilled the two books that I recommend the most are The Nontechnical Guide To Petroleum Geology, Exploration, Drilling and Production and A Primer Of Oilwell Drilling by Ron Baker. Both used by many colleges and technical schools as well as Oilfield Service companies in their training programs. For production only try Oil and Gas Production In Nontechnical Language. Drilling Technology In Nontechnical Language

is a lower cost alternative to "A Primer Of Oilwell Drilling". All can be found in The Oilfield Bookstore,

For More Information on any of these books and customer reviews click on the book covers below...

America Has Abundant (And Increasing) Amounts Of Natural Gas

This ought to be good news for everyone. The technology and infrastructure to drill and produce more natural gas is proven and much of it is already in place. We use this gas to heat our homes, cook our food, and generate substantial amounts of the electricity we need. The technology to use this gas to power automobiles, trucks and buses exists and involves only a simple and inexpensive conversion.

Increased drilling and production would create jobs, provide increased royalties and tax revenue to Local, State, and the Federal Government, and it would reduce our dependence on "foreign oil". So why aren't we going after this bonanza of energy? Why are drilling rigs sitting idle?
Peter

June 18, 2009

Estimate Places Natural Gas Reserves 35% Higher

By JAD MOUAWAD The New York Times (source)

Thanks to new drilling technologies that are unlocking substantial amounts of natural gas from shale rocks, the nation’s estimated gas reserves have surged by 35 percent, according to a study due for release on Thursday.

The report by the Potential Gas Committee, the authority on gas supplies, shows the United States holds far larger reserves than previously thought. The jump is the largest increase in the 44-year history of reports from the committee.

The finding raises the possibility that natural gas could emerge as a critical transition fuel that could help to battle global warming. For a given amount of heat energy, burning gas produces about half as much carbon dioxide, the main cause of global warming, as burning coal.

Estimated natural gas reserves rose to 2,074 trillion cubic feet in 2008, from 1,532 trillion cubic feet in 2006, when the last report was issued. This includes the proven reserves compiled by the Energy Department of 237 trillion cubic feet, as well as the sum of the nation’s probable, possible and speculative reserves.

What Is a Tcf?

Natural gas is generally priced and sold in units of a thousand cubic feet (Mcf, using the Roman numeral for

one thousand). Units of a trillion cubic feet (tcf) are often used to measure large quantities, as in

resources or reserves in the ground, or annual national energy consumption. A tcf is one billion Mcf

and is enough natural gas to: Heat 15 million homes for one year; Generate 100 billion kilowatt-hours of electricity;

Fuel 12 million natural gasfired vehicles for one year.

The new estimates show “an exceptionally strong and optimistic gas supply picture for the nation,” according to a summary of the report, which is issued every two years by a group of academics and industry experts that is supported by the Colorado School of Mines.

Much of that jump comes from estimated gas in shale rocks, which drilling companies have only recently learned how to tap. They have developed a technique called hydraulic fracturing, in which water is injected at high pressure into wells to shatter rocks deep underground, helping to release trapped gas.

The method, perfected in recent years in places like Texas and Pennsylvania, has set off a boom in new drilling, but is coming under increasing regulatory and environmental scrutiny. Shale gas accounts for 616 trillion cubic feet of reserves, or a third of the total, according to the report.

“New and advanced exploration, well drilling and completion technologies are allowing us increasingly better access to domestic gas resources — especially ‘unconventional’ gas — which, not that long ago, were considered impractical or uneconomical to pursue,” said John B. Curtis, a geology professor at the Colorado School of Mines and the report’s principal author.

The huge increase in estimated gas supplies comes just as concerns about energy security and climate change are prompting the most profound shift in energy policy since the oil shocks of the 1970s.

The Obama administration has sought more stringent fuel standards for new cars, and Congress is debating regulations that would progressively limit carbon dioxide emissions throughout the economy. The administration has taken a cautious approach to conventional energy resources, freezing leases to develop oil shale reserves and carefully reviewing future offshore leases for oil and gas.

Instead, the administration seeks to increase the share of renewable energy, especially wind and solar power. But experts say that meeting these goals will prove challenging given the scale of the nation’s energy use and the costs involved in switching from fossil fuels.

