Gas shale deposits appear in basins from the east to the west coast across the United States. Although recovery percentages are low, total volumes are high. (Map courtesy of Schlumberger)
Oil and gas producers gather to chase the latest hot play in North America forsaking the roller-coaster ride on the high-production, high-depletion accelerating treadmill for the relative comfort of slow-producing, long-lifetime gas reserves locked in shales.
The shale gas play already has expanded into Canada, and the prospect of massive reserves in widespread blanket formations will take the play to other nations as well, but only if the price is right.

The Gas Technology Institute calculates 780 Tcf of shale gas in place under US territory. Other estimates range from a low of 500 Tcf to a high of 1,000 Tcf. The US Energy Information Administration estimated US shales contain 55.42 Tcf in recoverable gas.
In a Schlumberger report titled “When Your Resource is Unconventional, So Is Our Solution,” Joseph H. Frantz Jr. and Valerie Jochen said, “Equally gas-rich organic shales almost certainly exist elsewhere around the world, but so far, the United States is the only place with a large shale industry.”

Operators in the Appalachian Basin in the eastern United States have produced gas from Devonian shales for years. The 1990s witnessed operators in Michigan assemble massive projects to pump off water and produce gas from groups of Antrim Shale wells.

By 2000, shale gas producers had drilled 28,000 wells and were producing 700 Bcf/year of gas. In 1999, operators had drilled only four horizontal wells in the Barnett Shale in the Fort Worth Basin of northern Texas. By the end of 2004, 744 horizontal wells produced Barnett gas in a play that became the hottest gas play in the nation. That was a long road to success. Mitchell Energy spent nearly a decade searching for the fracture technique that would release Barnett reserves profitably. The later horizontal wells produced three times the gas at twice the cost of vertical wells.

The New Albany shale in southern Indiana and northern Kentucky and the Antrim shale claim a combined 9,000 wells from 250 to 2,000 ft (76.2 to 609 m) below the surface in southern Indiana and northern Kentucky. More than 20,000 wells have been drilled in the Devonian shales of the Appalachian Basin between 3,000 and 5,000 ft (914.6 to 1,524 m) deep. The Fayetteville shale in Arkansas reaches as deep as 6,000 ft (1,829 m), and the Woodford and Barnett shales in west Texas can produce below 12,000 ft (3,658 m).

A prospective operator can’t just find a shale, start drilling holes and begin pouring money into a bank account. Shales are so tight that gas typically flows only through fractures. The best shales have taken stress that produces those fractures, and manmade frac jobs can open new fractures as far as 3,000 ft from the well bore, the Schlumberger paper said.
Operators and service companies have found slickwater fracs work best in the deeper formations, while nitrogen foam fracs seem to handle shallower, lower-pressured shales.
In a shale, the thicker the formation the better, and the more fractures the better. A good shale prospect in the Barnett or Woodford is 300 to 600 ft (91 to 183 m) thick. The Barnett ranges in thickness from 100 to 1,000 ft (30.4 to 304.9 m) with a gas content of 50 Bcf to 200 Bcf per sq mile.

Typically, production starts slow and may decline at a rate of only 5% a year as it continues to produce for more than 30 years.

As an example, the Schlumberger authors said, a shale well may start producing at 1 MMcf/d, and an operator can drill 10 wells on a 1-square-mile tract for 10 MMcf/d of gas. If that tract contains a recoverable 120 Bcf of gas, it’s going to produce for a long time.

The problem with that low recovery rate is that the economics favor larger companies that can assemble large tracts of land, put together factory-like drilling and completion programs, and take advantage of economies of scale on equipment, supplies and services.

Even that isn’t good enough sometimes. Simmons & Co. International constructed economic models of three of the most popular shale plays, the Barnett, the Woodford and the Fayetteville. In the Fayetteville, for example, Simmons looked at a horizontal well program with a leasehold cost of US $50,000, 80 drilling days at a cost of $19,000 a day, $1.5 million in completion costs and $750,000 in other costs with a 90% success rate. The dry-hole cost is $2.32 million.

The capital expenditure for one success was $4.08 million, and the implied finding and development cost was $1.78/Mcf of gas with a royalty rate of 20%.

