Big fields and long-lived reserves draw big players.

The Rocky Mountains of North America, from New Mexico in the United States to British Columbia in Canada, attract major exploration efforts in spite of their difficult geology and tight formations.
The tectonic changes that created the mountains also created traps for oil and gas that help make Alberta Canada's biggest producer and New Mexico, Colorado, Utah and Wyoming major producers in the United States.
Although EnCana Corp., recently formed by the merger of PanCanadian Petroleum and Alberta Energy Co. (AEC), is anything but typical, it recognizes the value of the Rocky Mountain tight sands and has the expertise to produce them economically.
Drawing on experience from Canada, Alberta Energy acquired properties first in Jonah field in southwestern Wyoming and later on in the Douglas Creek Arch in Colorado's Piceance Basin and made them major contributors to the corporate portfolio.
It makes sense for the largest independent in North America to work the tough Greater Green River Basin area even when it is capable of finding fields such as Buzzard, the biggest discovery in years in the North Sea.
"The US Rocky Mountain region is one of EnCana's four current North American growth platforms and a major component of our North American natural gas growth strategy," said Randy Eresman, president of EnCana's Onshore North American Division.
He backs that statement with a record that includes acquisitions since 2000 that have given the company 400 MMcfe/d of gas and liquids production from Jonah field. That doesn't include the latest acquisition from Williams Companies that added 135 MMcfe/d of production, 600 Bcfe of reserves and 16,000 net acres of land in northwestern Colorado.
In spite of the maturity of US fields, Jonah still is an emerging play. A 1997 edition of Petroleum Frontiers from IHS Energy (then Petroleum Information/Dwights) titled "Jonah Field: Expanding Gas Exploration and Production in the Greater Green River Basin," explained the play.
Even though the Green River Basin has between 3,600 Tcf and 6,800 Tcf of gas in place, 97% of it was marginally economic or inaccessible. Only 27 Tcf to 148 Tcf of the gas in tight sands was considered recoverable reserves.
In a 2001 report in Gas Tips, a publication of the Gas Technology Institute, Anthony Marino, Jonah/Pinedale team leader with AEC Oil & Gas, said producing intervals at Jonah are typically between 8,000 ft (2,440 m) and 11,000 ft (3,355 m) deep. The company had 790 Bcf in reserves at the end of 2000. Those reserves now total more than 1 Tcf.
Reservoirs include stacked channel-fill sands in a braided stream environment with permeability in the microdarcys. These were often overpressured Lance and Fort Union formation reservoirs with many intervals. At Jonah, the gas column is at least 2,500 ft (763 m), the report said.
"The key to making the economics of the field work is in hydraulic fracturing of the very tight Lance sands," Marino said. "We are using analytical methods to evaluate the effectiveness of our fracs, and as a result we are now looking at bigger fracs to increase productivity. Also, we are now pumping more jobs per well, sometimes 10 or more, to make sure we get all the pay treated."
IHS Resources traced the history of frac jobs in the tight sands and explained why the play got a reputation for marginal or non-existent economic viability and why that reputation changed.
Early attempts at completion used small-to-moderate doses of proppant (78,000 lb to 325,000 lb) and a water-based gel or carbon dioxide foam as a carrier. That resulted in wells that initially produced between 300 Mcf/d and 500 Mcf/d of gas and production that fell off sharply.
The Gas Research Institute (now the Gas Technology Institute) conducted a series of tests on two wells to determine key fracturing characteristics, closure pressure, significance of multiple fractures and proppant placement distribution. It analyzed the numbers and came up with a new completion design, the IHS report said.
It made a specific effort to fracture only productive sands, to reduce multiple fractures and to maximize propped fracture length. It used a borate cross-linked, water-based fluid to move the proppant and monitored the well through pressure response as it was being fractured. That allowed operators to adjust pad volumes proppant schedule and the chemistry of the transport fluid.
The agency ran nine treatments in the two wells in 10 weeks. That compares with treatments of up to 6 months using some previous techniques.
Both the old and new techniques resulted in wells that started production at 3.1 MMcf/d, but at the end of 12 months, the old-technique well was down to some 600 Mcf/d; the new treatment resulted in production of about 1.4 MMcf/d at the end of the year. Cumulative production was about 370 MMcf for the old-style well and more than 675 MMcf for the well with the new treatment.
In addition, according to IHS, estimated ultimate recoveries rose from the 500 MMcf to 750 MMcf range per well to 3 Bcf to 10 Bcf per well.

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