Shale gas currently provides a small fraction of the nation’s total gas production. But many experts believe the rising supply of natural gas means it can substitute for other fossil fuels. With the output of conventional gas forecast to decline, the Energy Department expects that shale production will rise substantially to meet higher demand, as will imports.

Natural gas accounts for about a quarter of the nation’s total energy use, and 22 percent of electrical production. Coal accounts for about half of the nation’s power generation, while oil dominates transportation fuels. While gas generates less carbon dioxide than oil or coal, it still accounted for about 20 percent of domestic energy-related emissions in 2006.

The Energy Department estimates that demand for natural gas will rise by 13 percent by 2030. In the power sector, utilities have been switching to natural gas from coal, but further increases in the use of gas will most likely depend on whether Congress puts a price on carbon dioxide emissions, as it is considering. That would favor cleaner fuels like gas.

“It’s nice to have aspirations about renewable energy and efficiency, but we need to recognize these are long-term goals and that we need something to get us there in the meantime,” said Guy F. Caruso, a former administrator of the Energy Information Administration. “Natural gas has a role to play as a bridge because of the long lead time and scalability issues of renewable fuels.”

That the nation’s gas reserves were bigger than expected does not mean they will necessarily be developed, Mr. Caruso warned. “There are some things to be cautious about,” he said, “and obviously one of them is cost, and the other is regulatory risk.”

In recent years, industry executives and analysts have been surprised by the discovery and successful development of new supplies of shale gas, like the Barnett Shale in the area around Fort Worth.

But higher drilling costs and the extensive use of water to fracture shale rocks have raised concerns about the long-run commercial potential of these supplies. Some environmental groups fear that hydraulic fracturing will pollute drinking water, and Congress is considering tighter regulation of the practice.

Mr. Caruso said that gas prices needed to be around $4 to $6 per thousand cubic feet to justify developing shale beds. They have fallen below that level at times in recent months, though gas settled Wednesday at $4.25.

For advocates of the gas industry, the report vindicates the potential of natural gas in the economy.

“Natural gas is part of the solution for a low-carbon future, and not an impediment,” said Chris McGill, the managing director for policy analysis at the American Gas Association, a trade group. “It has been difficult to get policy makers over that hump. Many have a vision of gas as a resource we’re running out of, and that’s just not true.”

EXCO Succesful In The Haynesville

EXCO Resources Announces Results of First Horizontal Haynesville Completion

Wednesday, December 10, 2008 (source)

EXCO Resources, Inc. today announced the completion of the Oden 30H#6 in DeSoto Parish, Louisiana, its first Haynesville horizontal well completion. The Oden 30H#6 was drilled vertically to a depth of 12,304 feet in the pilot hole where 180 feet of whole core was recovered in the Haynesville Shale. The horizontal target was selected, and the well was plugged back and drilled with a 4,481 foot lateral to a total measured depth of 16,083 feet. We completed the well with a nine stage fracture stimulation treatment using 3.2 million pounds of proppant. The well had an initial production rate of 22.9 million cubic feet of gas per day (MMcf/d) on a 26/64th inch choke with 7,800 pounds per square inch (psi) flowing casing pressure. The well has been flowing to sales for the past five days and, in the last 24 hours, averaged 22.5 MMcf/d on a 26/64th inch choke and 7,800 psi flowing casing pressure. EXCO owns a 100% working interest and a 75% net revenue interest in the well.

EXCO owns a substantial acreage position in the core area of the Haynesville play in North Louisiana and East Texas, much of which is held by shallow production. We have drilled and completed several vertical Haynesville tests and have identified productive Haynesville shale across much of our acreage holdings. We have conducted a variety of core and fluid studies from data acquired in our vertical well program and have tested a combination of fluid types and fracture stimulation designs. The results of those tests were instrumental in developing the completion plan for our first horizontal well. EXCO has 2 operated horizontal wells, 1 vertical well and 2 outside operated horizontal wells in progress in the Haynesville play. We plan to drill 25 or more horizontal Haynesville wells in 2009.

Douglas H. Miller, EXCO’s Chairman, commented, “This well is the largest single well in our Company’s history and represents the first of many horizontal drilling locations that we have in the Haynesville play.”

Penn Virginia Corps Tests Haynesville In East Texas

Penn Virginia Announces Lower Bossier (Haynesville) Shale Well Results

Tuesday, June 02, 2009

Penn Virginia Corporation announces the results of a horizontal Lower Bossier (Haynesville) Shale well in Harrison County in east Texas.

