Compressors push Canadian production march farther north: rapid depletion of accessible sites in Canada is resulting in a gradual push farther northward into the often-frozen muskeg of the Yukon and Northwest Territories. (Built To Withstand Stress).

For over the past half century, oil and natural gas production has been a vital economic activity in northwestern Canada. More recently, ever-increasing demand has resulted in rapid depletion of even the most abundant sites. The consequence is a gradual push farther northward, into the often-frozen muskeg of the Yukon and Northwest Territories. While new finds may seem promising, getting the land to give up its resources can quickly consume two other resources--time and money. The forbidding terrain is hard on man and machines alike.

Canadian gas drilling activity dates back to 1951: six years later saw the completion of the Westcoast transmission gas line, the first major natural gas pipeline, which brought gas to the U.S. border. It was followed by the TransCanada Pipeline.

In 2000, the 42-inch Alliance pipeline was completed, taking western Canadian gas from Fort St. John, BC, through Alberta to Chicago, moving around 37 MMcf/d. The West Coast pipeline has plants that can treat sour gas white the Alliance pipeline accepts only sweet gas.

Even today, the western province of Alberta holds most of the nation's proven reserves of natural gas. About half of the province's production is sent to the United States Next door; in British Columbia, mole than 250 oil and gas companies are actively investing about $2 billion a year in exploration, drilling, facilities and pipelines. During 2000 alone. 75t wells were drilled, an increase of 21 percent over 1999. Today, it is estimated that up to 1.5 Tcm of natural gas is available in proven British Columbia reserves.

Both Alberta and British Columbia have witnessed much seismic exploration activity, as grid lines cut through the forests visible during flyover will attest. Major finds soon become high activity areas. However, the heavy drilling and pumping that results can dramatically shorten a field's production lifespan.

As a result, exploration activity has been slowly moving northward, into the Yukon and Northwest Territories. This push presents new obstacles due to weather extremes and the terrain of the area--it's covered with muskeg, a thick, spongy, bog-like material that's found in wet areas dominated by coniferous trees. Until there's a hard freeze, roads carved out of it can't be traveled on tot tear of sinking, Rivers are too shallow to allow anything but barge traffic. Airplanes and helicopters are used to move oilfield personnel and equipment year-round, but are expensive.

"All of the easy stuff has been taken; the natural gas reserves now lie farther north," said Randy Clark, senior production foreman, Devon Canada Corp. "There was a moratorium on drilling in the Yukon Territory until 2000, but now it's the scene of much activity. This poses challenges cost and time wise, because you can only use the roads from about December through March, which is a very short season for drilling and building.

"Another problem is the lack of pipelines to transport the gas. There is a new pipeline proposed from Alaska south, but it's not set yet whether it will go through the Mackenzie Valley, which will help our sites, or farther west along the Alcan Highway. Not much gas is put into storage this far north; the salt caverns are all located farther south," he said.

Experts note the deeper, harder-to-get gas is still there for the taking farther north, but high exploration costs mean the price of natural gas will have to rise before it becomes feasible for recovery. As the U.S. attempts to wean itself away from Persian Gulf oil, the race is on to get more "black gold" from Alaska and the provinces of Northwest Canada. But due to recent mild winters and a low demand for natural gas in the U.S., natural gas production does not enjoy the same priority.

Compounding the problem is the realization that while gas production can be profitable at one price point in most of Canada, it can cost three times as much to take it from the Yukon because of the lack of infrastructure and harsh conditions, The price climbs higher the farther north exploration goes.

"In Alberta and British Columbia, you can drill a well and get it on-stream in the same year," Clark said. "In the Arctic and Yukon. it would take five or six years at the earliest. Two-thousand-foot wells are considered shallow here, with 6,000 to 8,000 feet being the norm; but some can be 13,000 to 15,000 feet. Plus, it can cost C$1.5 million just to get a rig to an Arctic site through barging and other variables. Until it becomes feasible to build the pipeline a few thousand miles north, the gas will just sit there."

There are thee Canadian sites, out of hundreds, that are using Waukesha engines to help bring gas to consumers who may be located a half continent away.

Devon Site, Kotalneelee, Yukon Territory: This is near the site where the Yukon Territory shares a border with British Columbia and the Northwest Territory. It's on the front slope of the La Biche Mountain Range and can be accessed in the warmer months from Fort Liard, BC, by barge on the Liard River. Gas production began in 1979, but the site was closed the following year when prices slumped. It reopened in 1990 and has been a strong producer ever since. Heavy exploration is also raking place in Fort Liard in the Northwest Territories.

