This is good news for producers in the Haynesville Shale Play in NW Louisiana and East Texas. It is good to hear someone is spending and investing.
Peter
Friday, February 27, 2009, 10:08am CST
Regency Energy lines up financing for Haynesville expansion
Dallas Business Journal
Natural gas pipeline company Regency Energy Partners has entered into a joint venture to finance the construction of Regency’s Haynesville Shale pipeline project, a pipeline expansion initiative that will transport gas out of the gas-rich Haynesville Shale in Northern Louisiana.
GE Energy Financial Services, and Alinda Capital Partners LLC are financing the deal in a joint venture arrangement with Regency.
As part of the joint venture, Regency (Nasdaq: RGNC) brings its $400 million Regency Intrastate Gas System to the table, while GE Energy Financial Services and Alinda Capital Partners LLC have agreed to contribute $126.5 million and $526.5 million, respectively, in cash towards the venture in exchange for a 12 percent and 50 percent interest in the general partnership established with Regency.
Regency will receive a cash payment covering the entire cost of the expansion project. The cash payment also provides Regency with a level of financing that enables the expansion project to move forward, while allowing Regency to continue to finance its current distribution levels.
Thus far, Regency says shippers wanting to utilize the pipeline’s capacity have already committed to using up to 84 percent of the pipeline’s capacity. The expansion is projected to double Regency’s pipeline in North Louisiana. The project should be in service by the end of this year.
The joint-venture between the companies is expected to close by April 30.
Friday, February 27, 2009
Sunday, February 22, 2009
Shale Gas Production Methods To Be Used Overseas
Why not take the technology mastered in the United States in the Barnett Shale, Haynesville Shale, Fayeteville Shale, Marcellus Shale, Bakken Formation, etc. and use it in shale formations containing gas in other parts of the world? It makes perfect sense and it is bound to happen. American companies with this expertise should position themselves to take advantage of this opportunity.
Peter
American drilling techniques may migrate overseas
By MARK WILLIAMS AP Energy Writer (source)
With one eye cast toward home, giant European energy companies are investing billions in U.S. natural gas and oil fields where huge, hard-to-get reserves have been unlocked with new drilling technology.
That technology is the prize in Europe, where gas production has declined and where an international utility dispute recently left people in more than a dozen European countries shivering in unheated homes.
Europe's natural gas supply is routed through Ukraine from Russia. Russia supplies about one-quarter of the EU's natural gas, with 80 percent of it shipped through Ukraine. A rift between the two nations left more than a dozen European countries with little or no gas for two weeks last month.
Declines in European gas production has potentially made the new techniques used in the U.S. even more pivotal.
At least three European oil and gas giants are developing or have bought interests in oil and gas shale projects in the U.S. - Norwegian oil company StatoilHydro, the U.S. unit of British oil company BP Plc and French company Total.
StatoilHydro and BP have agreed in recent months to pay billions of dollars for stakes in shale gas projects from the top U.S. producer of gas, Chesapeake Energy. Total has bought a 50 percent stake in a U.S. company exploring for oil shale in the Rocky Mountains.
"Given the magnitude of oil shale resources we believe that this project has an important long-term potential for global energy markets," Yves-Louis Darricarrere, Total's exploration and production president, said in announcing Total's deal with American Shale Oil.
Shale is a kind of layered, sedimentary rock that exists in formations throughout the world. In the U.S., gas production from shale dates back to the 1800s.
But the gas, tightly locked in rock formations, had been extraordinarily expensive to extract. That began to change about 15 years ago as producers developed new techniques such as horizontal drilling, where the drill is turned in a right angle to bore into a gas reservoir horizontally.
Gas from shale now amounts to about 5 percent of total U.S. production, according to the Gas Technology Institute.
If the same technology works in Europe it could free up an enormous amount of energy, and potentially provide a buffer against cross-border disputes to the east.
StatoilHydro bought into Chesapeake Energy's massive Appalachian Marcellus shale project for $3.37 billion in November. Executive Vice President Rune Bjornson said at an energy conference this month in Houston that StatoilHydro wants to bring new drilling technology to other regions of the world.
If the race to duplicate drilling success in the U.S. is on, few companies are talking about it.
Even Aubrey McClendon, co-founder and chief executive of Chesapeake, the largest natural gas producer in the U.S., said, "I doubt we will trumpet it as I think the combination of their international stature and presence and our knowledge of gas shale would do nothing but attract competition."
But it has become abundantly clear since a chilly two weeks in January that Europe's energy security has been diminished since the break up of the Soviet Union.
Buying into the technology in the U.S. makes sense and could spare European companies years of development, said Don Hertzmark, an international energy expert.
"The Europeans never bothered to develop this stuff," he said.
U.S. companies stand to expand through new markets in Europe if the new techniques work, and many experts believe that they will.
Energy companies are now funding a six-year study to locate gas deposits in Europe and to determine if they can be exploited.
"The companies that are involved here - they're not beginners," said Brian Horsfield of the GFZ German Research Center, which is heading the study. "It could come online within three years if it turns out these gas shales really are as prolific as we're led to believe."
Horsfield, a professor of organic geochemistry, said companies already have acquired land rights throughout Europe.
"The shale gas, if it were to be economic here, is very close to the user," Horsfield said. "That's one of the selling points, certainly, of our project on a nonscientific basis. And the events of the last month or so have helped to stress that."
European Commission President Jose Manuel Barroso said after the dispute between Russia and Ukraine was settled (the second dispute in recent years) that Europe must diversify its energy sources and supply route.
"It was utterly unacceptable that European gas consumers were held hostage to this dispute between Russia and Ukraine," he said.
Associated Press writers Patrick McGroarty in Berlin and Greg Keller in Paris contributed to this story.
Peter
American drilling techniques may migrate overseas
By MARK WILLIAMS AP Energy Writer (source)
With one eye cast toward home, giant European energy companies are investing billions in U.S. natural gas and oil fields where huge, hard-to-get reserves have been unlocked with new drilling technology.
That technology is the prize in Europe, where gas production has declined and where an international utility dispute recently left people in more than a dozen European countries shivering in unheated homes.
Europe's natural gas supply is routed through Ukraine from Russia. Russia supplies about one-quarter of the EU's natural gas, with 80 percent of it shipped through Ukraine. A rift between the two nations left more than a dozen European countries with little or no gas for two weeks last month.
Declines in European gas production has potentially made the new techniques used in the U.S. even more pivotal.
At least three European oil and gas giants are developing or have bought interests in oil and gas shale projects in the U.S. - Norwegian oil company StatoilHydro, the U.S. unit of British oil company BP Plc and French company Total.
StatoilHydro and BP have agreed in recent months to pay billions of dollars for stakes in shale gas projects from the top U.S. producer of gas, Chesapeake Energy. Total has bought a 50 percent stake in a U.S. company exploring for oil shale in the Rocky Mountains.
"Given the magnitude of oil shale resources we believe that this project has an important long-term potential for global energy markets," Yves-Louis Darricarrere, Total's exploration and production president, said in announcing Total's deal with American Shale Oil.
Shale is a kind of layered, sedimentary rock that exists in formations throughout the world. In the U.S., gas production from shale dates back to the 1800s.
But the gas, tightly locked in rock formations, had been extraordinarily expensive to extract. That began to change about 15 years ago as producers developed new techniques such as horizontal drilling, where the drill is turned in a right angle to bore into a gas reservoir horizontally.
Gas from shale now amounts to about 5 percent of total U.S. production, according to the Gas Technology Institute.
If the same technology works in Europe it could free up an enormous amount of energy, and potentially provide a buffer against cross-border disputes to the east.
StatoilHydro bought into Chesapeake Energy's massive Appalachian Marcellus shale project for $3.37 billion in November. Executive Vice President Rune Bjornson said at an energy conference this month in Houston that StatoilHydro wants to bring new drilling technology to other regions of the world.
If the race to duplicate drilling success in the U.S. is on, few companies are talking about it.
Even Aubrey McClendon, co-founder and chief executive of Chesapeake, the largest natural gas producer in the U.S., said, "I doubt we will trumpet it as I think the combination of their international stature and presence and our knowledge of gas shale would do nothing but attract competition."
But it has become abundantly clear since a chilly two weeks in January that Europe's energy security has been diminished since the break up of the Soviet Union.
Buying into the technology in the U.S. makes sense and could spare European companies years of development, said Don Hertzmark, an international energy expert.
"The Europeans never bothered to develop this stuff," he said.
U.S. companies stand to expand through new markets in Europe if the new techniques work, and many experts believe that they will.
Energy companies are now funding a six-year study to locate gas deposits in Europe and to determine if they can be exploited.
