The following article comes from the AAPG Explorer, November 2008. Of particular note in the discussion of the factors important to finding and producing this "shale gas", is a lack of a mention of the importance of actually drilling, or steering one of these "horizontal wells". This must be addressed and it is not as simple as it might seem. I hope to discuss this more in the future.
Peter
Understanding gains on ‘new’ reservoir
Shales Closing ‘Conventional’ Gap (source)
At what point do unconventional resources become conventional resources?
If this is possible, gas shales are certainly closing the gap.
Even though operators have produced gas from shales since the first shale-gas well in the organic-rich Dunkirk Shale (Devonian) in New York in 1821, the recent interest in gas shales began in 1981 with the first Barnett Shale well, drilled in the Fort Worth Basin in northern Texas by Mitchell Energy Corporation. Gas shales have advanced to an economic gas play since the year 2000 thanks to a combination of high gas prices, shale reservoir characterization and advances in drilling and completion technology.
The sheer number of articles and conferences describing gas-shale plays in the United States and Canada attests to the high interest level.
As for importance, the Barnett Shale alone supplies about 7 percent of the United States’ annual dry-gas production.
The Marcellus Shale has helped raise the interest in shale plays.
Note the accompanying alphabetical list of many of the United States and Canada gas-shale plays in the news.
Gas shales span reservoir ages of Cambrian to Miocene, and shale formations such as the Barnett, Fayetteville and Woodford have become household names.
Some long-producing shales such as the Antrim, Huron and New Albany are seeing renewed interest – and the Haynesville Shale in Louisiana and Marcellus Shale in the Appalachian states are being compared to the Barnett Shale as the next big plays.
(The Late Devonian-Early Mississippian Bakken Shale in the Williston Basin is not on the list because it is primarily an oil play.)
Early lessons learned and shared concerning how to produce gas from shales have drastically shortened the learning curve when exporting the technology to new shale-gas plays.
One of these lessons was the importance of fractures (natural and induced) for gas production while avoiding fracture propagation into water-bearing formations with the occurrence of shale or carbonate fracture barriers.
Hydraulic slick-water fracturing and re-fracturing were the initial keys to completing the tight-shale reservoir. Today, horizontal wells – first applied to shales in 2003 – are now routinely applied to expose more of the shale to the well bore and use the shale boundaries as fracture barriers.
Recent technological advances applied to horizontal wells in shales include:
3-D seismic in determining lateral length and placement.
Multilaterals (drilling several laterals from a single well pad).
Multiple frac stages within a lateral.
Real-time microseismic monitoring to image hydraulic-fracture treatments.
Simul-fracs (simultaneous hydraulic fracturing of offset parallel horizontal wells about 1,000 feet apart).
Seismic is playing an increasing role in shale gas appraisal and development. In addition to imaging the basic structural geometry and faults, multi-trace attributes such as coherence and volumetric curvature are being used to detect smaller-scale faults, areas of more intense fracturing and collapse features such as sinkholes.
Of course, not all organic-rich shales will be economic gas shales, even with the application of innovative completion technology. What was once thought of as a hydrocarbon source rock or cap rock must now be evaluated as a gas reservoir.
Also, it is not enough to have a thick, organic-carbon rich black shale in the gas window. Other factors such as mineralogy (e.g., clay content and types) and petrographic properties (e.g., silt stringers, laminae, bitumen network) are important to produce gas from shales.
Fortunately, research on petrophysics, geomechanics and geochemistry conducted at universities, service companies and consortia is advancing our understanding of shales as reservoirs.
Much has been learned about how to evaluate shale as a gas source rock and reservoir. Some remaining questions include:
What is the optimum range of thermal maturity?
How low or high of thermal maturity is too low or too high?
What depth is too shallow or too deep to be economic?
How important is reservoir pressure?
Energy Minerals Division members have access to the EMD members-only Web site, which has semiannual gas-shale reports, a calendar of gas-shale conferences, an extensive list of published gas-shale literature, presentations, online reports, Web links and short course notes.
Check it out – and please let me know if you have suggestions on additions to the EMD Gas Shales Committee Web site.