PVA successfully completed the Steele #2-H well (100 percent working interest) which tested at an initial production rate of approximately 11.4 million cubic feet of natural gas per day with a flowing casing pressure of approximately 4,600 pounds per square inch. The well had an approximate 4,000-foot lateral and was stimulated with approximately 2.5 million pounds of sand and bauxite over ten stages. This well has the highest initial production rate of any Lower Bossier Shale well PVA has drilled to date in east Texas.

PVA is in the process of completing an additional Lower Bossier (Haynesville) well.

Investing In Shale Gas

How to Invest In Shale Gas Fields Like The Marcellus And Eagle Ford Shale

By Doodlebugs, eHow Member

The United States is the Saudi Arabia of natural gas, thanks to the discovery of new shale gas deposits like the Marcellus Formation. Here is how you can invest in what could be our primary energy source in the future. (source)

Instructions

1. Step 1

   Learn as much as you can about shale gas and its economic importance. The United States has an abundance of clean natural gas trapped in shale formations such as the Marcellus Shale of Appalachia, the Barnett Shale near Fort Worth, the Haynesville Shale in Louisiana and newly discovered gas shales such as the Eagle Ford shale in South Texas. Many experts believe that there is enough natural gas in these shale formations to last the United States a hundred years or more. According to oil man T. Boone Pickens this clean fuel may one day power our cars as well as our homes. How can you invest in this growing industry? There are a couple of ways to invest in shale gas. Some are more risky than others.

2. Step 2

   Consider direct investment in a well. One way to invest in shale gas is to invest directly in a wildcat well being planned. This type of investing is for the rich only since there is a high probability it could be a dry hole but potential rewards could be very high. For direct investment you will often need as much as $100,000. If you have the stomach for this kind of investing contact companies like Petrohawk Resources, symbol HK, and inquire about direct investment.
   The second, and less risky way of investing in shale gas is to buy shares of the companies that are most active in drilling in gas shales such as the Marcellus shale formation. These include Chesapeake, symbol CHK, XTO Energy, symbol XTO, Petrohawk, symbol HK, Devon Energy, symbol DVN, and EOG Resources, symbol EOG.
   Petrohawk (HK) and TXCO Resources (TXCO) are active in the newly discovered Eagle Ford Shale in South Texas. Chesapeake, Devon and XTO are active in the Barnett Shale and Marcellus formation.

3. Step 3

   Buy shares on the open market. A third option for investing in shale natural gas is to buy shares of an Exchange Traded fund or ETF. You can invest in natural gas as a commodity with the ETF whose symbol is UNG or you can focus on exploration and production with an ETF called First Trust ISE Revere Natural Gas, symbol FCG and listed on the NYSE, which is composed of companies like the ones mentioned in step 2 that explore for and produce natural gas.
   For more info on the Marcellus Formation see the resources section.

Gas Production Boom

APRIL 30, 2009

U.S. Gas Fields Go From Bust to Boom

• By BEN CASSELMAN (source)

CADDO PARISH, La. -- A massive natural-gas discovery here in northern Louisiana heralds a big shift in the nation's energy landscape. After an era of declining production, the U.S. is now swimming in natural gas.

Even conservative estimates suggest the Louisiana discovery -- known as the Haynesville Shale, for the dense rock formation that contains the gas -- could hold some 200 trillion cubic feet of natural gas. That's the equivalent of 33 billion barrels of oil, or 18 years' worth of current U.S. oil production. Some industry executives think the field could be several times that size.

"There's no dry hole here," says Joan Dunlap, vice president of Petrohawk Energy Corp., standing beside a drilling rig near a former Shreveport amusement park.

From Rock to Gas

View Slideshow

Jared Moossy/Redux

Huge new fields also have been found in Texas, Arkansas and Pennsylvania. One industry-backed study estimates the U.S. has more than 2,200 trillion cubic feet of gas waiting to be pumped, enough to satisfy nearly 100 years of current U.S. natural-gas demand.

The discoveries have spurred energy experts and policy makers to start looking to natural gas in their pursuit of a wide range of goals: easing the impact of energy-price spikes, reducing dependence on foreign oil, lowering "greenhouse gas" emissions and speeding the transition to renewable fuels.