"The companies that are involved here - they're not beginners," said Brian Horsfield of the GFZ German Research Center, which is heading the study. "It could come online within three years if it turns out these gas shales really are as prolific as we're led to believe."
Horsfield, a professor of organic geochemistry, said companies already have acquired land rights throughout Europe.
"The shale gas, if it were to be economic here, is very close to the user," Horsfield said. "That's one of the selling points, certainly, of our project on a nonscientific basis. And the events of the last month or so have helped to stress that."
European Commission President Jose Manuel Barroso said after the dispute between Russia and Ukraine was settled (the second dispute in recent years) that Europe must diversify its energy sources and supply route.
"It was utterly unacceptable that European gas consumers were held hostage to this dispute between Russia and Ukraine," he said.
Associated Press writers Patrick McGroarty in Berlin and Greg Keller in Paris contributed to this story.
Saturday, February 21, 2009
An Excellent Summary Of Unconventional Gas (and oil) Plays In The US
The following is a well-written and fairly detailed summary of the status of so-called unconventional shale gas, (and some oil) plays taking place in the United States as of August, 2008. It seems the economic benefits of this activity is going relatively unnoticed, compared to all the emphasis on "green" energy. Green meaning solar, wind and geothermal energy. It does make one wonder who is controlling or influencing what the mainstream media reports.
Note, one of the keys to the success of these new plays is horizontal drilling, and of course, the interpretation of these horizontal wells. This kind of interpretation presents a totally new challenge to geologists and engineers, something that can not be taken lightly.
Peter
ARCHIVE August 2008
Vol. 229 No. 8
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 (source)
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.
Note, one of the keys to the success of these new plays is horizontal drilling, and of course, the interpretation of these horizontal wells. This kind of interpretation presents a totally new challenge to geologists and engineers, something that can not be taken lightly.
Peter
ARCHIVE August 2008
Vol. 229 No. 8
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 (source)
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). 1Chesapeake 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. 16The 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.
Friday, February 20, 2009
Petrohawk: A Very Successful Producer In Shale Gas Plays
Consider the following facts and figures. The numbers of wells drilled, their success rate, and production rates all demonstrate a very skilled operation. The follwing comes from Petrohawk's own website here.
Peter
Petrohawk Provides Fourth Quarter Operational Update (2008)
Final Proved Reserves up 34% Year Over Year at 1.42 Tcfe, 419% of Production Replaced Haynesville Shale Gross Operated Production Reaches 160 Mmcfe/d
HOUSTON, Feb. 3 /PRNewswire-FirstCall/ -- Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK) provided its fourth quarter 2008 operational update, including additional drilling results in the Haynesville Shale and proved reserves for year-end 2008.
During the fourth quarter, Petrohawk drilled 218 wells, with a success rate of 98%. On average, 32 operated rigs and 15 non-operated rigs were running during the quarter, including a combination of spudder rigs and horizontal rigs in both the Haynesville Shale and Fayetteville Shale development programs. For 2008, Petrohawk drilled 739 total wells, also with a success rate of 98%.
Production for the fourth quarter was approximately 361 million cubic feet of natural gas equivalent (Mmcfe/d), a 15% quarter over quarter increase and a 52% increase over fourth quarter 2007, on a pro forma basis. Petrohawk exited the quarter producing approximately 400 Mmcfe/d. Full year 2008 production was approximately 305 Mmcfe/d.
strong>Haynesville Shale
Petrohawk recently placed four additional wells online utilizing production practices consistent with previously reported wells. The initial production rates of these wells averaged 17.7 Mmcfe/d, detailed as follows:
The Mack Hogan #4 (Bossier Parish, Section 3, 16N, 11W) had an initial production rate of 13.4 Mmcfe/d on a 24/64" choke with 6,350# flowing casing pressure.
The Osborne 8 #3H (Bossier Parish, Section 8, 16N, 11W) had an initial production rate of 18.8 Mmcfe/d on a 24/64" choke with 6,800# flowing casing pressure.
The Roos "A" #5 (Bossier Parish, Section 3, 16N, 11W) had an initial production rate of 15.1 Mmcfe/d on a 24/64" choke with 6,100# flowing casing pressure.
The Griffith 11 #1 (DeSoto Parish, Section 11, 13N, 14W) had an initial production rate of 23.3 Mmcfe/d on a 28/64" choke with 7,550# flowing casing pressure. This well is a significant step-out to the southwest from existing completions.
Two Haynesville Shale completions, the Sample 4 #1 and the R.E. Smith Jr. 32 #1, experienced mechanical problems that resulted in lower than expected initial production rates. On the Sample 4 #1, a valve malfunctioned following completion, causing casing damage in the lateral portion of the well. The Company elected to produce the well on a 12/64" choke as a precaution against further wellbore damage. This well had an initial production rate of 5.4 Mmcfe/d with 7,020# flowing casing pressure. The R.E. Smith Jr. 32 #1 screened out halfway through completion due to the inadvertent firing of a perforating gun in the curve of the lateral. With only six stages of fracture stimulation, this well had an initial production rate of 11.1 Mmcfe/d on a 20/64" choke with 5,900# flowing casing pressure.
The Company is currently producing approximately 160 Mmcfe/d gross from the Haynesville Shale with 16 operated wells on production. Eleven operated wells have been on production 30 days or more, averaging 15.2 Mmcfe/d over their first 30 days of production. Eight operated wells have been on production 60 days or more, averaging 13.2 Mmcfe/d over their first 60 days of production. The four wells on production greater than 90 days have averaged 8.8 Mmcfe/d over their first 90 days of production. All operated wells to date have been produced utilizing similar production practices. During 2009, Petrohawk will conduct a pilot program on certain wells whereby production practices will be altered to restrict production by utilizing smaller choke sizes. The Company will monitor this subset of wells for effects on decline rate and mechanical operation.
Petrohawk's current drilling and completion methodology focuses on completing wells with longer laterals and maximizing the number of frac stages, spaced approximately 325 feet apart. The objective of this technique is to minimize the total number of wells required to effectively drain the reservoir, resulting in lower overall development costs. The Company is currently targeting lateral lengths between 4,300' and 4,600' with up to 15 frac stages. Petrohawk's first four completions averaged 3,339' in lateral length with 10 frac stages while the last twelve completions have averaged 3,958' in lateral length and 12 stages (with the exception of the R.E. Smith Jr 32 #3, which had down hole mechanical issues and only six frac stages).
During 2008, the Company utilized a "pre-drill" program whereby smaller, "spudder" rigs drilled the vertical portion of the wellbore in advance of horizontal rigs moving in to drill the lateral. At year end 2008, Petrohawk had eleven operated horizontal rigs running in the Haynesville Shale. The Company expects spud-to-first sales to average approximately 75 days during 2009, assuming longer laterals are drilled.
Petrohawk has budgeted $690 million for Haynesville Shale drilling in 2009. Seventy-five to eighty gross operated wells are budgeted, with approximately 6 wells expected to be completed per month. The Company expects to operate an average of 12 rigs in the play in 2009 with an emphasis on holding operated acreage.
Eagle Ford Shale
A second well in Petrohawk's Eagle Ford Shale discovery in South Texas, formally known as Hawkville Field, was completed in mid-January. The Dora Martin #1H, located approximately 14 miles west of the Company's first Eagle Ford Shale well, tested at a rate of 8.3 Mmcfe/d on a 22/64" choke with 4,610# flowing casing pressure. The well was drilled to a true vertical depth of approximately 11,000' and had a lateral length of 4,300' with 12 stages of fracture stimulation. The Company has also reached total depth on its third well, the Donnell #1H. Completion is scheduled for mid-February. Petrohawk is currently running one rig in the play with drilling and completion expected to average 50 days.
Fayetteville Shale
During the fourth quarter, Petrohawk drilled 44 operated and 74 non-operated wells in the Fayetteville Shale. Of 143 horizontal wells drilled during 2008, 113 had state test data available at December 31, 12 were waiting on state tests to be performed, and 18 were waiting on completion due to the delayed in-operation date of the Boardwalk pipeline. Current gross operated production in the Fayetteville Shale reached approximately 145 Mmcfe/d as of December 31, 2008.
Throughout 2008, the Company experienced significant operational improvements in the results of its completions, primarily as a result of drilling longer laterals with cemented liners. This supported by the following data comparing first quarter 2008 and fourth quarter 2008 techniques and results as follows:
Percentage of cemented liners increased from 4% in the first quarter to 100% in the fourth quarter.
Average lateral length increased from 2,286' in the first quarter to 2,655' in the fourth quarter, a 16% increase.
Average number of frac stages increased from 6.0 in the first quarter to 7.6 in the fourth quarter, a 27% increase.
