"Unconventional" Gas Plays

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

Peter

SPECIAL FOCUS: NORTH AMERICAN OUTLOOK- UNCONVENTIONAL RESOURCES
Unconventional plays grow in number after Barnett Shale blazed the way
The Haynesville and Marcellus are becoming exciting new gas plays, while activity in the Woodford and Fayetteville continues.
Katrina Boughal , Technical Editor

Unconventional gas plays in the US have been booming since technological advances increased production in the now-famous Barnett Shale. Horizontal drilling and fracture stimulation in the shale source rock, as opposed to the sandstone/limestone/dolomite reservoir rock, have proved to be successful not only in gas plays like the Barnett, Fayetteville and Woodford, but also in the Bakken-a primarily oil-rich formation.

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

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

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

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

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

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 thicknesses varying between 50 and 300 ft and drilled at depths ranging from 2,000 to 6,000 ft. Thickness in the Fayetteville differs from east to west, at about 50 to 75 ft thick in western Arkansas to about 300 ft at the eastern edge of the Arkoma Basin. The formation is productive from its middle to base because the lower section is rich in organic material, with chert and siliceous interbedding. 9 The unit is thermally mature, and is differentiated from surrounding units by high radioactivity and resistivity signatures. 10

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

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

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

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

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

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

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

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

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, please see page 83.

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

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

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

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

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

New Albany.

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

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

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,” Platts Oilgram News , July 4, 2008, pg. 6.

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

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

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

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

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

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

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

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

12 “Baker Hughes US rig count- Summary report,” Baker Hughes- Investor relations- Rig counts, http://164.109.37.157/Reports/StandardReport.aspx, accessed July 11, 2008.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The Father Of The Barnett Shale Gas Play

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The Father of the Barnett
A unique set of factors converged to kick off the Barnett boom. New technologies such as artificial fracturing and horizontal drilling made it possible to extract large amounts of gas from shales. The relatively high price of gas in recent years made it economically viable.
Yet according to Eric Potter, neither of these would have mattered without one critical element:
“It wasn’t high tech. It was persistence and experimentation on the part of one company that got this boom going.”

Mitchell Energy had produced gas from a shallower formation, the same formation that John Jackson had discovered in the 1950s. That production was waning.
“They began looking around for what could be done in the same area,” says Potter. “They had always noticed that when you drilled through the Barnett, you would get a gas show. But everyone thought you wouldn’t get much gas.”
Even though shale may have a lot of pores with the ability to store gas, it is not very permeable. In other words, it does not have many connections between the pores and so trapped oil and gas can not flow easily.

“Mitchell Energy sunk a lot of money over a long period into learning how to stimulate the rock so it would flow,” says Potter. Their first attempts were expensive “massive hydraulic frac jobs.” They would pump a very large volume of fluid and sand down a well bore to crack the rock and give it more permeability. At first, they got the gas flowing, but the methods and materials were expensive. So they wondered if they could pump less fluid and get the same effect.
“They arrived at something called a light sand frac,” says Potter. “Suddenly it was economical and at the same time—in the mid-1990s—the price of gas was rising. By the late 1990s, they had perfected the technique in vertical wells and started applying it to several hundred wells. That’s when it came to the attention of industry.”

Potter first heard about these early successes from a Mitchell employee in 1996.
“I didn’t think it would have the kind of impact it did,” he says. “I wasn’t the only one. Most people in industry were surprised and had difficulty adjusting to the notion that shale could produce in commercial amounts over such a wide area. There were only a few companies that appreciated the value of hydraulic fracture technology applied on such a large scale.”
When thermally-mature organic-rich mudstone is drilled into, the pressure drops and gas is released by a process called desorption. Early estimates of how much gas would be given up by the Barnett Shale turned out to be far too low. The experiments were run again and it was realized that this shale would give up much more gas than was previously thought.
“Then it was realized, oh, if you scale that up to the whole area and then to the whole county and up to the whole Basin, the amounts of gas are really quite prodigious,” says Potter. “People became aware of that in 2002 and 2003 and that really got the ball rolling.”