United States and Canada Gas-Shale Plays
Antrim (Late Devonian; Michigan Basin, Michigan)
Baxter (Late Cretaceous; Vermillion Basin, Colorado, Wyoming)
Barnett (Mississippian; Fort Worth and Permian basins, Texas)
Bend (Pennsylvanian; Palo Duro Basin, Texas)
Cane Creek (Pennsylvanian; Paradox Basin, Utah)
Caney (Mississippian; Arkoma Basin, Oklahoma)
Chattanooga (Late Devonian; Alabama, Arkansas, Kentucky, Tennessee)
Chimney Rock (Pennsylvanian; Paradox Basin, Colorado, Utah)
Cleveland (Devonian; east Kentucky)
Clinton (Early Silurian; east Kentucky)
Cody (Cretaceous; Montana)
Colorado (Cretaceous; central Alberta, Saskatchewan)
Conasauga (Middle Cambrian; Black Warrior Basin, Alabama)
Duvernay (Late Devonian; west central Alberta)
Eagleford (Late Cretaceous; Maverick Basin, Texas)
Ellsworth (Late Devonian; Michigan Basin, Michigan)
Excello (Pennsylvanian; Kansas, Oklahoma)
Exshaw (Devonian-Mississippian; Alberta, northeast British Columbia)
Fayetteville (Mississippian; Arkoma Basin, Arkansas)
Fernie (Jurassic; west central Alberta, northeast British Columbia)
Floyd/Neal (Late Mississippian; Black Warrior Basin, Alabama, Mississippi)
Frederick Brook (Mississippian; New Brunswick, Nova Scotia)
Gammon (Late Cretaceous; Williston Basin, Montana)
Gordondale (Early Jurassic; northeast British Columbia)
Gothic (Pennsylvanian; Paradox Basin, Colorado, Utah)
Green River (Eocene; Colorado, Utah)
Haynesville/Bossier (Late Jurassic; Louisiana, east Texas)
Horn River (Middle Devonian; northeast British Columbia)
Horton Bluff (Early Mississippian; Nova Scotia)
Hovenweep (Pennsylvanian; Paradox Basin, Colorado, Utah)
Huron (Devonian; member of Ohio Shale; east Kentucky, Ohio, Virginia, West Virginia)
Klua/Evie (Middle Devonian; northeast British Columbia)
Lewis (Late Cretaceous; Colorado, New Mexico)
Mancos (Cretaceous; San Juan Basin, New Mexico, Uinta Basin, Utah)
Manning Canyon (Mississippian; central Utah)
Marcellus (Devonian; New York, Pennsylvania, West Virginia)
McClure (Miocene; San Joaquin Basin, California)
Monterey (Miocene; Santa Maria Basin, California)
Montney-Doig (Triassic; Alberta, northeast British Columbia)
Moorefield (Mississippian; Arkoma Basin, Arkansas)
Mowry (Cretaceous; Bighorn and Powder River basins, Wyoming)
Muskwa (Late Devonian; northeast British Columbia)
New Albany (Devonian-Mississippian; Illinois Basin, Illinois, Indiana)
Niobrara (Late Cretaceous; Denver Basin, Colorado)
Nordegg/Gordondale (Late Jurassic; Alberta, northeast British Columbia)
Ohio (Devonian; Appalachian Basin, east Kentucky, Ohio, West Virginia)
Pearsall (Cretaceous; Maverick Basin, Texas)
Percha (Devonian-Mississippian; west Texas)
Pierre (Cretaceous; Raton Basin, Colorado)
Poker Chip (Jurassic; west central Alberta, northeast British Columbia)
Queenston (Ordovician; New York)
Rhinestreet (Devonian; Appalachian Basin)
Second White Speckled (Late Cretaceous; southern Alberta)
Sunbury (Mississippian; Appalachian Basin)
Utica (Ordovician; New York, Quebec)
Wilrich/Buckinghorse/ Garbutt/Moosebar (Early Cretaceous; west central Alberta, northeast British Columbia)
Woodford (Late Devonian-Early Mississippian; Oklahoma, Texas)
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any thoughts on the Palo Duro Basin? it had a bit of activity over the past several years and then seems to have gone dormant.
ReplyDeleteThere has been a lot of leasing activity in the Palo Duro Basin of NW Texas. This is primarily based on the potential of the Mississippian Bend Shale. It is known to be organic-rich, thermally mature and has good gas shows over the years. It is being compared to the Barnett Shale.
ReplyDeleteHowever, like any new play, much remains to be learned, and the few players are understandably reluctant to reveal details of their operations.
Each of these "gas shales" in basins around the U.S. and the world are going to be different, stratigraphically, stucturaly, geochemically, and in other ways. The Palo Duro Basin is more complex structurally and stratigraphically than the where the Barnett Shale is. This makes the vital horizontal drilling process tricky.
My thoughts about the Palo Duro Basin are that some operator needs to have the guts, (and the money) to drill some horizontal wells into this thick shale, after identifying what is the most likely productive zone, and interpret it while it is drilling (using my company's proprietary software, of course), with the same drilling and completion techniques used so successfuly in plays like the Barnett, Haynesville and Fayetteville Shales. Higher gas prices would not hurt either.