Average state initial production test rate increased from 1.919 Mmcfe/d in the first quarter to 2.456 in Mmcfe/d in the fourth quarter, a 28% increase.
Percentage of completions that tested greater than 3 Mmcfe/d increased from 12% in the first quarter to 54% in the fourth quarter, with 2 wells in the second half of 2008 testing greater than 5 Mmcfe/d.
Price realizations and overall production from the Fayetteville Shale were impacted in the fourth quarter by a delay in the completion of a new third-party pipeline, which increased demand on other transportation lines servicing the play, causing wider than normal basis differentials. Production was either sold at lower than normal prices or shut in at various times during the quarter as a result of these market conditions. The new pipeline, constructed by Boardwalk Pipeline Partners LP, is currently in service and the Company currently expects no additional transportation constraints on its production in the area.
New Gathering Subsidiary - Hawk Field Services, LLC
During 2008, Petrohawk initiated construction of its own gathering systems servicing the Company's as well as third party production in the Fayetteville Shale and Haynesville Shale. Operating under a new subsidiary, Hawk Field Services, LLC, Petrohawk constructed approximately 100 miles of gathering lines in the Fayetteville Shale in 2008, with approximately 150 miles of gathering lines currently in service, under construction or planned in the Haynesville Shale during 2009.
Petrohawk Fourth Quarter and Full Year 2008 Earnings Conference Call
Petrohawk has scheduled a conference call for Wednesday, February 25, 2009 at 9:30 a.m. CDT (10:30 a.m. EDT) to discuss fourth quarter and full year 2008 financial and operating results. To access, dial 800-644-8607 five to ten minutes before the call begins. Please reference Petrohawk Energy Conference ID 81822729. International callers may also participate by dialing 706-679-8184. A replay of the call will be available approximately two hours after the live broadcast ends and will be accessible until March 11, 2009. To access the replay, please dial 800-642-1687 and reference conference ID 81822729. International callers may listen to a playback by dialing 706-645-9291. In addition, the call will be webcast live on Petrohawk's website at http://www.petrohawk.com/. A replay of the call will be available at that site through March 11, 2008.
Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of natural gas and oil with properties concentrated in North Louisiana, Arkansas, East Texas, Oklahoma and the Permian basin.
For more information contact Joan Dunlap, Vice President - Investor Relations, at 832-204-2737 or jdunlap@petrohawk.com. For additional information about Petrohawk, please visit our website at http://www.petrohawk.com/.
Peter
Petrohawk Provides Fourth Quarter Operational Update (2008)
Final Proved Reserves up 34% Year Over Year at 1.42 Tcfe, 419% of Production Replaced Haynesville Shale Gross Operated Production Reaches 160 Mmcfe/d
HOUSTON, Feb. 3 /PRNewswire-FirstCall/ -- Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK) provided its fourth quarter 2008 operational update, including additional drilling results in the Haynesville Shale and proved reserves for year-end 2008.
During the fourth quarter, Petrohawk drilled 218 wells, with a success rate of 98%. On average, 32 operated rigs and 15 non-operated rigs were running during the quarter, including a combination of spudder rigs and horizontal rigs in both the Haynesville Shale and Fayetteville Shale development programs. For 2008, Petrohawk drilled 739 total wells, also with a success rate of 98%.
Production for the fourth quarter was approximately 361 million cubic feet of natural gas equivalent (Mmcfe/d), a 15% quarter over quarter increase and a 52% increase over fourth quarter 2007, on a pro forma basis. Petrohawk exited the quarter producing approximately 400 Mmcfe/d. Full year 2008 production was approximately 305 Mmcfe/d.
strong>Haynesville Shale
Petrohawk recently placed four additional wells online utilizing production practices consistent with previously reported wells. The initial production rates of these wells averaged 17.7 Mmcfe/d, detailed as follows:
The Mack Hogan #4 (Bossier Parish, Section 3, 16N, 11W) had an initial production rate of 13.4 Mmcfe/d on a 24/64" choke with 6,350# flowing casing pressure.
The Osborne 8 #3H (Bossier Parish, Section 8, 16N, 11W) had an initial production rate of 18.8 Mmcfe/d on a 24/64" choke with 6,800# flowing casing pressure.
The Roos "A" #5 (Bossier Parish, Section 3, 16N, 11W) had an initial production rate of 15.1 Mmcfe/d on a 24/64" choke with 6,100# flowing casing pressure.
The Griffith 11 #1 (DeSoto Parish, Section 11, 13N, 14W) had an initial production rate of 23.3 Mmcfe/d on a 28/64" choke with 7,550# flowing casing pressure. This well is a significant step-out to the southwest from existing completions.
Two Haynesville Shale completions, the Sample 4 #1 and the R.E. Smith Jr. 32 #1, experienced mechanical problems that resulted in lower than expected initial production rates. On the Sample 4 #1, a valve malfunctioned following completion, causing casing damage in the lateral portion of the well. The Company elected to produce the well on a 12/64" choke as a precaution against further wellbore damage. This well had an initial production rate of 5.4 Mmcfe/d with 7,020# flowing casing pressure. The R.E. Smith Jr. 32 #1 screened out halfway through completion due to the inadvertent firing of a perforating gun in the curve of the lateral. With only six stages of fracture stimulation, this well had an initial production rate of 11.1 Mmcfe/d on a 20/64" choke with 5,900# flowing casing pressure.
The Company is currently producing approximately 160 Mmcfe/d gross from the Haynesville Shale with 16 operated wells on production. Eleven operated wells have been on production 30 days or more, averaging 15.2 Mmcfe/d over their first 30 days of production. Eight operated wells have been on production 60 days or more, averaging 13.2 Mmcfe/d over their first 60 days of production. The four wells on production greater than 90 days have averaged 8.8 Mmcfe/d over their first 90 days of production. All operated wells to date have been produced utilizing similar production practices. During 2009, Petrohawk will conduct a pilot program on certain wells whereby production practices will be altered to restrict production by utilizing smaller choke sizes. The Company will monitor this subset of wells for effects on decline rate and mechanical operation.
Petrohawk's current drilling and completion methodology focuses on completing wells with longer laterals and maximizing the number of frac stages, spaced approximately 325 feet apart. The objective of this technique is to minimize the total number of wells required to effectively drain the reservoir, resulting in lower overall development costs. The Company is currently targeting lateral lengths between 4,300' and 4,600' with up to 15 frac stages. Petrohawk's first four completions averaged 3,339' in lateral length with 10 frac stages while the last twelve completions have averaged 3,958' in lateral length and 12 stages (with the exception of the R.E. Smith Jr 32 #3, which had down hole mechanical issues and only six frac stages).
During 2008, the Company utilized a "pre-drill" program whereby smaller, "spudder" rigs drilled the vertical portion of the wellbore in advance of horizontal rigs moving in to drill the lateral. At year end 2008, Petrohawk had eleven operated horizontal rigs running in the Haynesville Shale. The Company expects spud-to-first sales to average approximately 75 days during 2009, assuming longer laterals are drilled.
Petrohawk has budgeted $690 million for Haynesville Shale drilling in 2009. Seventy-five to eighty gross operated wells are budgeted, with approximately 6 wells expected to be completed per month. The Company expects to operate an average of 12 rigs in the play in 2009 with an emphasis on holding operated acreage.
Eagle Ford Shale
A second well in Petrohawk's Eagle Ford Shale discovery in South Texas, formally known as Hawkville Field, was completed in mid-January. The Dora Martin #1H, located approximately 14 miles west of the Company's first Eagle Ford Shale well, tested at a rate of 8.3 Mmcfe/d on a 22/64" choke with 4,610# flowing casing pressure. The well was drilled to a true vertical depth of approximately 11,000' and had a lateral length of 4,300' with 12 stages of fracture stimulation. The Company has also reached total depth on its third well, the Donnell #1H. Completion is scheduled for mid-February. Petrohawk is currently running one rig in the play with drilling and completion expected to average 50 days.
Fayetteville Shale
During the fourth quarter, Petrohawk drilled 44 operated and 74 non-operated wells in the Fayetteville Shale. Of 143 horizontal wells drilled during 2008, 113 had state test data available at December 31, 12 were waiting on state tests to be performed, and 18 were waiting on completion due to the delayed in-operation date of the Boardwalk pipeline. Current gross operated production in the Fayetteville Shale reached approximately 145 Mmcfe/d as of December 31, 2008.
Throughout 2008, the Company experienced significant operational improvements in the results of its completions, primarily as a result of drilling longer laterals with cemented liners. This supported by the following data comparing first quarter 2008 and fourth quarter 2008 techniques and results as follows:
Percentage of cemented liners increased from 4% in the first quarter to 100% in the fourth quarter.