A climate-change bill being pushed by President Barack Obama could boost reliance on natural gas. The bill, which could emerge from the House Energy and Commerce Committee in May, is expected to set aggressive targets for reducing emissions of carbon dioxide, the most prevalent man-made greenhouse gas.

Meeting such goals would require quickly moving away from coal-fired power plants, which account for substantial carbon emissions. President Obama wants the U.S. to rely more on renewable energy such as wind and solar power, but those technologies aren't ready to shoulder more than a fraction of the nation's energy burden. Advocates for natural gas argue that the fuel, which is cleaner than coal, would be a logical quick fix. In addition, billionaire energy investor T. Boone Pickens has been touting natural gas as an alternative to gasoline and diesel for cars and trucks.

"The availability of natural-gas generation enables us to be much more courageous in charting a transition to a low-carbon economy," says Jason Grumet, executive director of the National Commission on Energy Policy, who was a senior adviser to President Obama during the campaign.

Just three years ago, the conventional wisdom was that U.S. natural-gas production was facing permanent decline. U.S. policy makers were resigned to the idea that the country would have to rely more on foreign imports to supply the fuel that heats half of American homes, generates one-fifth of the nation's electricity, and is a key component in plastics, chemicals and fertilizer.

But new technologies and a drilling boom have helped production rise 11% in the past two years. Now there's a glut, which has driven prices down to a six-year low and prompted producers to temporarily cut back drilling and search for new demand.

The natural-gas discoveries come as oil has become harder to find and more expensive to produce. The U.S. is increasingly reliant on supplies imported from the Middle East and other politically unstable regions. In contrast, 98% of the natural gas consumed in the U.S. is produced in North America.

Coal remains plentiful in the U.S., but is likely to face new restrictions. To produce the same amount of energy, burning gas emits about half as much carbon dioxide as burning coal.

Natural gas has never played more than a supporting role in the nation's energy supply. Crude oil, refined into gasoline or diesel, fuels nearly all U.S. cars or trucks. Coal is the dominant fuel for generating electricity.

Natural-gas production in the U.S. peaked in the early 1970s, then fell for a decade due to weak prices and declining gas fields in Texas, Louisiana and elsewhere. Production bounced back in the 1990s with the discovery of new fields in New Mexico and Wyoming, but by 2002, output was falling again -- this time, most experts thought, for good. Believing the U.S. would soon need to import liquefied natural gas from overseas, companies such as ConocoPhillips, El Paso Corp. and Cheniere Energy Inc. spent billions on terminals, pipelines and storage facilities.

The supply fears drove up prices, which spurred innovation. Oil-and-gas companies had known for decades that there was gas trapped in shale, a nonporous rock common in much of the U.S. but considered too dense to produce much gas.

In the 1980s, Texas oilman George Mitchell began trying to produce gas from a formation near Fort Worth, Texas, known as the Barnett Shale. He pumped millions of gallons of water at high pressure down the well, cracking open the rock and allowing gas to flow to the surface.

Oklahoma City-based Devon Energy Corp. bought Mr. Mitchell's company in 2002. It combined his methods with a technique for drilling straight down to gas-bearing rock, then turning horizontally to stay within the formation. Devon's first horizontal wells produced about three times as much gas as traditional vertical wells.

The development of the Barnett Shale almost single-handedly reversed the decline in U.S. natural-gas production. Last year, the Barnett produced four billion cubic feet of gas a day, making it the largest field in the U.S. Other companies such as Newfield Exploration Co., Southwestern Energy Co. and Range Resources Corp. found shale fields across the U.S.

One of the most aggressive companies was Oklahoma City-based Chesapeake Energy Corp., which got into the Barnett a couple of years behind cross-town rival Devon, and was an early entrant into the second big U.S. field, the Fayetteville Shale in Arkansas. In 2005, Chesapeake Chief Executive Aubrey McClendon sent teams of geologists across the country with a mission: Find the next Barnett. Less than two years later, they told him they had it, in Louisiana.

The Haynesville Shale is centered in northern Louisiana, one of the country's oldest oil- and gas-producing regions. Wildcatters had explored beneath the lush cow pastures and cotton fields as far back as the 1870s. Shreveport, the region's largest city, saw decades of booms and busts until the 1980s, when a glut of cheap oil from overseas all but killed the region's oil industry.

