Wednesday, November 30, 2011

In-situ Step-change

Two Norwest supervisors checking equipment in Alberta's Underground Test Facility;
photo courtesy of Gerry Stephenson
How underground shafts and tunnels changed the future of the oilsands

This article appears in the December issue of Oilsands Review
By Peter McKenzie-Brown
The year was 1976 and the place was a small town called Yarega – about 600 miles northeast of Moscow, near the Arctic Circle. A group of Albertans had gone there to observe a Soviet “oil mine.”

The Soviets had constructed shafts and tunnels into a heavy oil reservoir. Local workers were pumping steam into the reservoir through angled drill holes and production was taking place within the mine. A mining engineer among the Canadians, Gerry Stephenson, describes the project: “The wells that were injecting steam were drilled from an upper level of tunnel, which was above the heavy oil reservoir. So the injection wells were drilled from above but from tunnels. The recovery wells were drilled from tunnels below.”

According to Maurice Carrigy, vice-chair of the Alberta Oil Sands Technology and Research Agency (AOSTRA), “They had a tap, you know like a tap you would see in plumbing, a bathroom tap, and they would turn that on and off to get the oil out.”

Chronically short of cash, the USSR was hoping to sell the technology to the Canadian oil industry. The visit in part reflected a 1972 technology-sharing agreement between Canada and the USSR – one that collapsed in ‘78 when Canada expelled 13 Soviet officials for trying to infiltrate national security services.

The Canadians were not impressed with the oil mine, but they were intrigued. According to Carrigy, it led to a “total revolution in the concept of what you could do with bitumen that you couldn’t do in a traditional reservoir.… You got (the bitumen) into a form where it was either emulsified or liquefied so that you could produce it.”

At least one other group of Canadians had visited a Soviet oil mine. Hugh Lieper, who chaired Canada’s petroleum committee for the technology sharing agreement, also visited one in 1976. He describes being hoisted 800 feet into the mine in an elevator that swung wildly from side to side. At the bottom of the shaft, he found the oil being collected in a large open pit on the operations floor. “When I asked whether the electrical motors on the site were explosion-proof, no one knew what I was talking about.”

AOSTRA’s Carrigy puts the impact of his group’s visit to the Yarega oil mine in perspective. While Canada didn’t use the primitive Soviet technology, it gave credibility to “the idea that we could go below (an oilsands reservoir) instead of working from above.” That way “we could use gravity as the driver in getting the oil out. That would be natural. It would come down and flow in and then we’d take it from below rather than pulling it up to the surface.”

Adds Stephenson, “the system was definitely working, but the mine was very, very primitive. The tunnels were tiny. They weren’t mechanized at all. The piping systems were not much better than you would find in your garden. But it demonstrated that if you heat heavy oil, it will mobilize, it will be possible then to drain it, and if you put in wellheads below the reservoir, you will get production without pumping.”

The Mac of SAGD
A few years after the Canadian expeditions to the USSR, the legendary Roger Butler began developing the two-well SAGD concept, which eventually took the form in use today: injecting steam into a horizontal well and collecting oil through a parallel well below. Clem Bowman, who worked at Imperial Oil with Butler, says he actually developed the theoretical model for SAGD in the early 1970s. However Chi-Tak Yee, who was Butler’s first graduate student at the University of Calgary, says he once saw a document dated 1969 in which Butler had sketched out his preliminary ideas.

Whatever the facts of the matter, in the early 1980s the time was ripe for radical experimentation.

The AOSTRA’s first chairman, Bowman picks up the story. According to him, one day Gerry Stephenson came into his office and said “The oil companies have got it all wrong. The idea of drilling vertical wells into the oilsands and only contacting the pay zone for the few metres where there’s bitumen and having to put multiple wells down in these grid patterns just doesn’t make sense. I’m a mining man and the logical thing to do in a mine is to put down a shaft and to drill horizontal wells from that shaft and then every foot of well that’s drilled is in the pay zone.” Stephenson added that he had gone to the oil companies with this idea without success.