Average lateral length increased from 2,286' in the first quarter to 2,655' in the fourth quarter, a 16% increase.
Average number of frac stages increased from 6.0 in the first quarter to 7.6 in the fourth quarter, a 27% increase.
Average state initial production test rate increased from 1.919 Mmcfe/d in the first quarter to 2.456 in Mmcfe/d in the fourth quarter, a 28% increase.
Percentage of completions that tested greater than 3 Mmcfe/d increased from 12% in the first quarter to 54% in the fourth quarter, with 2 wells in the second half of 2008 testing greater than 5 Mmcfe/d.
Price realizations and overall production from the Fayetteville Shale were impacted in the fourth quarter by a delay in the completion of a new third-party pipeline, which increased demand on other transportation lines servicing the play, causing wider than normal basis differentials. Production was either sold at lower than normal prices or shut in at various times during the quarter as a result of these market conditions. The new pipeline, constructed by Boardwalk Pipeline Partners LP, is currently in service and the Company currently expects no additional transportation constraints on its production in the area.
New Gathering Subsidiary - Hawk Field Services, LLC
During 2008, Petrohawk initiated construction of its own gathering systems servicing the Company's as well as third party production in the Fayetteville Shale and Haynesville Shale. Operating under a new subsidiary, Hawk Field Services, LLC, Petrohawk constructed approximately 100 miles of gathering lines in the Fayetteville Shale in 2008, with approximately 150 miles of gathering lines currently in service, under construction or planned in the Haynesville Shale during 2009.
Petrohawk Fourth Quarter and Full Year 2008 Earnings Conference Call
Petrohawk has scheduled a conference call for Wednesday, February 25, 2009 at 9:30 a.m. CDT (10:30 a.m. EDT) to discuss fourth quarter and full year 2008 financial and operating results. To access, dial 800-644-8607 five to ten minutes before the call begins. Please reference Petrohawk Energy Conference ID 81822729. International callers may also participate by dialing 706-679-8184. A replay of the call will be available approximately two hours after the live broadcast ends and will be accessible until March 11, 2009. To access the replay, please dial 800-642-1687 and reference conference ID 81822729. International callers may listen to a playback by dialing 706-645-9291. In addition, the call will be webcast live on Petrohawk's website at http://www.petrohawk.com/. A replay of the call will be available at that site through March 11, 2008.
Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of natural gas and oil with properties concentrated in North Louisiana, Arkansas, East Texas, Oklahoma and the Permian basin.
For more information contact Joan Dunlap, Vice President - Investor Relations, at 832-204-2737 or jdunlap@petrohawk.com. For additional information about Petrohawk, please visit our website at http://www.petrohawk.com/.
Some Incredible Gas Wells In The Haynesville Shale
Undoubtedly these are horizontal wells by Petrohawk. It is easy to understand the excitement over the potential of the Haynesville Shale Gas Play.
Peter
Petrohawk Announces Three New Haynesville Shale Wells Placed on Production at a Combined Rate of 73 Mmcfe/d
HOUSTON, Dec. 9 /PRNewswire-FirstCall/ -- Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK) has placed three additional Haynesville Shale wells on production at a combined rate of 73 Mmcfe/d, one with the highest reported initial production rate of any well in Petrohawk's history, as follows:
--The Brown 17 #4 (69% W.I.), located in Section 17-T16N-R11W, Bossier Parish, Louisiana, was completed on November 18 and produced at a rate of 23.4 Mmcfe/d on a 26/64" choke with 7,700# flowing casing pressure.
--The Goodwin 9 #5 (97% W.I.), located in Section 9-T16N-R11W, Bossier Parish, Louisiana, was completed on November 25 and produced at a rate of 21.1 Mmcfe/d on a 26/64" choke with 6,750# flowing casing pressure.
--The Sample 9 #1 (100% W.I.) is located in Section 9-T14N-R11W, Red River Parish, Louisiana, approximately 12 miles south of Elm Grove Field. It was completed on November 27 and produced at a rate of 28.2 Mmcfe/d on a 30/64" choke with 7,100# flowing casing pressure.
The Company expects to complete five additional Haynesville Shale wells by the end of the year.
Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of natural gas and oil with properties concentrated in Northwest Louisiana and East Texas (Haynesville / Bossier Shale and Cotton Valley), Arkansas (Fayetteville Shale), South Texas (Eagle Ford Shale), Oklahoma and the Permian basin.
For more information contact Joan Dunlap, Vice President - Investor Relations, at 832-204-2737 or jdunlap@petrohawk.com. For additional information about Petrohawk, please visit our website at http://www.petrohawk.com/.
Peter
Petrohawk Announces Three New Haynesville Shale Wells Placed on Production at a Combined Rate of 73 Mmcfe/d
HOUSTON, Dec. 9 /PRNewswire-FirstCall/ -- Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK) has placed three additional Haynesville Shale wells on production at a combined rate of 73 Mmcfe/d, one with the highest reported initial production rate of any well in Petrohawk's history, as follows:
--The Brown 17 #4 (69% W.I.), located in Section 17-T16N-R11W, Bossier Parish, Louisiana, was completed on November 18 and produced at a rate of 23.4 Mmcfe/d on a 26/64" choke with 7,700# flowing casing pressure.
--The Goodwin 9 #5 (97% W.I.), located in Section 9-T16N-R11W, Bossier Parish, Louisiana, was completed on November 25 and produced at a rate of 21.1 Mmcfe/d on a 26/64" choke with 6,750# flowing casing pressure.
--The Sample 9 #1 (100% W.I.) is located in Section 9-T14N-R11W, Red River Parish, Louisiana, approximately 12 miles south of Elm Grove Field. It was completed on November 27 and produced at a rate of 28.2 Mmcfe/d on a 30/64" choke with 7,100# flowing casing pressure.
The Company expects to complete five additional Haynesville Shale wells by the end of the year.
Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of natural gas and oil with properties concentrated in Northwest Louisiana and East Texas (Haynesville / Bossier Shale and Cotton Valley), Arkansas (Fayetteville Shale), South Texas (Eagle Ford Shale), Oklahoma and the Permian basin.
For more information contact Joan Dunlap, Vice President - Investor Relations, at 832-204-2737 or jdunlap@petrohawk.com. For additional information about Petrohawk, please visit our website at http://www.petrohawk.com/.
Wednesday, February 18, 2009
Another Very Long Horizontal Well
Apparently this is well in the North Sea holds the previous record for the longest well drilled. It is impressive by any standards. I wonder who and how the interpretation of where
Peter
Gulltopp is world record well
By Billy Youngson Filed from Aberdeen 4/14/2008 5:02:05 PM GMT (source)
NORWAY: StatoilHydro has successfully completed the most complicated well in the company's history, and has set a record for the longest producing well in the world drilled from an offshore platform.
At almost 10 kilometres (6.2 miles) long and almost completely horizontal, the Gulltopp well on the Gullfaks field has seen hydrocarbons flowing up through the well at 9,910 metres (32,513 ft).
StatoilHydro Head of Operations West Arne Sigve Nylund said, "This is a day of rejoicing both for Gullfaks and StatoilHydro. We were aware of the risk that Gulltopp drilling from the platform might fail. This makes it extra great that we today have successfully completed the company's most demanding drilling operation."
The experience gained by StatoilHydro is very valuable to the further development of both remote prospects at Gullfaks and on other fields in the company's portfolio.
"The increased range that we now envisage for platform drilling opens up new perspectives for effective exploitation of existing infrastructure, and thus increased producing life," Nylund says.
Gulltopp will, together with other prospects in the area, secure continued Gullfaks operations towards 2030. An extensive plan for how to extend the life of the field, which came on stream back in 1986, has been developed.
The 10 kilometre (6.2 mile) drill pipe was controlled from the drilling rig at the sea surface. It was run 150 metres (492 ft) down to the seabed, and then kilometre after kilometre through various types of rock strata.
The longer the drill pipe is, the more difficult it is to control the forces that are transferred to the drill bit down in the deep, thousands of metres away. This requires great attention and skills by personnel in charge of drilling.
"The Gulltopp well has been a great technological challenge, and was possible thanks to high professional skills among our own drilling and well personnel, in addition to crucial contribution by the involved suppliers," said Geir Slora, head of drilling and wells in StatoilHydro.
Peter
Gulltopp is world record well
By Billy Youngson Filed from Aberdeen 4/14/2008 5:02:05 PM GMT (source)
NORWAY: StatoilHydro has successfully completed the most complicated well in the company's history, and has set a record for the longest producing well in the world drilled from an offshore platform.
At almost 10 kilometres (6.2 miles) long and almost completely horizontal, the Gulltopp well on the Gullfaks field has seen hydrocarbons flowing up through the well at 9,910 metres (32,513 ft).