Oil companies knew about the Haynesville Shale, but it was considered a less viable prospect than the Barnett. The shale lies 10,000 or more feet below ground, where high pressure and 300-degree temperatures are enough to fry high-tech drilling equipment.

But in 2006, Chesapeake drilled an exploratory well and decided the results were promising enough to justify the higher cost of drilling in such harsh conditions. By late 2007, Mr. McClendon says, "we knew that we had a tiger by the tail."

In March 2008, as oil and gas prices were soaring, Chesapeake went public with its findings. The rush was on: Dozens of companies dispatched agents to the area to lease land for drilling, turning farmers and ranchers into millionaires overnight.

"There was excitement in the air," recalls Jeffrey Wellborn, a Shreveport resident who sits on the board of the local Sierra Club. "You thought everyone in the world had won the lottery."

The frenzy marked the peak of a nationwide drilling boom that was fueled by a combination of soaring energy prices and easy credit. It didn't last. Between July and October, oil and gas prices fell by more than 50%, and kept falling.

The weakening economy eroded demand for both oil and gas. Natural gas, unlike oil, suffered from a supply glut. U.S. gas production rose 7.2% last year, while oil production fell 1.9%. As a result, oil prices are up 12% since the start of 2009. Natural-gas prices have fallen 41% to their lowest since 2002.

Gas producers saw their profits evaporate and share prices slump. Liquefied-natural-gas imports plunged, leaving import terminals nearly idle. Worried about a glut, companies cut back sharply on drilling and formed a lobbying group to try to boost demand.

The growing supply created opportunities for policy makers and environmentalists, who saw natural gas as a possible solution to the nation's energy problems. Some groups suggested burning more gas and less coal for power generation. Others favor its use in vehicles.

Mr. Pickens has spent millions promoting an energy plan that aims to, among other things, convert thousands of big-rig trucks to run on natural gas. Mr. Pickens has large investments in natural gas and stands to benefit if his plan is adopted. In TV ads, Internet videos and speeches, he emphasizes a different goal: reducing U.S. dependence on foreign oil.

Environmental Capital

• Green Ink: Mixed Blessings of a Natural-Gas Boom

Mr. Pickens arrived for a recent speech in Dallas in a natural-gas-fueled Honda Civic with a bright blue "Pickens Plan" logo. He told a packed auditorium that the U.S. is importing two-thirds of its oil even as the country is "absolutely overwhelmed with natural gas." If the reverse were true, he said, he would favor burning oil.

Some environmentalists have embraced Mr. Pickens's plan as a way to fight climate change. Carl Pope, executive director of the Sierra Club, says he sees natural gas as a "bridge fuel" that could help the U.S. burn less coal and oil until renewable sources of energy are ready to take over.

The dual message of energy security and environmental responsibility has helped Mr. Pickens win powerful allies, including Senate Majority Leader Harry Reid, House Speaker Nancy Pelosi and dozens of elected officials from both parties. A bipartisan bill providing tax incentives for natural-gas cars looks likely to pass this year.

Not everyone shares Mr. Pickens's enthusiasm for natural-gas vehicles. Major users of natural gas, such as utilities and chemicals companies, are concerned the plan would drive up prices -- an outcome that would benefit producers.

Energy Secretary Steven Chu and some other policy makers have expressed doubts about the practicality of retrofitting hundreds of thousands of service stations to offer natural gas. Some environmental groups, including the Natural Resources Defense Council, have argued that natural gas is better used to replace coal for power generation, and that cars should run on electricity generated by the sun, wind and natural gas.

Market forces are already helping natural gas make inroads against coal and oil. Gas is now cheaper than coal in many parts of the country, leading utilities to burn more gas. Of the 372 power plants expected to be built in the U.S. over the next three years, 206 will be fired by gas and just 31 by coal, according to the Energy Information Administration.

Natural gas is gaining market share far more slowly in transportation. Earlier this year, AT&T announced it would convert up to 20% of its truck fleet to run on natural gas, largely because it has been cheaper than gasoline in recent years. Cities including New York, Los Angeles and Atlanta have converted part of their bus fleets to run on natural gas, for air-quality reasons.

Shreveport could be the next city to make the switch. In March, Mayor Cedric Glover announced that the oil capital turned natural-gas boomtown would abandon diesel and convert its bus fleet to natural gas.

—Russell Gold contributed to this article.

