Demand is fueling a drilling boom in North America.

Oil and gas drilling activity will continue to drive rig counts higher in 2001 as North American operators work to meet accelerating demand with the help of higher prices and lower storage levels for oil and gas.
Baker Hughes put the active rig count at 1,055 by the end of October, up from 741 a year earlier.
A check of new permit requests filed suggests demand for rigs may continue to grow. At the end of September, West Coast operators obtained permits for 2,011 wells, compared with 1,147 a year earlier. In the Appalachian Basin on the East Coast, permit requests climbed from 3,259 to 3,794 in the same period, and they increased from 7,880 to 9,875 in the Rocky Mountains.
Active seismic crews climbed from five on Sept. 15, 1999, to 12 last year in the Rocky Mountains. The count rose from six to 11 in the Midcontinent, from eight to 11 in the Southwest, from none to four in the Arkansas-Louisiana-Texas area and from none to one in Appalachia.
Some spot checks of activity might show where and why demand for rigs is rising.
Northeastern United States
High gas prices have helped overcome the high cost of fracturing in the tight Devonian shales of West Virginia and Kentucky, but the real resurgence in activity has come from a rediscovery of the Trenton-Black River combination of formations.
Columbia Natural Resources Inc. (CNR) has drilled 10 wells to Trenton-Black River in a structure known as the Rome Trough, which extends from New York through Pennsylvania, West Virginia and Kentucky. CNR reported completion details on a deep discovery in Kanawha County, W.Va., in Clendenin field. The No. 24021 Pine Mountain O&G Unit, Elk District, Mammoth Quad, flowed 15 MMcf/d of gas from Black River at 9,481ft (2,892m).
In the Michigan Basin, Shell Western E&P Inc. has expanded its Devonian Antrim Shale program in Michigan's Sanilac County by staking nine wildcats outside the traditional Antrim corridor that runs across northern Michigan.
Gulf Coast
One of the best plays in the area is the Bossier Sand, brought into the spotlight 2 years ago by Anadarko Petroleum Co. after the company discovered the secret of unlocking the tight reserves. That play is moving out of Limestone County, Texas, into Robertson County, and Anadarko has extended the play into Jackson County, La.
Anadarko drilled 105 wells in the first 9 months of 2000, and at the end of the third quarter had 265 wells producing an average 234 MMcf/d of gas. One well tested at 30.2 MMcf/d. Other operators are joining the play, and Anadarko geologists are enthusiastically looking throughout the area for the sweet spots in the Bossier.
Midcontinent
High product prices also have reawakened Oklahoma's deep gas plays. Wagner & Brown Ltd. staked the No. 1-24 Wagner & Brown in Caddo County. It's to be directionally drilled to 21,150ft (6,451m), at a true vertical depth of 20,625ft (6,291m) with Deep Arbuckle at 19,625ft (5,986m) tagged for testing.
The shallow Jackfork remains a strong target, too. The GHK Co. drilled a horizontal well that flowed 24 MMcf/d of gas from 5,981ft (1,824m) measured depth in Oklahoma's Potato Hills region in Pushmataha County, according to IHS Energy Group.
In western Kansas, operators are looking forward to potential enhanced production from CO2 injection into older fields. Operators would like to extend the CO2 line that terminates in Texas County in the Oklahoma Panhandle into the Morrow fields of Kansas. If that works well, the pipeline should step deeper into Kansas.
Permian Basin
Occidental Petroleum became the biggest oil producer in the Permian Basin and Texas when it bought Altura Energy in 2000. Since then it has halted Altura's declining production at 143,000 b/d, and it planned to revise reserves upward from 850 million bbl by the end of 2000.
On the New Mexico side of the basin, several operators are taking harder looks at deeper, more expensive formations such as the Morrow. David H. Arrington Oil & Gas Inc. was drilling at 12,500ft (3,813m) at the No. 1 Irresistible, a Lea County, N.M., wildcat.