StatoilHydro Head of Operations West Arne Sigve Nylund said, "This is a day of rejoicing both for Gullfaks and StatoilHydro. We were aware of the risk that Gulltopp drilling from the platform might fail. This makes it extra great that we today have successfully completed the company's most demanding drilling operation."
The experience gained by StatoilHydro is very valuable to the further development of both remote prospects at Gullfaks and on other fields in the company's portfolio.
"The increased range that we now envisage for platform drilling opens up new perspectives for effective exploitation of existing infrastructure, and thus increased producing life," Nylund says.
Gulltopp will, together with other prospects in the area, secure continued Gullfaks operations towards 2030. An extensive plan for how to extend the life of the field, which came on stream back in 1986, has been developed.
The 10 kilometre (6.2 mile) drill pipe was controlled from the drilling rig at the sea surface. It was run 150 metres (492 ft) down to the seabed, and then kilometre after kilometre through various types of rock strata.
The longer the drill pipe is, the more difficult it is to control the forces that are transferred to the drill bit down in the deep, thousands of metres away. This requires great attention and skills by personnel in charge of drilling.
"The Gulltopp well has been a great technological challenge, and was possible thanks to high professional skills among our own drilling and well personnel, in addition to crucial contribution by the involved suppliers," said Geir Slora, head of drilling and wells in StatoilHydro.
New Horizontal Drilling Record: 35,770 Feet!
Imagine logging, interpreting, setting casing, perforating, and fracing a horizontal section of a well 35,770 long? Amazing.
Peter
Transocean rig breaks world drilling record
Filed from Houston 5/21/2008 1:51:37 PM GMT (source)
QATAR: Offshore drilling contractor Transocean is claiming a new world record for the longest extended-reach well ever drilled. Transocean jackup GSF Rig 127 set the record, drilling Well BD-04A in the Al-Shaheen field offshore Qatar to a depth of 40,320 feet (12,289 m) with a 35,770-foot (10,902-m) horizontal section.
The well is the first offshore well to exceed 40,000 feet (12,191 m) and breaks the previous extended-reach record holder, ExxonMobil's Sakhalin-1 well in Russia's Chayo field, by 2,000 feet (6,096 m).
During the 36 incident-free days of drilling, the crew members on GSF Rig 127 overcame high drilling torque through the horizontal section, and used deck-management planning and a supply boat to hold additional drill pipe, allowing the rig to stay within its variable deck load rating.
GSF Rig 127 is a Friede & Goldman L-780 Mod II design jackup, with 250-foot (76.2-m) water depth capability and operates with two Emsco FB 1600 Mud pumps. Other equipment includes a 2000-horsepower National 1320 UE Drawworks, and a Varco TDS-4S Top Drive.
Transocean Egypt and Middle East Division Manager Gary Bauer lauded the crew of the rig. "It goes without saying that your accomplishment truly epitomizes and embraces Transocean's vision statement where Rig 127 has a group of highly motivated people dedicated to achieving operational excellence in an incident-free environment and being recognized for delivering superior performance. Well done to the entire Rig 127 Team and continued success in delivering safe, superior performance."
Peter
Transocean rig breaks world drilling record
Filed from Houston 5/21/2008 1:51:37 PM GMT (source)
QATAR: Offshore drilling contractor Transocean is claiming a new world record for the longest extended-reach well ever drilled. Transocean jackup GSF Rig 127 set the record, drilling Well BD-04A in the Al-Shaheen field offshore Qatar to a depth of 40,320 feet (12,289 m) with a 35,770-foot (10,902-m) horizontal section.
The well is the first offshore well to exceed 40,000 feet (12,191 m) and breaks the previous extended-reach record holder, ExxonMobil's Sakhalin-1 well in Russia's Chayo field, by 2,000 feet (6,096 m).
During the 36 incident-free days of drilling, the crew members on GSF Rig 127 overcame high drilling torque through the horizontal section, and used deck-management planning and a supply boat to hold additional drill pipe, allowing the rig to stay within its variable deck load rating.
GSF Rig 127 is a Friede & Goldman L-780 Mod II design jackup, with 250-foot (76.2-m) water depth capability and operates with two Emsco FB 1600 Mud pumps. Other equipment includes a 2000-horsepower National 1320 UE Drawworks, and a Varco TDS-4S Top Drive.
Transocean Egypt and Middle East Division Manager Gary Bauer lauded the crew of the rig. "It goes without saying that your accomplishment truly epitomizes and embraces Transocean's vision statement where Rig 127 has a group of highly motivated people dedicated to achieving operational excellence in an incident-free environment and being recognized for delivering superior performance. Well done to the entire Rig 127 Team and continued success in delivering safe, superior performance."
More Horizontal Drilling Success
If there is a bright spot, (sorry seismic interpreters, no pun intended) in today's domestic oil and gas industry, it seems to lie in the area of horizontal drilling, completion and production from so-called unconventional reservoirs. The following notes are from two recent examples reported in the February 16 issue of the Oil and Gas Journal, page 36.
Note in particular the GeoResources, Inc. well in the Austin Chalk of south Texas' Giddings Field that produced 1BCF in its first 60 days of production. At $4/MCF, that equals $4 Million return in 60 days, which probably paid the cost of drilling and completing the well. Not bad, I'd say.
Petrohawk Energy Corp. of Houston is also doing very well with their wells in the Haynesville Shale Play in NW Louisiana and the Fayetteville Shale Play in Arkansas, both involving horizontal drilling. The company claims to have replaced "419 % of its production in 2008". Now that is the kind of economic stimulation we could use more of!
Peter
Note in particular the GeoResources, Inc. well in the Austin Chalk of south Texas' Giddings Field that produced 1BCF in its first 60 days of production. At $4/MCF, that equals $4 Million return in 60 days, which probably paid the cost of drilling and completing the well. Not bad, I'd say.
Petrohawk Energy Corp. of Houston is also doing very well with their wells in the Haynesville Shale Play in NW Louisiana and the Fayetteville Shale Play in Arkansas, both involving horizontal drilling. The company claims to have replaced "419 % of its production in 2008". Now that is the kind of economic stimulation we could use more of!
Peter
Friday, February 13, 2009
Forest Oil Hits It Big In Haynesville Shale
It is not often that you hit a home run in your first at-bat, but it looks like Forest Oil, with corporate headquarters in Denver, Colorado, has done just that. Their first horizontal well in the Haynesville Shale Gas Play produced at a rate of 14 MMcfe/d, which is eye-opening by any standards.
Note that Forest Oil says they completed a 14 well vertical drilling program in 2008 in the Haynesville Shale. Why 14 vertical wells before drilling a single horizontal well? Prudence and foresight. The vertical wells give them geologic information which they can use to correlate, interpret and maximize the drilling, completion, and production of their subsequent horizontal wells. Obviously they're doing it right. Beginners luck you say? I don't think so.
Peter
Forest Oil All Smiles over Completed Haynesville/Bossier Shale Well
Forest Oil Corp. 2/11/2009
URL: http://www.rigzone.com/news/article.asp?a_id=72803
Forest Oil has reported results from its first horizontal Haynesville/Bossier shale well in the East Texas/North Louisiana corridor. The Moseley 14-1H, located in Red River Parish, Louisiana, produced into the sales line at a rate of 14 MMcfe/d with 6,500 psi flowing casing pressure while still cleaning up frac load. Forest has a 100% working interest in this well.
Forest holds approximately 3,800 net acres around the drillsite. Forest has approximately 140,000 gross (106,000 net) acres in the Haynesville/Bossier play and intends to operate a two rig program to drill 10-12 horizontal Haynesville/Bossier shale wells and participate in 2-3 non-operated wells during 2009. The Company currently has two horizontal Haynesville/Bossier shale wells completing and two drilling.
In 2008, Forest completed a 14 well vertical Haynesville/Bossier shale program in East Texas and North Louisiana. The 2008 vertical program allowed the Company to obtain additional data to identify the most prospective geographic areas to drill horizontally for the Haynesville/Bossier shale on its acreage. In 2009, Forest will now focus on executing a horizontal drilling program on its Haynesville/Bossier shale acreage using the Company’s wholly owned drilling subsidiary Lantern Drilling.
H. Craig Clark, President and CEO, stated, "We are particularly pleased with the productivity of our first Haynesville/Bossier horizontal. Our operations team has again performed well, especially in light of the mechanical difficulties being experienced in the industry related to this type of horizontal drilling. We will continue to evaluate different well designs and stimulation treatments as we did in our successful Cotton Valley horizontal program. Our future Haynesville program, like the Cotton Valley, will lead to increased cost efficiencies and enhanced completions."