Write to Ben Casselman at ben.casselman@wsj.com

The Challenge Of Producing Gas From Shale

The following article comes from the May, 2009 issue of the "AAPG Explorer". Reading about the many logging tools and other methods allegedly used to evalute these shales and make drilling, fracing, and completion decisions, leads me to wonder if maybe some people are making this more complex than it needs to be. Of course service companies want to sell as many of their products and services as possible, and that should be taken into consideration.

At the same time, these shale gas plays are relatively new and experience will provide more efficiency. Meanwhile I think there is much to be learned.
Peter

Shale Calls for the Unconventional

By LOUISE S. DURHAM
EXPLORER Correspondent (source)

Natural gas prices in the $3/Mcf-and-under range understandably are causing many operators to scale back on budgets, production and new drilling projects.

Just don’t expect this to be a permanent scenario.

The consensus is that once the economy turns around, hydrocarbon demand will make an about-face as well.

The waiting game doesn’t necessarily imply wasted time as it offers continued opportunity to delve deeper into potential techniques to better evaluate some of the more challenging and often perplexing plays being explored/ produced.

High on this list are the numerous shale gas plays that have sprung to life over the past couple of years in various regions of the country.

Gas shales differ from conventional reservoirs in that they function not just as reservoir rock but also source rock and seal. Economical production from this complex rock demands extensive hydraulic fracturing and often requires horizontal wells.

Successful wells depend on an in-depth understanding of the geology, petrophysics and geomechanics of the particular shale formation. In fact, an integrated approach to shale gas evaluation can be key to conquering the complexities of these rocks to optimize production of the natural gas they hold.

“It’s fairly obvious to anyone who works in these plays that conventional methods just don’t work,” said Duane Sommer, senior petrophysical engineer at Baker Hughes.

“Our integrated interpretation methodology designed specifically to evaluate shale gas reservoirs focuses on conventional resistivity, neutron, density, advanced acoustic logs,” Sommer said, “and we add magnetic resonance, geochemical, geomechanics and borehole image logs to determine an array of information.”

That array includes lithology, mineralogy, rock mechanical properties, total organic carbon and gas-in-place in the formation, he added.

Specific Challenges

However, not all shales are created equal, so there are differing factors that must be taken into account.

For instance, borehole imaging is not that important in the high-profile Haynesville shale play because there’s no significant fracturing in the Haynesville, Sommer said. In contrast, it’s quite important in the Barnett play and some others.

He noted also that in the Haynesville the actual presence of gas is a given, but it presents other challenges:

• How to optimize getting that gas out of the ground.
• Selecting the best intervals for the completion.
• How to implement the frac job to get the best production possible.
• Where to place the horizontal leg if going lateral.

The goal with all the shales is to gather all the data possible.

“One of the things we found in the Haynesville, especially, is the intervals that seem to produce the best and have the most silicious material,” Sommer said. “They have more quartz than limestone.

“Part of that is the geomechanics,” he explained. “That rock breaks easier – making it easier to frac – so we look at the geochemical logs in combination with the advanced acoustics which we do rock mechanical properties with and look at what intervals will frac easiest.”

Identifying the Interval

The next step is to look at some of the standard logs or magnetic resonance to try to get a better idea of porosity. This can vary significantly in different plays, e.g., porosity is quite low in the Barnett but ranges from 8 to 10 percent in the Haynesville, according to Sommer.

“When we put all our information together, first we find which intervals in the well will fracture easiest,” he said. “Of those we identify which have the best porosity, which has total organic carbon in or near that interval to supply the gas itself.

“We’re trying to pick the interval we think will be most successful for completion,” Sommer noted. “If you’re going lateral instead of just perfing and fracing, you still want to drill the lateral in that same interval.”

The acquired data are presented to the client in a large, wide plot that Sommer likens to a facies curve that shows crucial information such as:

• The target type of rock.
• A piece of rock that would be a barrier to a fracture.
• Rock to stay away from.

“We’re trying to make it as simple as possible for someone to look at the well,” Sommer said, “and even if they don’t understand all the pieces, to be able to say OK, this is where we need to be, where we need to frac, where we need to perf or where to drill our lateral.

“In a nutshell, that’s our approach,” said Sommer, who noted the overall presentation remains the same even though the individual pieces change from basin to basin.

“The general process,” he said, “usually works for all.”