Understanding gains on ‘new’ reservoir

Shales Closing ‘Conventional’ Gap

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.
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)

Comments (0)


Division Column-EMD Brian Cardott

Brian J. Cardott is Chair of the EMD Gas Shale Committee for 2008-09.

Division Column-EMD

The Energy Minerals Division (EMD), a division of AAPG, is dedicated to addressing the special concerns of energy resource geologists working with energy resources other than conventional oil and gas, providing a vehicle to keep abreast of the latest developments in the geosciences and associated technology. EMD works in concert with the Division of Environmental Geosciences to serve energy resource and environmental geologists.

View column archives

See Also: Book

Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 4090 Book
Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 4551 Book

See Also: Bulletin Article

Emission of carbon dioxide (CO2) from fossil-fueled power generation stations contributes to global climate change. Capture of CO2 from such stationary sources and storage within the pores of geologic strata (geologic carbon storage) is one approach to mitigating anthropogenic climate change. The large storage volume needed for this approach to be effective requires injection into pore space saturated with saline water in reservoir strata overlain by cap rocks. One of the main concerns regarding storage in such rocks is leakage via faults. Such leakage requires, first, that the CO2 plume encounter a fault and, second, that the properties of the fault allow CO2 to flow upward. Considering only the first step of encounter, fault population statistics suggest an approach to calculate the probability of a plume encountering a fault, particularly in the early site-selection stage when site-specific characterization data may be lacking. The resulting fault encounter probability approach is applied to a case study in the southern part of the San Joaquin Basin, California. The CO2 plume from a previously planned injection was calculated to have a 4.1% chance of encountering a fully seal offsetting fault and a 9% chance of encountering a fault with a throw half the seal thickness. Subsequently available information indicated the presence of a half-seal offsetting fault at a location 2.8 km (1.7 mi) northeast of the injection site. The encounter probability for a plume large enough to encounter a fault with this throw at this distance from the injection site is 25%, providing a single before and after test of the encounter probability estimation method.
Desktop /Portals/0/PackFlashItemImages/WebReady/measuring-and-modeling-fault-density.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 3714 Bulletin Article

See Also: DL Abstract

With the growing global attention in shale gas and shale oil plays there has been a renewed interest in source rock geochemistry. This has resulted in a number of key questions concerning source characterization, including: 1) how much internal variability might be anticipated; 2) what is the potential impact of the variability on resource assessment; and 3) how best may a source be sampled to "fully" understand its variability?

Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 11652 DL Abstract

We have an unprecedented ability to realistically depict the spatial distributions of lithofacies in the subsurface thanks to developments in sequence stratigraphy, sedimentology, structural geology, geostatistics, and geophysics. As important as these developments have been, however, they in themselves have a limited ability to accurately predict rock properties–particularly in regions with high thermal exposures and restricted well control. We are developing a next-generation modeling platform that rigorously simulates processes in 3D at the grain scale. This 3D approach has the potential to provide unique predictive models of pore network geometries and grain contact properties for rocks in undrilled areas.

Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 11651 DL Abstract