Note that Forest Oil says they completed a 14 well vertical drilling program in 2008 in the Haynesville Shale. Why 14 vertical wells before drilling a single horizontal well? Prudence and foresight. The vertical wells give them geologic information which they can use to correlate, interpret and maximize the drilling, completion, and production of their subsequent horizontal wells. Obviously they're doing it right. Beginners luck you say? I don't think so.
Peter
Forest Oil All Smiles over Completed Haynesville/Bossier Shale Well
Forest Oil Corp. 2/11/2009
URL: http://www.rigzone.com/news/article.asp?a_id=72803
Forest Oil has reported results from its first horizontal Haynesville/Bossier shale well in the East Texas/North Louisiana corridor. The Moseley 14-1H, located in Red River Parish, Louisiana, produced into the sales line at a rate of 14 MMcfe/d with 6,500 psi flowing casing pressure while still cleaning up frac load. Forest has a 100% working interest in this well.
Forest holds approximately 3,800 net acres around the drillsite. Forest has approximately 140,000 gross (106,000 net) acres in the Haynesville/Bossier play and intends to operate a two rig program to drill 10-12 horizontal Haynesville/Bossier shale wells and participate in 2-3 non-operated wells during 2009. The Company currently has two horizontal Haynesville/Bossier shale wells completing and two drilling.
In 2008, Forest completed a 14 well vertical Haynesville/Bossier shale program in East Texas and North Louisiana. The 2008 vertical program allowed the Company to obtain additional data to identify the most prospective geographic areas to drill horizontally for the Haynesville/Bossier shale on its acreage. In 2009, Forest will now focus on executing a horizontal drilling program on its Haynesville/Bossier shale acreage using the Company’s wholly owned drilling subsidiary Lantern Drilling.
H. Craig Clark, President and CEO, stated, "We are particularly pleased with the productivity of our first Haynesville/Bossier horizontal. Our operations team has again performed well, especially in light of the mechanical difficulties being experienced in the industry related to this type of horizontal drilling. We will continue to evaluate different well designs and stimulation treatments as we did in our successful Cotton Valley horizontal program. Our future Haynesville program, like the Cotton Valley, will lead to increased cost efficiencies and enhanced completions."
Haynesville Shale May Become World's Largest Gas Field?
Ok, CEO's have been known to exaggerate their company's prognosis. See the following comments by the CEO of Chesapeake Energy. However, the Haynesville Shale in northwestern Louisiana and far eastern Texas is shaping up to be at least a major new gas play. Call it "unconventional shale gas", but it is for real. This gas play is at the heart of what I'm presenting on this blog.
The Haynesville Shale Play involves horizontal drilling, and the interpretation and steering while drilling of those wells, multi-stage frac jobs, and the opening of thousands of feet of pay zone, and multiple wells being drilled in all directions from one location. The Haynesville Shale and plays like it represent a big part of the future gas industry. Stay tuned.
Peter
Haynesville Shale Primed to Become World's Largest Gas Field by 2020 by Starr SpencerPlatts 2/11/2009
URL: http://www.rigzone.com/news/article.asp?a_id=72839
The Haynesville Shale may eventually become the world's largest producing gas field, Aubrey McClendon, CEO of Chesapeake Energy and a pioneer of the play in east Texas and northwest Louisiana, said Wednesday.
(Map showing the location of the Haynesville Gas Shale Play)
Chesapeake expects the play, which only became widely known when the company began talking about it last March, will produce at least 500 Tcf over time and then recover around 700 Tcf before potentially growing even larger, McClendon said during a presentation to the annual Cambridge Energy Research Associates conference in Houston.
"We think in time it will become the largest gas field in the world at 1.5 quadrillion cubic feet," he added.
Haynesville will become the largest US gas field by 2020, he added.
Meanwhile, the Barnett Shale play in north Texas, which sparked the shale craze earlier this decade, now produces 4.5 to 5 Bcf/d, and "is largely responsible for the current oversupply of natural gas" in the US, said the CEO. However, Chesapeake does not believe production will peak at more than 7 Bcf/d.
"If the current 100 rigs there -- half what it was six months ago -- holds, this field won't ever produce more than about 6 Bcf/d," he said.
Last week, Chesapeake peer EOG Resources said it expected the Haynesville to peak in the first quarter at 5 Bcf/d.
In addition, McClendon projected that a declining rig count could cause a 7% to 8%, and possibly even as much as 10%, decline in US natural gas production.
"You could see as much as a 10 Bcf/d swing in gas output year over year," McClendon said. US gas production currently hovers about 60 Bcf/d.
However, oilfield service costs should be down this year about 20%, and that, on top of the fall in rig count, should also spur recovery in the rig count, he said.
"The seeds of recovery in gas prices are being sown today and we think 2010 and 2011 should be a much better environment," said the CEO.
He also said he believes the US gas rig count, which peaked at about 1,500 rigs last September, needs to go down about 60% to create the much-sought price rebound. It is currently at 1,104 rigs.
The Haynesville Shale Play involves horizontal drilling, and the interpretation and steering while drilling of those wells, multi-stage frac jobs, and the opening of thousands of feet of pay zone, and multiple wells being drilled in all directions from one location. The Haynesville Shale and plays like it represent a big part of the future gas industry. Stay tuned.
Peter
Haynesville Shale Primed to Become World's Largest Gas Field by 2020 by Starr SpencerPlatts 2/11/2009
URL: http://www.rigzone.com/news/article.asp?a_id=72839
The Haynesville Shale may eventually become the world's largest producing gas field, Aubrey McClendon, CEO of Chesapeake Energy and a pioneer of the play in east Texas and northwest Louisiana, said Wednesday.
(Map showing the location of the Haynesville Gas Shale Play)Chesapeake expects the play, which only became widely known when the company began talking about it last March, will produce at least 500 Tcf over time and then recover around 700 Tcf before potentially growing even larger, McClendon said during a presentation to the annual Cambridge Energy Research Associates conference in Houston.
"We think in time it will become the largest gas field in the world at 1.5 quadrillion cubic feet," he added.
Haynesville will become the largest US gas field by 2020, he added.
Meanwhile, the Barnett Shale play in north Texas, which sparked the shale craze earlier this decade, now produces 4.5 to 5 Bcf/d, and "is largely responsible for the current oversupply of natural gas" in the US, said the CEO. However, Chesapeake does not believe production will peak at more than 7 Bcf/d.
"If the current 100 rigs there -- half what it was six months ago -- holds, this field won't ever produce more than about 6 Bcf/d," he said.
Last week, Chesapeake peer EOG Resources said it expected the Haynesville to peak in the first quarter at 5 Bcf/d.
In addition, McClendon projected that a declining rig count could cause a 7% to 8%, and possibly even as much as 10%, decline in US natural gas production.
"You could see as much as a 10 Bcf/d swing in gas output year over year," McClendon said. US gas production currently hovers about 60 Bcf/d.
However, oilfield service costs should be down this year about 20%, and that, on top of the fall in rig count, should also spur recovery in the rig count, he said.
"The seeds of recovery in gas prices are being sown today and we think 2010 and 2011 should be a much better environment," said the CEO.
He also said he believes the US gas rig count, which peaked at about 1,500 rigs last September, needs to go down about 60% to create the much-sought price rebound. It is currently at 1,104 rigs.
Thursday, February 12, 2009
A Look At All Categories Of "Unconventional Gas" Supplies
How things change, in just one year. The economic downturn has put much of the drilling and production of so called "unconventional gas" on hold. The question is, when and to what degree will the economy recover and increase demand and price? This article, written just one year ago, in February 2008, describes and defines the different categories of unconventional gas. The authors also make projections of future demand and production.
Today, unconventional natural gas already accounts for one-third of the annual domestic production of the slightly more than 18 trillion cubic feet (Tcf) of natural gas from the lower 48 states, according to DOE. Most unconventional gas is differentiated from traditional natural gas sources in that the gas is produced from reservoir rocks with poor permeability — so poor that drillers must routinely enhance permeability in the rocks surrounding each producing well. Unconventional resources occur in low-permeability sandstones (tight gas), within unusual host rocks such as shales (shale gas) or coal seams (coalbed methane), or within gas hydrates in offshore continental margins and onshore Arctic permafrost. Although the U.S. Energy Information Administration (EIA) and National Petroleum Council foresee slight declines in future production of conventional natural gas in the lower 48 states, both onshore and shallow offshore, unconventional natural gas, as well as deepwater and subsalt offshore gas, will continue to provide a greater share of the overall gas supply in the future.