A four person crew staffs the site and works on a two-week rotation basis, Snow levels can reach 12 feet during the long winter season, and temperatures swing from as low as -40[degrees]F in the winter to 90 degrees in the summer with daylight ranging from 19 hours to :as little as five, The site produces 39 MMcf/d of sour gas from two deep 4,200-foot wells, which is lower than the 55 MMcf/d from previous levels, showing that the gas is slowly being depleted. The site is considered medium sized for this area. The gas is dewatered on site then shipped to Fort Nelson where it's scrubbed before it enters the Westcoast Energy pipeline.

Until recently, the gas free-flowed from the wells, with the addition of more sites farther tip the feeder line over the past two years, it was necessary to bring an engine-driven compressor on site to boost the gas pressure before it entered the line. A Waukesha Series Four VHP was chosen for the job. The site has a long history with Waukesha Engine, as two VHP 2895 models were installed to provide electricity when the site was first constructed.

Responsibility for the engines, as well as for most of the site's mechanical equipment, belongs to Willie Thomas, who has 30 years of experience in working with engines, including several of them on an icebreaker in the Beaufort Sea. Born in the tiny village of Old Crow, not far from the top of the Yukon near Mackenzie Bay, most of his career has been spent in the Canadian oil patch.

At the Kotalneelee site, two Waukesha 2895 engines driving generators have been in use since the site was built to provide power. "They have been very reliable over the years, providing the heat and power for the site," Thomas noted.

In April 2000, a Waukesha VHP 7044 was placed on site driving an Ariel compressor to boost pressure to 1,240 psi for the gas to enter the line. The engine is running at 900 rpm today, but had run at 1,200 rpm to meet the higher earlier volume demands.

Penn West Mega Site, Alberta: About an hour's drive through the dense pine forests surrounding the closest town of Rainbow Lake, this site is one of several in the area operated by Penn West Petroleum Ltd. There is plenty of natural gas activity in the area and Penn West is bringing two more sites on-line. It was long known that ample supplies of gas were to be found hem at the northwestern tip of Alberta, but the costs for exploration and gathering were too high until the production infrastructure and pipeline access slowly progressed north.

As a production foreman, Terry Rycroft is responsible for seven Rainbow South fields and visits each at least once a week. Mega, which came on-line in spring 2000, is the largest of his sites, yet because of automation, it only requires a two-person crew that is also responsible for two other nearby fields.

Three Waukesha VHP L7044 engines are in use at Mega, each compressing around 11 MMcf/d of sweet gas. About 5 percent of the gas is used on site to run the engines, electrical and heal generation. The rest is sent to a Chevron site 22 miles away where CO2 is stripped. Eventually, the field will be producing 60 MMcf/d. The engines am pack aged with Gemini compressors and maintain 100 pounds suction pressure and boost to 1,400 pounds discharge pressure with engines running at 1,000 rpm.

"The engines are the key in gas production because if they don't ran, you're not making money," Rycroft said. "I get uptimes on the Waukesha engines in high 90s, probably at 98 or 99 percent availability with the only downtime for preventive maintenance."

Gas prices can vary greatly during the year, but production goes on year-round. Some of it winds up in storage facilities near the U.S. border. One of those is a salt cavern operated by Husky Oil, about an hour's drive east of Calgary.

Pipeline-spec sweet gas is pumped into and out of the 19 Bcf capacity natural salt cavern at the 40-year-old facility. Typically, gas is gathered during the summer months when demand and prices are low and then transported from there during the winter heating season. The gas is transported by TransCanada,

Two Waukesha engines packaged with Ariel compressors transfer the gas from the pipeline into the cavern. Maintaining the engines is the responsibility of Duncan Macpherson, a field operator at the Husky Severin Gas Storage Facility. He has been at the site for 17 years and earlier worked in oil exploration.

The two Waukesha Engine VHP 7044s transfer gas from pipeline into the cavern and accumulate about 6,000 hours per year, at 1,170 rpm. On site since spring 1999, the engines' biggest roles are during the summer storage phase, July-September.

Next, after the first of the year to the end of April, they help send gas down the line. "The VHP 7044s are quite excellent performers, very smooth running units," Macpherson said. "They run right through the low ambient temperatures in the winter months and through the hot summer months with no problems. I estimate we're 99 percent reliability."