Mitchell Energy already had critical infrastructure in place to process and transport gas. So they could quickly and economically take advantage of the discovery.
“It took George Mitchell 18 years to make it work,” notes Larry Brogdon, partner and chief geologist for Four Sevens Oil Company. “He is the father of the Barnett Shale. He was tenacious. He started in 1981 and it really didn’t take off until 1999. And even then, it took a long time to develop it.”
by Marc Airhart

Barnett Shale Gas

The gas being produced from the Barnett Shale represents one of the most exciting developments in the oil and gas industry in decades.
Peter

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Barnett Boom Ignites Hunt for Unconventional Gas Resources
January 2007
The global hunt for unconventional gas reserves recently turned to an unlikely spot—a patch of north central Texas that already seemed tapped out after 50 years of intense oil and gas drilling.
Technology, economics and one man’s persistence transformed the Barnett Shale formation of the Fort Worth Basin into a booming new frontier.
As conventional petroleum reserves dwindle in the U.S., public pressure mounts to reduce the country’s dependence on foreign energy, and the price of oil and gas rises, energy companies are setting their sights on “unconventional” domestic sources. These include oil sands, coal beds and shales.

In less than a decade, the Barnett Shale play has become the largest natural gas play in the state of Texas and, as new wells sprout like bluebonnets across the Fort Worth region, it might soon become the largest in the nation.
“This play already covers parts of 15 or more counties,” says Eric Potter, associate director of the Bureau of Economic Geology at the University of Texas at Austin. “It compares favorably with the biggest of the old oil booms of the early 20th century.”
Of course this boom is different. The concrete-like shale gives up its gas grudgingly. So individual wells tend to be smaller and more expensive to operate.

In less than a decade, the Barnett Shale play has become the largest natural gas play in the state of Texas and, as new wells sprout like bluebonnets across the Fort Worth region, it might soon become the largest in the nation.
“The East Texas gushers would win out hands down,” says Potter. “But there are so many [Barnett] wells that even though they are modest, the total output is going to be huge.“
This play is also different because much of the untapped gas lies under the highly populated Fort Worth metropolitan area. Oil and gas companies are finding new challenges drilling in an urban setting.
Now, some experts are wondering if the boom can go global. The search is on for similar shale formations around the world, including the Fayetteville Shale in Arkansas.

Going to the Source
The fact that there is a Barnett boom at all reflects a tectonic shift in thinking. In the past, drillers bypassed the source rock that generated the oil and gas and focused on the reservoir rock, where the resources were easier to extract. Typically, oil or gas exits from the source rock and migrates to places where it is trapped. And those traps—conventional fields—typically do not cover a large area.
“There would be a field here and then a lot of blank space and then a few miles over there would be another field,” says Potter. “But this kind of play, it just covers county after county. You’re looking at thousands and thousands of wells covering the land.”
According to Eric Potter, the 5,500 wells currently pumping gas in the Barnett Shale play will ultimately generate on the order of $35 billion for their owners and through an economic ripple effect, $100 billion for the Texas economy.

With new technologies for coaxing gas out of shales, drillers see the Barnett as both source and reservoir. One such technology is artificial fracturing—in which operators pump water and sand down a well to create fractures that liberate more gas from the rock.
Potter and his colleagues at the Bureau are analyzing the properties of shales across the state. Ultimately, they hope to apply their work to similar rock formations anywhere in the world.
“Now any kind of mudrock or shale that’s black, organic rich, reasonably thick, and reasonably deep we’re interested in,” says Potter. “The question is, all shales are not alike, so what makes a shale prospective as opposed to one that is not prospective? We don’t really know that yet.”

Wise Investment
Before he died in 2003, oilman and philanthropist John Jackson donated to The University of Texas at Austin royalty interests in roughly a thousand wells in the Fort Worth Basin, part of the bequest that led to the formation of the Jackson School of Geosciences. These wells were producing oil and gas from the younger Bend Conglomerate formation just above the Barnett.
The Bend Conglomerate was formed during the Pennsylvanian age, meaning it was laid down about 290 to 320 million years ago. The Barnett Shale, a marine basinal deposit of middle to late Mississippian age, was laid down about 320 to 360 million years ago.
Could the same wells produce significant amounts of gas from the older, deeper Barnett shale? Potter and his colleagues at the Bureau helped the University assess the long-term potential of the University’s royalty interests.