The Need
The continuing growth of unconventional domestic gas supplies will lessen the need for LNG. These gas “plays” have already spurred a dramatic rise in drilling activity, with the U.S. gas-rig count surpassing 1,400 since August 2006, double the levels of 2002, according to Jeremy Platt, chair of the Energy Economics Committee of the Energy Minerals Division (EMD) of the American Association of Petroleum Geologists. This upsurge in drilling activity is attributable to rising natural gas prices. The sources of unconventional gas certainly vary, but many are currently economically viable.
The Sources
Because unconventional gas resources are generally lower-grade compared to conventional gas, more wells — closely spaced over large areas (whole counties or larger) — are required to produce them. Tens of thousands of new wells have been drilled in the United States for unconventional gas in the past decade. Cost-effective exploration and production strategies must take into account the unique set of play elements that exist for each type of unconventional gas reservoir. An in-depth look at the rock properties is vital to understanding the true complexity of these unusual reservoirs.
Tight Gas
Stephen Laubach and his team at the Bureau of Economic Geology (BEG) at the University of Texas at Austin are investigating low-permeability sandstones in the deep subsurface and examining links between mechanical and chemical processes in open fractures that can serve as permeability pathways for gas migration to the well bore. Observations of microfractures in thin sections demonstrate that fracturing and mineral cementation are linked processes. Laubach’s team learned that, ironically, fractures can be both clogged (bad news) or propped open (good news) by quartz cementation. Research efforts are now directed at predicting areas of enhanced fracturing where the cracks remain partially open to fluid flow.
Coalbed Methane
Coalbed methane production in the United States and Canada is centered in the West.
Coalbed methane has a unique set of factors that affect production, including the type of coal, as well as cleat and fracture development, which together control migration of gas to the well bore. Coal-seam thickness and continuity also play a role in coalbed methane resource size by controlling reservoir volumes and extent. For example, the greatest coalbed methane production in the Cretaceous Fruitland Formation in the San Juan Basin in New Mexico and Colorado coincides with thick coal seams that accumulated landward (southwestward) of ancient shorelines of the shallow sea that once covered this region about 73 million years ago.
Shale Gas
Shale gas research is expanding rapidly as a result of successes in the Barnett in Texas and the age-equivalent Fayetteville Shale in northern Arkansas, and the push to repeat those successes elsewhere. This research covers a wide spectrum of issues. Fundamental depositional controls on mudstones are being reexamined by geologists such as Juergen Schieber at Indiana University in Bloomington. Other major areas of study include pore and fracture development, physical rock properties of shales, and burial/thermal history with related hydrocarbon expulsion. All of these areas of research will help determine production strategies during the lifetime of shale gas plays, targeting recovery of a larger fraction of in-place resources.
Still, there are challenges to this production. The need for safe and efficient disposal of waste water produced during production can be a significant cost factor for producing both coalbed methane and shale gas. Many coalbed methane wells (for example, in the Powder River Basin in Wyoming) require the production of substantial volumes of water before methane becomes mobile and migrates to the well bore. Water is commonly used to fracture the rocks to enhance production in shale gas reservoirs such as the Barnett Shale, where an individual horizontal well can require up to 3 million gallons of water for multiple “frac jobs” in the well-completion process. The Railroad Commission of Texas reports that about 2.6 billion gallons of water were used for frac jobs in the Barnett Shale in 2006. Basinwide, this amounts to 2 percent of total water usage, but in some areas in the Fort Worth Basin, frac water is 10 to 20 percent of the local usage from the Trinity aquifer, according to Jean-Philippe Nicot of BEG. Most of this frac water is produced with the gas and must be disposed of by deep injection. One implication for the oil and gas industry, particularly in the Barnett Shale play, is that operators may eventually have to rely on fracturing techniques that use reconditioned, produced water or less water in general.
Gas hydrates —The New Frontier
Although natural gas from hydrates is not yet economically feasible to produce, it has been produced successfully in pilot wells in permafrost regions of Russia and Canada. Lessons learned from these investigations could result in viable commercial production by 2015, according to Art Johnson, chair of the EMD Gas Hydrates Committee. However, several safety and technical issues need to be resolved before gas hydrates can become a viable source of unconventional gas. For example, seafloor stability must be assured, as large-scale slumping of shallow, hydrate-bearing strata during production could potentially damage production facilities and release large amounts of methane into the water column and eventually into the atmosphere. Methane, volume-for-volume, is about 20 times more potent than carbon dioxide as a greenhouse gas, so unintended releases must be guarded against.
Important technical issues for gas hydrates include the need for improved petrophysical characterization — a difficult proposition, however. The three-dimensional distribution of gas hydrates can be complex, occurring either in disseminated or tabular form. Realistic modeling of this distribution has a significant bearing on an accurate determination of gas saturation and, thus, on potential resource size. One step in determining distribution of hydrates in sediments involves the correlation of gas-hydrate rock properties with seismic data.
The Future
Ambrose, Potter and Briceno are all at the Bureau of Economic Geology at the University of Texas at Austin. The authors gratefully acknowledge Joel Lardon, who drafted the second figure, and Lana Dieterich, who helped edit the manuscript.
Peter
An “Unconventional” Future for Natural Gas in the United States
Growing demand for energy in the United States is causing shifts in the mix of fossil fuel supplies and creating new opportunities for geological research. Oil, gas and coal are the country’s primary energy sources. Yet the United States faces declining domestic oil production and increasing reliance on oil imports: According to the U.S. Department of Energy (DOE), the United States already imports 67 percent of the oil it consumes. And though we have plenty of coal, it has a bad reputation for not being clean. Natural gas, on the other hand, is relatively clean, and the United States produces quite a bit of it, only importing about 16 percent each year. Furthermore, domestic production is expected to continue to rise in the near future, thanks primarily to “unconventional” gas resources. Such unconventional sources were thought to be noncommercial only a few years ago. Recent efforts to pursue these lower-quality reservoirs, which host huge amounts of widely disseminated gas resources, have been remarkably successful.
Today, unconventional natural gas already accounts for one-third of the annual domestic production of the slightly more than 18 trillion cubic feet (Tcf) of natural gas from the lower 48 states, according to DOE. Most unconventional gas is differentiated from traditional natural gas sources in that the gas is produced from reservoir rocks with poor permeability — so poor that drillers must routinely enhance permeability in the rocks surrounding each producing well. Unconventional resources occur in low-permeability sandstones (tight gas), within unusual host rocks such as shales (shale gas) or coal seams (coalbed methane), or within gas hydrates in offshore continental margins and onshore Arctic permafrost. Although the U.S. Energy Information Administration (EIA) and National Petroleum Council foresee slight declines in future production of conventional natural gas in the lower 48 states, both onshore and shallow offshore, unconventional natural gas, as well as deepwater and subsalt offshore gas, will continue to provide a greater share of the overall gas supply in the future.
The Need
Natural gas provides about 22 percent of total U.S. energy needs and is used primarily for industrial fuel and raw materials, electrical power generation and home heating, according to EIA. Natural gas is a cleaner-burning alternative to other fossil fuels used in power generation and can be considered, along with nuclear power and “clean coal” technologies, in near-term carbon-reduction strategies. Natural gas is also the best current starting material for hydrogen manufacture for both industrial use and fuel cells.
Ambrose, Potter and Briceno: Sources: EIA and NPC
Ambrose, Potter and Briceno: Sources: EIA and NPC
Annual natural gas production in the U.S. lower 48 states in trillion cubic feet. Production from unconventional gas sources (predominantly tight gas) and deepwater/subsalt offshore will continue to increase. In contrast, production from the lower 48 conventional onshore and shallow offshore sources will decline slightly.
Despite abundant natural gas resources and production capacity in the United States, demand still exceeds supply, with the balance imported mostly via pipeline from Canada. The natural gas supply gap will grow to nearly 9 Tcf per year by 2025, according to Michelle Foss at the Center for Energy Economics in Houston, Texas.
Liquefied natural gas (LNG), transported from traditional high-quality reservoirs outside North America, is expected to make up for this growing shortfall. LNG is a form of natural gas that has been refrigerated to reduce volume. It is typically transported to coastal receiving terminals via large, double-hulled transport ships. When giant fields of natural gas are discovered far from markets or pipelines, transport of the gas in LNG form is a common strategy, and this form of international gas trade is growing rapidly. Significant sources of LNG include the Middle East, North and West Africa, the Caribbean, South America, Indonesia, Malaysia and Australia. The United States is expected to increase imports of LNG from 0.6 billion cubic feet per day in 2006 to 9.6 billion cubic feet per day by 2011, according to EIA.
