NORTH AMERICAN OUTLOOK UNCONVENTIONAL RESOURCES
Katrina Boughal, Technical Editor; World Oil, August 2008
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.  Unconventional gas plays in the US have been booming since technological advances increased production in the now-famous Barnett Shale. Horizontal drilling and frac 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 previously thought 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. 
HAYNESVILLE
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

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 late June 2008. The Elm Grove Plantation #63, drilled in Bossier Parish, encountered about 212 ft of Haynesville Shale, producing 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

Forest Oil 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

<>CMX 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, completed a horizontal well in Feb., initial production of 8 MMcfd.8

FAYETTEVILLE
 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 thickness 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

MARCELLUS

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 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 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<>WOODFORD
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 later.

BARNETT 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
BAKKEN
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.

OTHER PLAYS
There are a multitude of unconventional shale plays being assessed, and the following ate 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 "nor 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 I MMcfd production rates from two 4,800-ft vertical wells.29


<>Chattanooga
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 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 ro 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 rare of 3.9 MMcfd.34 Atlas Energy Resources announced in June 2008 the successftil 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 deprhs from about 4,000 ft to 9,000 ft below surface level,36 the Floyd thickens toward the northeast, wirh a maximum thickness of about 600 ft, and has aTOC 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 quartet 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.
LITERATURE CITED
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,” Plats 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/080701/2008070l006524.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/ap5l69765. html, accessed July 10, 2008.
7 GMX Resources Inc. announces Haynesville/Bossier Shale drilling to begin 3Q08,” Prime Newswire, July 7, 2008, http://wwsv.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/artic1e. 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, http://164. 109.37.157/Reports/Stan-dardReport.aspx, accessed July 11, 2008.
13 “Fayetteville Shale play,” Southwestern Energy Company, http://www. swn.com/operations/fayetteville.shale.asp, accessedJuly 8, 2008.
14 “Chesapeake reports Haynesville Shale discovery in Louisiana and announces CapEx increase,” OilVoice, March 24, 2008, http:// wwsv.oilvoice.com/n/Chesapeake_Reports_Haynesville.Shale_Discovery_in_Louisiana. and_Announces CapEx increase/92fOlda5.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/arricle/pressRelease/idU5l27932-v2l-Feb-2008+MW20080221, accessed July 14, 2008.
21 Brown, D., “Big potential boost the Woodford,”4APGExplorer, July 2008.
22 Comet, 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/artic1e/pressRelease/ idU5l39442+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%20l-l-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/ idU5l34787+Ol-Apr-2008+BW20080401, accessed July 11, 2008.
30 “Chattanooga Shale natural gas field,” Oil Shale Gas, http://wwsv. 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://wsvw.reuters.com/article/preeRelease/ idU5l39048+28-Apr-2008+MW20080428, accessed July 9, 2008.
34 “CNX Gas reports fourth quarter and full year 2007 results,” Reu­ters, Jan. 29, 2008, http://wwsv.reuters.com/article/pressRelease/ idUSl4O4lO+29-Jan-2008÷PRN20080129, accessed July 11, 2008.
35 “Atlas Energy announces 4successful 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/At-lasEnergyAnnounces_FourSuccessful_Horizontal...WellsJn..Tennessees_Chattanooga_Shale/9fc6bbeo.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 3rd Q 2007 financial results,” Carrizo Oil & Gas, Nov. 8, 2007, http://carrizo.mediaroom.com/index.php?s=43&iten=l54, accessed July 10, 2008.
38 Edmonds, C., “New shales may be ready to deliver,” The Street, Feb. 22, 2007, http://www.thestreet.com/story/l0340267/l/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://wsvsv.reuters.com/article/pressRelease/ idU5248894÷09-May-2008-vPRN20080509, accessed July 11, 2008.
<>Woodford Shale -- a viable play.
Reservoir characteristics, production potential, with enough oil and gas to potentially become a major unconventional hydrocarbon reservoir. John B. Corner, 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<>.

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 Wood-ford. 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, <unconventional_Fig_6.jpg Organic carbon con­centrations range from less than 0.1 per­cent weight in some chert beds15 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

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.














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. 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% TOG.


The association of chert and fractures in producing reservoirs suggests that the best unconventional wells are likely to be completed in the cherry facies. The Woodford facies distribution is the result of Late Devonian paleogeography and depositional processes. During the Late Devonian, the southern mid-continent 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 Wood-ford 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

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.

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.