The recent drilling into the Bend Shale within the Palo Duro Basin did indicate gas in place. One model of the Palo Duro Basin places the thicker and more thermally mature Bend Shale north of the recent drilling area. If this model is correct, then the recent drilling was at the southern edge of the play where the Bend Shale is thinner, less mature, and more interfaced with water zones. Going to take more exploration to truly evaluate the gas potential of the Bend Shale. The potential is definitely there.
ReplyDeleteThe Palo Duro Basin Bend Shale is still an on-going case study. The recent drilling into the Bend Shale did show gas in-place. Unfortunately, a majority of the companies involved in the recent exploration were more interested in "pumping/hyping their stock" than in actual production. Good engineering advice was, in some cases, ignored. No seismic was run at any location before drilling. Exploratory holes were just permitted and drilled without proper subsurface studies.
ReplyDeleteThere is one model of the Bend Shale within the Palo Duro Basin that places the thicker and more mature Bend Shale to the north of where the recent drilling took place. If this model is correct, the recent drilling was at the southern edge of the play where the Bend Shale is thinner, less mature, and more interfaced with water bearing formations. Extracting the gas in this region did proved difficult. There was one good show of gas (3.3 MMcu.ft./da) in one well that came from a 7' sand stringer. This zone was NOT frac-ed.
During the recent drilling, the Bend Shale was promoted to the investors as the next Barnett Shale Play. Engineering techniques that were used in the Barnett were used on the Bend; which any good engineer knows is not good science. Every gas shale is different with its own set of engineering parameters.
There is the potential that gas extraction will be easier and more prolific north of the area where the recent exploratory drilling occurred. The Bend Shale definitely has potential. It will take a big company with investment money and a good team of engineers to truly evaluate the Bend Shale potential.
The Cisco Shale is an Upper Pennsylvanian aged shale located within the basinal deposits the Palo Duro Basin. It lies above the Bend Shale. The Cline Shale in the Permian Basin is now being evaluated for the purpose of hydrocarbon production. The Palo Duro Basin, at one point in time, was part of the Permian Basin until the Matador Arch uplift separated the Palo Duro Basin from the Permian Basin. Although not totally confirmed as to whether the two shales are the same, the Cisco Shale does correlate with the Cline Shale geologically. Soon the Cisco Shale will be tested within the Palo Duro Basin for hydrocarbon productivity. The Cisco Shale is rich in organic matter (Dutton), but the maturity of the Cisco Shale still has to be determined. If the Cisco Shale is indeed mature, hydraulic fracking may be instrumental in developing its potential.
ReplyDeleteUnfortunately, until gas prices recover no one will be doing much gas field exploring. Many operators are drilling gas only because leases are about to expire, and they don't want to lose that sunk cost. Some are even shutting in wells waiting for prices to improve. No one is happy with the current return on gas wells since low sales prices and high drilling and completion costs are making the wells un-economic.
ReplyDeleteWe were fortunate that our gas well plays were able to turn on a dime and reconfigure to oil wells as the price dropped. We really hit the sweet spot as crude prices advanced and are receiving a good return.
--Wagner. www.checkmywells.com
Paragraphs below concerning the Cisco Shale is from Pet Rose's Technical Report:"Hydrocarbon Resources of the Palo Duro Basin, Texas Panhandle ", 1986.
ReplyDeleteCisco Basin-Fill Shales--This stratigraphic unit contains the thickest and richest source rocks ricks in the Palo Duro Basin. It is limited to the basinal area between the eastern and western Canyon shelf margins, including the oval basinal reentrant formed by the secondary shelf margin in northwestern Randall and northern Deaf Smith Counties. Thickness ranges from 100 ft (30m) along the basin margins to more than 1,400 ft (427m) in central Motley County; an average of 800 ft (244 m) in thickness is probably reasonable. I believe that at least one-half of this interval would qualify as petroleum source rock. Dutton's (1980) data indicated that, from the 8 wells that penetrated this stratigraphic unit, 41 present of the 32 samples had TOCs of 0.5 to 1 percent, and an additional 16 percent had TOCs in excess of 1 percent.
The organic material is lipid rich and oil prone, and the shales are described on sample logs as being dark gray to brown and laminated. Individual core samples from this zone show TOCs of around 2 percent, and individually picked cuttings samples range from 3 percent to as much as 12 percent TOC.
Need to correct some typos. Ignore "ricks" and that should be 41 percent, not "present". Sorry for the mistakes.
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