Royalty interests on about a thousand wells donated by John Jackson, mostly in Wise County, Texas help build one of the world’s premier geoscience programs at the Jackson School.
“The short answer is that we think that most of that acreage has quite good potential in the Barnett,” says Potter. “Eight of the top ten Jackson School royalty wells are producing from the Barnett Shale. We are forecasting that most of these holdings will produce from the Barnett.”
The University receives on average about two percent of the gross revenue from wells it holds royalty interests on. That money is being used to build one of the world’s premier geosciences programs at the new Jackson School. Because the money goes into general funds, it supports all of the activities of the school, including dean Eric Barron’s priorities: to create the world’s most student-centered earth science program, to attract and retain the best research talent, to increase the breadth and depth of the faculty and research community and to establish the “fabric of a great school.”

Researchers at the Bureau are providing technical analysis to help stimulate additional drilling and production in Wise County, where most of the University’s royalty interests are located. Emphasis so far has been on mapping the basic stratigraphic and structural framework, tracking successful drilling in the less developed southern part of the play, mapping similar conditions in Wise County, and remapping the thermal maturity of the formation. The maturity seems to relate directly to the gas to oil ratio, one of the key factors controlling gas flow rates.
According to Potter, the 5,500 wells currently pumping gas in the Barnett Shale play will ultimately generate on the order of $35 billion for their owners. As those companies pay taxes and wages, and as their employees and contractors in turn spend their money, there is an economic ripple effect, creating an overall value of about $100 billion to the Texas economy.
Of course, that is only counting current wells. Potter predicts that if gas prices stay relatively high, tens of thousands of new wells will be drilled in the coming decades.

“It’s a ubiquitous reservoir,” says Larry Brogdon, partner and chief geologist for Ft. Worth based Four Sevens Oil Company. “It’s everywhere. You can not drill a well without hitting the Barnett, and the gas is always there. The question is can you get it out or not.“
So far, operators have extracted 2 trillion cubic feet of gas from the Barnett Shale play. At about 1.5 billion cubic feet a day, that’s about 2 percent of the daily natural gas consumption of the U.S.
“When you can go from nothing to the second largest producing gas field in the country in a matter of just a few years, that makes a statement,” says Rich Pollastro, a geologist with the U.S. Geological Survey in Lakewood, Colorado. “That’s huge. And it could potentially become the largest producing field in the country. That was a real awakening for the country and now because of its success, industry and nations are looking at it worldwide.”

The Next Barnett?
In the summer of 2004, Southwestern Energy announced that the Fayetteville Shale formation in the Arkoma Basin had many of the same characteristics that made the Barnett Shale formation so desirable for gas production. Before the announcement, the company had quietly acquired mineral leases on nearly a half million acres of land.
The announcement set off another gas boom. Oil and gas operators familiar with the Barnett Shale rushed to Arkansas to get in on the action.
“The analog would be like a 19th century gold rush,” says Ed Ratchford, geology supervisor for the Arkansas Geological Commission in Little Rock. “Everyone stakes a claim. You don’t say this place is going to be better than this place. You don’t have time. People were leasing thousands of acres a day.”

Ratchford and his team maintain a well log library, a collection of well cuttings and cores from oil and gas wells across Arkansas. They used these to conduct geochemical tests on samples from the Fayetteville Shale and produce a regional picture of where good gas prospects were likely to be.
“We had companies all over us waiting for us to get this stuff done,” says Ratchford. “They were sitting out in the parking lot before we opened up. We were the only ones that had this information. It was critical for helping the operators know where to lease.”
In the excitement, many companies took a gamble on mineral leases.

Locations of the Barnett Formation. Source: USGS.
“We had a lot of companies that had leased before the report came out,” says Ratchford. “Then they had a big golf ball in their throats saying, ‘I wish I hadn’t leased here.’ That’s the risk you run when you lease big tracts of land in a boom without having the luxury of doing the science first.”
“Some of those companies are going to make a lot of money,” notes Ratchford, “some are going to be doing tax write offs. That’s the nature of exploration. In a situation like this, where there’s a frenzy, there are going to be winners and losers.“
It’s too early to tell how much gas will ultimately be recoverable from the Fayetteville Shale. Southwestern Energy, still the largest lease holder in the play, estimates that they will recover 17 trillion cubic feet of gas.