Rocky Mountains
PetroSource Partners Ltd. plans to extend the existing CO2 pipeline from southwestern Wyoming to central Wyoming an additional 135 miles (217km) to the Powder River Basin in northeastern Wyoming in 2001. Previous plans called for further extensions northeast to the Williston Basin and northwest to the Big Horn Basin.
The Jonah field play continues to expand in Sublette County in southwestern Wyoming. Forest Oil Corp. recorded a flow of 10.8 MMcf/d of gas and 110 b/d of from Upper Cretaceous Lance at completion of the No. 23-14 Elm-Federal. Meanwhile, Questar E&P is one of several operators planning campaigns on the Pinedale Anticline north of the Jonah field basin-center gas play. The company said the play has a possible 3 Tcf of gas in place. It planned to finish as many as 10 wells in 2000 at a cost of US $2.5 million per well and with reserve potential of 4 Bcf to 11 Bcf per well.
West Coast
In Kern County, Calif.'s massive oil fields, most of the work is in accelerated development activity. Berkley Petroleum Ltd. of Calgary is trying to assess the full potential of its deep Temblor Formation gas play in northwestern Kern County.
Alaska
Phillips Alaska Inc. plans to directionally drill a 14,400ft (4,392m) wildcat at the No. 1 Phillips McCovey in the Beaufort Sea, probably in late February.
BP Exploration (Alaska) Inc. will kick off a 5-year National Petroleum Reserve-Alaska exploration program called Trailblazer this winter on Alaska's North Slope. BP plans a gas pipeline from North Slope to Alberta as early as 2007. Competing Alaska Natural Gas Transportation Co. said it can get North Slope gas to the United States in the same time frame for $2/Mcf.
Eastern Canada
First oil production at the Terra Nova floating production, storage and offloading vessel is expected late in the second quarter of 2001, with peak production going to 129,000 b/d from reserves of 400 million bbl of oil in the $2.5 billion project. Initial production at Husky's White Rose is planned for 2004.
Nova Scotia raised $125.62 million in work commitments in the 2000 offshore bidding auction for projects in water depths to 10,000ft (3,050m), compared with $40.08 million raised in 1999.
The Canada-Newfoundland Offshore Petroleum Board has issued a call for nominations for its NF 00-1 off Labrador and Newfoundland. Nominations were due Dec. 18, and will be considered for the April 2001 licensing round. Late in 2000, four geophysical surveys were being conducted offshore Newfoundland and Labrador, two in the southern Grand Banks, one in the northern Grand Banks and one in Flemish Pass.
Western Canada
Higher prices encouraged Canadian operators to drill an estimated 11,095 wells in 2001, up from 7,290 in 2000 as operators probed opportunities from heavy crude at Lloydminster to deep natural gas in the Foothills play.
Northern Canada
The August 2000 Mackenzie Delta-Beaufort Sea sale by Canada's Department of Indian Affairs and Northern Development brought in $316 million from Anderson, Petro-Canada, Shell Canada, Amoco Canada Petroleum, Burlington Resources Canada, Anadarko Petroleum and Chevron Canada Resources. The Canadian National Energy Board puts discovered reserves in the Mackenzie Delta and Beaufort Sea at 1.38 billion bbl of oil, 11.44 Tcf of gas and 102.6 million bbl of condensate and recoverable resources at 12 billion bbl of oil and 168 Tcf of gas.
At least one proposal has been made for a $4 billion Mackenzie Valley pipeline from the Mackenzie Delta to Alberta.
According to the Northwest Territories government, oil and gas companies are expected to spend more than $200 million a year through 2003 on exploration and development. Chevron planned to ramp production from its M-25 well at Fort Liard up to 50 MMcf/d while it decides whether facilities can handle a volume of 75 MMcf/d of gas. The K-29 well already is producing 70 MMcf/d.
Correction
A statement in an article titled "Gulf shelf offers opportunity," (Hart's E&P, November 2000, p. 26) erroneously said the speaker "wondered if EEX could recover the $200 million it put into its Llano 2 deepwater well." According to EEX, the Llano 2 well cost about $34 million to all companies participating, and EEX had no cost in the well. Its costs were carried by Enterprise Oil Gulf of Mexico. Hart's E&P regrets the error.