The model assumed an initial production rate of 2.5 MMcf/d, a sharp decline in the first 3 years and 6% out into the future. Ultimate recovery was 2.86 Bcf. It figured in operating expense, production taxes, general and administrative expenses, a 30% tax rate, and a gas price of $6.50/Mcf. At that rate, the play offers a 15% rate of return. The play should remain active as long as gas prices stay above $4.25/Mcf under those conditions.

The modeled Woodford shale program also returned 15% at a gas price of $6.50/ Mcf, and the Barnett shale returned 31% at that price level.

Other, less prolific shale plays need higher prices for similar returns. The accuracy of that estimate showed up when gas prices dipped below $6/Mcf in the United States. Canada’s EnCana, the third largest operator in the Barnett shale play (behind Devon Energy and XTO Resources) with 35 MMcf/d of Barnett production, or 8% of the plays total, stopped working four of the 12 rigs it had drilling the shale. Low gas prices and high rig costs ($20,000 to $22,000 a day) triggered the move.

Demonstrating the importance of the frac job on production, the Dawson 34-03-01 well in the Conassauga Shale in the Black Warrior Basin in Alabama tested for 47.5 Mcf/d of gas before a fracture treatment and for 232 Mcf/d after fracturing.

Among recoveries around the country, the four-well Little Creek Lafayette shale field in White County produced 32.01 MMcf of gas between May and December. The Culebra Oil & Gas 5 R.L. Graham Barnett well showed an initial potential of 285 Mcf/d and produced 6.25 MMcf of gas in 6 months. Burlington Oil & Gas tested its 1 Dornfield Barnett well for 3.11 MMcf/d in Reeves County, Texas and producing 23.41 MMcf in the first 4 months of production at Medusa field. The only other producer in Medusa field is the 1 Kirk, completed in two Barnett intervals for 2.04 MMcf/d initially and produced 103.27 MMcf of gas between March 2005 and June 2006.

Shale plays with potential occur throughout the United States, from the San Joaquin and Santa Maria basins in southern California through the Williston, Denver, Piceance, Uinta, Paradox and San Juan Basins in the Rocky Mountains, across the Anadarko, Fort Worth and Arkoma basins in the Midwest into the Michigan, Illinois and Appalachian basins in the east and as far south as the Black Warrior Basin in Alabama.

Although it’s in fledgling stages, the shale play also is expanding into Canada. Junex Petroleum and a partner from the United States drilled the 1 Becancour No. 8 as part of a program to evaluate the Utica Shale in Quebec. If early evaluation works out, the companies will organize an $8 million campaign. Junex controls more than 4 million acres in the area.

In the Winter 2004 edition of its GasTIPS newsletter, the Gas Technology Institute revealed a preliminary study on shale gas potential in the Western Canada Sedimentary Basin covering an area from western Alberta through northeastern British Columbia.

It looked at the gas potential of the Upper Cretaceous Wilrich, Jurassic Nordegg and Fernie, Triassic Doig, Doig Phosphate and Montney, the Exshaw and Bakken, and the Devonian Ireton and Duvernay.

The organization calculated 87 Tcf in hydrocarbon volumes in the Wilrich, Duvernay, Montney, Doig and Doig Phosphate and estimated 20% recovery from those volumes, compared with a typical 80% recovery from conventional reservoirs.

Production rates should range between 20 Mcf/d and 500 Mcf/d initially and decline at a rate of 2% to 3% a year with a production span of some 30 years. Although shales can be thicker in the United States, Canadian shales range up to 1,500 ft (457.3 m) thick. They contain between 5 Bcf and 50 Bcf/sq mile, and they all need fracture treatments for maximum yield.
In rating the shales, the Gas Technology Institute said the Wilrich in northern Alberta and northeastern British Columbia has a low carbon content, similar to the Lewis Shale in the San Juan Basin of New Mexico and Colorado. The Nordegg has the highest potential with thick, carbon-rich rock covering a large area. The formation is oil-prone in many places, but as maturity grows toward the west, it should become more gas-prone.

The Canadian Centre for Energy provided its own estimate of in-place gas in Canadian shales. That estimate included:

• Wilrich 156 Tcf
• Doig 1.1 Tcf
• Doig Phosphate 129 Tcf
• Montney 187 Tcf
• Duvenay 377 Tcf

It’s not easy to predict where the shale play will go from here, but the world probably will follow the North American model. Nations naturally will tap the easy-to-find, cheap-to-produce gas sources first. When those supplies dwindle, they will move to harder-top-find tighter and deeper formations and coalbed methane.

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