The future looks good for the Fayetteville play. Ratchford expects the number of wells producing in the area to rise from the current 80 to a couple hundred and that gas will be extracted for at least 15 or 20 years.
He also notes that oilfield services provider Schlumberger has recently built a 30,000 square foot facility in Conway, Arkansas and will employ approximately 100 employees at that facility. “They would not do this if they didn’t believe this would be a long term venture,” says Ratchford.
Other areas that have generated interest for possible large shale gas plays are the Caney and Woodford formations in Oklahoma, the Floyd formation in the Black Warrior Basin of northwest Alabama, and the Barnett and Woodford formations in the Permian Basin of Texas.
It remains to be seen if the rising star of the Barnett Shale play will be eclipsed by other gas plays.
“The Barnett might be as good as it gets,” says Pollastro. “No one knows for sure.”
He produced the U.S. Geological Survey’s assessment of the Fort Worth Barnett shale play in 2003. At the time, he estimated that it held a remaining volume of 26 trillion cubic feet of recoverable unconventional gas. Now he’s evaluating the Barnett and Woodford formations in the Permian Basin, where drillers have experienced mixed results.
“It’s a different animal,” he says. “The Barnett in the Delaware Basin part of the Permian Basin is deeper and is more clay rich, so at present it’s not working like everybody thought it would. It’s not as rich in organic material as the Fort Worth Basin. I think there’s good potential, but I think there will be a steep learning curve.”
by Marc Airhart

Natural Gas, Marcellus Shale Play in Pennsylvania

The following article about a new natural gas exploration and production "play" in Pennsylvania and neighboring States, is a good example of how rising prices can increase the amount of oil and gas found and produced. Apparently there is a real boom going on. One of the reasons why producing gas from shale is economically attractive is because the layer of shale in the subsurface is often thick and widespread. This means it is easy to find. The rock also tends to be very impermeable and lacking in porosity (that is open space between rock particles).

Engineers have solved those problems primarily through the processes of "horizontal drilling" and "fracing" or fracturing the rock under ground by pumping fluid down the well bore and into the rock formation under high pressure. This is immediately followed with "sand" grains suspended in the fluid that goes into the induced fractures and keeps them open. This creates artificial porosity and permeability. It is an expensive and highly technical operation, but once perfected, as it seems to be, the results and the accompanying high value of the gas produced make it all worthwhile. This is a major development which can be very good for the area, and America's economy in general. It is a good time to be a working petroleum geologist and engineer.

Peter

source

April 8, 2008
There’s Gas in Those Hills
By CLIFFORD KRAUSS
HUGHESVILLE, Pa. — At first, Raymond Gregoire did not want to listen to the raspy voice on his answering machine offering him money for rights to drill on his land. They want to ruin my land, he thought. But he called back anyway a week later to hear more.
By the end of February, he had a contract in hand for $62,000, and he pulled together a group of 75 neighbors who signed $3 million in deals.

“It’s a modern-day gold rush in our own backyard,” Mr. Gregoire said.
Not just his backyard either — a frenzy unlike any seen in decades is unfolding here in rural Pennsylvania, and it eventually could encompass a huge chunk of the East, stretching from upstate New York to eastern Ohio and as far south as West Virginia. Companies are risking big money on a bet that this area could produce billions of dollars worth of natural gas.

A layer of rock here called the Marcellus Shale has been known for more than a century to contain gas, but it was generally not seen as economical to extract. Now, improved recovery technology, sharply higher natural gas prices and strong drilling results in a similar shale formation in north Texas are changing the calculus. A result is that a part of the country where energy supplies were long thought to be largely tapped out is suddenly ripe for gas prospecting.
Pennsylvania, where the Marcellus Shale appears to be thickest, is the heart of the action so far. Leasing agents from Texas and Oklahoma are knocking on doors, leaving voice mail messages and playing host at catered buffets to woo dairy farmers and retirees. They are rifling through stacks of dusty deeds in courthouse basements to see who has underground mineral rights to the deepest gas formations.

Thomas B. Murphy, a Pennsylvania State University educator who runs a program to instruct landowners on their rights, estimated that more than 20 oil and gas companies will invest $700 million this year developing the Marcellus Shale. Up to one half of that will be invested in Pennsylvania, he estimated.
The cost to companies for leasing mineral rights jumped from $300 an acre in mid-February to $2,100 now. “It shows you the pace this is going,” Mr. Murphy said. “I would call it breakneck.”
Dale A. Tice, a lawyer representing landowners in lease negotiations, said companies were on a “feeding frenzy.

A natural gas drilling site on a farm in Hickory, outside Pittsburgh, that seeks to extract gas from 600 feet below the surface.