The continuing growth of unconventional domestic gas supplies will lessen the need for LNG. These gas “plays” have already spurred a dramatic rise in drilling activity, with the U.S. gas-rig count surpassing 1,400 since August 2006, double the levels of 2002, according to Jeremy Platt, chair of the Energy Economics Committee of the Energy Minerals Division (EMD) of the American Association of Petroleum Geologists. This upsurge in drilling activity is attributable to rising natural gas prices. The sources of unconventional gas certainly vary, but many are currently economically viable.
The Sources
Unconventional natural gas differs from conventional natural gas and oil systems in terms of its “play elements,” or key geologic attributes. Major play elements for oil and gas deposits include reservoir quality, trap, source and migration. In conventional oil and natural gas deposits, most hydrocarbons originate from organic-rich source beds and migrate into either structural or stratigraphic traps sealed by low-permeability shales, mudstones or salt.
In contrast, unconventional gas systems, such as shale gas and coalbed methane, are self-sourcing, and gas molecules (principally methane) are trapped in pore networks and in adsorbed state on in-situ organic material. Shale gas and coalbed methane production come from a combination of desorbed gas and free gas flowing through fractures (or cleats in coal in the case of coalbed methane), rather than through the types of intergranular pore networks typically encountered in sandstone beds in conventional oil and gas deposits.
Because unconventional gas resources are generally lower-grade compared to conventional gas, more wells — closely spaced over large areas (whole counties or larger) — are required to produce them. Tens of thousands of new wells have been drilled in the United States for unconventional gas in the past decade. Cost-effective exploration and production strategies must take into account the unique set of play elements that exist for each type of unconventional gas reservoir. An in-depth look at the rock properties is vital to understanding the true complexity of these unusual reservoirs.
Tight Gas
Although tight-gas reservoirs — which account for the majority of unconventional U.S. gas production (about 5 Tcf per year) — produce gas from conventional host-rock lithologies (sandstones and limestones), the quality of the reservoir is a major limiting factor for how accessible the gas is. Tight gas reservoirs are commonly so impermeable that fractures, either natural or those that are intentionally induced in the well-completion process, or both, are necessary to boost producibility. Major tight-gas drilling programs are under way in Rocky Mountain basins as well as in eastern and southern Texas.
Stephen Laubach and his team at the Bureau of Economic Geology (BEG) at the University of Texas at Austin are investigating low-permeability sandstones in the deep subsurface and examining links between mechanical and chemical processes in open fractures that can serve as permeability pathways for gas migration to the well bore. Observations of microfractures in thin sections demonstrate that fracturing and mineral cementation are linked processes. Laubach’s team learned that, ironically, fractures can be both clogged (bad news) or propped open (good news) by quartz cementation. Research efforts are now directed at predicting areas of enhanced fracturing where the cracks remain partially open to fluid flow.
Coalbed Methane
Coalbed methane also provides significant contributions to the U.S. unconventional gas supply, accounting for approximately 10 percent of the nation’s methane resources. With at least 750 Tcf of domestic coalbed methane resources recently discovered, more than 550 Tcf of which is in the western United States, coalbed methane production has climbed from negligible amounts in the mid-1980s to almost 2 Tcf per year, according to DOE. Despite this rapid increase, there are indications that production is beginning to flatten, introducing the challenges of searching for new coalbed methane targets and enhancing production in marginal areas.
Coalbed methane production in the United States and Canada is centered in the West.
Coalbed methane has a unique set of factors that affect production, including the type of coal, as well as cleat and fracture development, which together control migration of gas to the well bore. Coal-seam thickness and continuity also play a role in coalbed methane resource size by controlling reservoir volumes and extent. For example, the greatest coalbed methane production in the Cretaceous Fruitland Formation in the San Juan Basin in New Mexico and Colorado coincides with thick coal seams that accumulated landward (southwestward) of ancient shorelines of the shallow sea that once covered this region about 73 million years ago.
Shale Gas
Shale gas plays have recently made a significant impact on unconventional gas production, especially from the Barnett Shale in the Fort Worth Basin in Texas, where estimated resources are approximately 26 Tcf, according to the U.S. Geological Survey. The Fort Worth Basin is one of about 20 shale gas basins across the United States where total domestic shale gas resources are thought to range from 500 Tcf to 780 Tcf, according to Schlumberger, Inc.
Despite this enormous resource, the percentage of gas recovered by today’s production methods in shale gas reservoirs is low (typically less than 15 percent of estimated gas in place), and controls on shale gas producibility and recovery are still not well-understood. Work continues on modeling fluid flow in nanometer-scale pores in shale gas reservoirs, where classical equations that describe fluid flow through porous media may not be valid, according to Farzam Javadpour at the Alberta Research Council in Canada.
Shale gas research is expanding rapidly as a result of successes in the Barnett in Texas and the age-equivalent Fayetteville Shale in northern Arkansas, and the push to repeat those successes elsewhere. This research covers a wide spectrum of issues. Fundamental depositional controls on mudstones are being reexamined by geologists such as Juergen Schieber at Indiana University in Bloomington. Other major areas of study include pore and fracture development, physical rock properties of shales, and burial/thermal history with related hydrocarbon expulsion. All of these areas of research will help determine production strategies during the lifetime of shale gas plays, targeting recovery of a larger fraction of in-place resources.
Still, there are challenges to this production. The need for safe and efficient disposal of waste water produced during production can be a significant cost factor for producing both coalbed methane and shale gas. Many coalbed methane wells (for example, in the Powder River Basin in Wyoming) require the production of substantial volumes of water before methane becomes mobile and migrates to the well bore. Water is commonly used to fracture the rocks to enhance production in shale gas reservoirs such as the Barnett Shale, where an individual horizontal well can require up to 3 million gallons of water for multiple “frac jobs” in the well-completion process. The Railroad Commission of Texas reports that about 2.6 billion gallons of water were used for frac jobs in the Barnett Shale in 2006. Basinwide, this amounts to 2 percent of total water usage, but in some areas in the Fort Worth Basin, frac water is 10 to 20 percent of the local usage from the Trinity aquifer, according to Jean-Philippe Nicot of BEG. Most of this frac water is produced with the gas and must be disposed of by deep injection. One implication for the oil and gas industry, particularly in the Barnett Shale play, is that operators may eventually have to rely on fracturing techniques that use reconditioned, produced water or less water in general.
Gas hydrates —The New Frontier
Although commercial production has already been established from shale gas and coalbed methane, gas hydrates are truly a frontier resource. Hydrates occur predominantly as methane trapped inside ice-lattice molecular structures in deepwater seafloor sediments. Because of the high-pressure and low-temperature conditions of the seafloor, hydrate methane is a concentrated energy source, with an energy density of 42 percent of that of LNG, according to Bob Hardage of BEG. Although estimates of gas-hydrate resources are uncertain, many experts think that these resources are enormous, and the potential North American resource may be many thousands of trillion cubic feet.
Although natural gas from hydrates is not yet economically feasible to produce, it has been produced successfully in pilot wells in permafrost regions of Russia and Canada. Lessons learned from these investigations could result in viable commercial production by 2015, according to Art Johnson, chair of the EMD Gas Hydrates Committee. However, several safety and technical issues need to be resolved before gas hydrates can become a viable source of unconventional gas. For example, seafloor stability must be assured, as large-scale slumping of shallow, hydrate-bearing strata during production could potentially damage production facilities and release large amounts of methane into the water column and eventually into the atmosphere. Methane, volume-for-volume, is about 20 times more potent than carbon dioxide as a greenhouse gas, so unintended releases must be guarded against.
Important technical issues for gas hydrates include the need for improved petrophysical characterization — a difficult proposition, however. The three-dimensional distribution of gas hydrates can be complex, occurring either in disseminated or tabular form. Realistic modeling of this distribution has a significant bearing on an accurate determination of gas saturation and, thus, on potential resource size. One step in determining distribution of hydrates in sediments involves the correlation of gas-hydrate rock properties with seismic data.
The Future
Obviously, there are several sources of natural gas that are markedly different from conventional gas that may stave off some of the energy issues the United States will face in the coming years. The new unconventional sources are lower-grade, but very widespread in U.S. sedimentary basins. Natural gas consumption in the United States will continue to grow, driven by demand for electric power, home heating, industrial uses and cleaner-burning alternatives to oil and coal for transportation and electricity.
LNG imports, which EIA anticipates will grow from 1 percent of the U.S. natural gas supply to approximately 15 percent by 2025, will help to meet future demands. As these LNG imports come online, additional natural gas production from unconventional gas plays will help to fill supply gaps for the next several decades.
Ambrose, Potter and Briceno are all at the Bureau of Economic Geology at the University of Texas at Austin. The authors gratefully acknowledge Joel Lardon, who drafted the second figure, and Lana Dieterich, who helped edit the manuscript.
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