Industry experts say in the last three years companies like Anadarko Petroleum, Chesapeake Energy and Cabot Oil and Gas have leased up to two million acres for drilling in the region, half of that in the last nine months.
Whether their bets will pay off is by no means a sure thing.
Researchers at Penn State and the State University of New York at Fredonia estimate that the Marcellus has 50 trillion cubic feet of recoverable natural gas, roughly twice the amount of natural gas consumed in the United States last year. But government estimates of the amount of gas recoverable from the Marcellus are relatively modest.
Early test results have encouraged companies to keep drilling, but most are holding details of their test wells close to the vest.

The company that has done the most work is Range Resources of Fort Worth, which says it plans to invest at least $426 million in the Appalachia region this year.
The company has reported promising results from the first 12 wells that it has drilled horizontally, the technique considered by most experts to be the most effective in the Marcellus. The most recent six have each produced more than three million cubic feet of production a day in recent months, and company executives say that is better than the average for wells recovering natural gas in the Barnett Shale in north Texas.

“The Marcellus is important to Range and it could be important to the country but it really is still early,” said Rodney L. Waller, a senior vice president at Range. “I can build you a scenario where it can be significantly better than the Barnett but it’s a function of economics.”
Energy experts say the Marcellus, along with other smaller shale formations being developed around the country, is coming under scrutiny at an opportune moment, just when conventional domestic natural gas production and imports from Canada are diminishing. With easy-to-find gas fields in decline, the country will need to explore in deeper waters in the Gulf of Mexico and penetrate deeper under the surface on land.

If all goes well, the Marcellus could help moderate the steep climb in natural gas prices and reduce possible future dependence on natural gas from the Middle East, which is beginning to arrive at coastal terminals in liquefied form.
Natural gas in the Marcellus and other shale formations is sometimes found as deep as 9,000 feet below the ground, a geological and engineering challenge not to be underestimated. The shales are sedimentary rock deposits formed from the mud of shallow seas several hundred million years ago. Gas can be found trapped within shale deposits, although it is too early to know exactly how much gas will be retrievable.

The gas from all the shales combined “is a game changer,” said Robert W. Esser, an oil and gas expert at Cambridge Energy Research Associates. He estimated that shale produced four billion cubic feet of gas a day on average last year, or about 7 percent of national production, and that shale gas production would increase to nine billion cubic feet a day by 2012, or about 15 percent of expected national production.
The New York State Energy Research and Development Authority estimates that developing New York’s portion of the Marcellus could roughly double the amount of natural gas now produced in New York. Currently that is about 55 billion cubic feet a year, providing for 5 percent of the state’s needs.

The Marcellus has suddenly become attractive in large part because natural gas prices have spiked in the last several years and the geologically similar Barnett Shale has been an industry sensation.
By using horizontal drilling techniques, oil and gas companies have been able to draw natural gas from underneath the city of Fort Worth, even from below schools, churches and airports. The companies have perfected hydraulic fracturing techniques, pumping water and sand into well bores to fracture shale and release gas from its pores.
Production in the Barnett has exploded from a trickle five years ago to over three billion cubic feet a day, and energy experts say that number could more than double by 2015. Shale gas development in other parts of Texas, Louisiana and Arkansas has also shown promise.
But no formation compares in size to the Marcellus. It is deeply entrenched in wooded and mountainous countryside and expensive to reach. But the reserve is also within short pipeline distance from some of the nation’s most energy-hungry cities.

Still, not everyone here is happy about all the leasing and drilling. At meetings with the companies, landowners have asked questions about potential hazards to water and woodlands.
Keith Eckel, 61, a grain farmer with 700 acres in northeastern Pennsylvania, said he had not decided whether to let the companies drill on his property. “Farmers have taken care of this land all their lives and don’t want to see it destroyed,” he said.
But many farmers and retirees in rural Pennsylvania appear excited that their lives are about to change.

“Now I can retire,” said Robert Deiseroth, a 63-year-old farmer and auctioneer from the town of Hickory, who recently received a $16,000 royalty check from Range Resources that he hopes will be repeated month after month. “This was a godsend for me. If it weren’t for this I would have to sell off some of my land to get some money for retirement.”
Mr. Deiseroth has put new windows in his house, bought a new fishing boat and plans to build a new garage. His 89-year-old father and 90-year-old mother, who live nearby, just got a $20,000 monthly check. His father has replaced the golf cart he drove around his farm with a Kubota utility vehicle, while his mother has bought a flat-screen television.
“When Range came in a lot of people didn’t like it,” Mr. Deiseroth said, “But things changed when they started getting their checks.”