“And so he came to my office and sat there and made his plea that we should build a facility, put down a shaft and he had worked out what the costs would be,” Bowman continued. “According to his numbers, drilling a shaft into the deposit is not an expensive operation and the coal companies know how to handle methane in spades. So we put together a concept called the Underground Test Facility. No oil company would put any money into it but (petroleum executives on AOSTRA’s board) said they would support it technically and they’d have people help us on it.” For the only time in its history, the government agency paid full fare – and for what seemed a most speculative idea. Total budget for shafts, tunnels and infrastructure was about $30 million.

As Bowman continues, “It seemed this was the obvious time to test (Roger Butler’s) principle of gravity drainage.” Butler had left Imperial oil to become part of AOSTRA, and he became a member of the technical team. Maurice Carrigy was the project executive. Today a vice president of MEG Energy, Chi-Tak Yee says that “one of the most fortunate things that I was involved with was the Underground Test Facility project that was essentially the birthplace of SAGD. Think of (the UTF) as the Mac of SAGD development.”

First photo taken under the oilsands;
Stephenson in centre
According to Carrigy, “although we did contemplate going right into the oil sands, we thought it would be better to go down below the oil sands, put the tunnels in a secure and safe place” – a layer of limestone – “and then drill upwards” into the reservoir.

The magnitude of the UTF is hard to imagine. Sinking the shafts was done with a drill bit almost four metres in diameter weighing 230 tonnes. The two shafts were 223 metres deep and neither one deviated from the vertical by more than an inch. As a safety measure, AOSTRA constructed two parallel tunnels through the limestone. More than a kilometre in length, the tunnels were five metres wide by four metres high.
A Subway to the Wellhead
At the UTF’s official opening on June 29th 1987, a senior executive at Shell Canada – up to that time he had been a critic of the project – went to Stephenson and said, “It’s really not a mine, Gerry, is it? This is really impressive. It’s like a subway to the wellhead.”
Then came the tests. The Phase A pilot involved three well pairs 70 metres in length, each with 40-50 metres of exposure to the McMurray formation. According to Stephenson, “steam was injected and the first experiment with SAGD wells began. After a year or so, it was obvious the system was working.”
That was the beginning of a turnaround within the industry, which soon decided to get financially involved. Ten companies each contributed $16 million to the project. That funding enabled the test crew to complete Phase A and to move on to Phase B. It also funded several years of additional experimentation.
Phase B involved another three well pairs, 70 metres apart. According to Stephenson, “the effective length in the reservoir was 500 or 550 metres. They resembled a commercial development” despite having only three producing well pairs. Project engineers expected production to reach about 1,800 barrels a day.
What was the result? “AOSTRA’s staff had estimated that the recovery might be somewhere between 30 percent and 45 percent of the bitumen in place,” he says. “We actually got 65 percent recovery. The steam chambers formed by mobilization of the bitumen spread way beyond the area that we’d expected, so obviously we didn’t need to drill the well pairs as close together on Phase B as we did on Phase A, so we opened them up. Anyway, on Phase A the figures were 65 percent recovery – way beyond what we’d estimated. Over the 10-year life of the well pairs, Phase B got a steam/oil ratio, the most critical figure of all, of 2.3 to one.”
The petroleum industry soon began to develop SAGD projects from well pads. According to Stephenson, however, there are many reasons why SAGD is better done from tunnels underground. “You don’t disturb the surface to the same extent. You can use gravity to your full advantage.” And, he adds, surface schemes require a high-capacity, expensive pump for each producing well. They cost a lot to buy and a lot to service.
Also, he says, “it costs more to pump through a multitude of  8-inch pipelines than it does through a single 18-inch pipeline in a shaft. Another advantage is that you can drill more accurately from underground, and you get better recovery because you can use lower steam pressures. Your production might not be quite as high, but your recovery of the bitumen is going to be better, because you’re allowing a slow process of heat soaking upwards by thermal conductivity.”
He claims still other advantages for the system. “You’re operating in an underground climate in a tunnel. You're doing all your drilling and completion of wells as well as your process manipulation work in a safe working environment at a temperature of 58 F year round and with no snow and ice to hinder and delay your work. You can operate 24 hours a day, 365 days a year, instead of being confined with your drilling and your completions to those periods when you can drill on the muskeg and so on. You can do all these things in a safe environment that allows you to work all year long.”
A visionary but not a dreamer, Stephenson acknowledges that the system also has disadvantages. One is the need for upfront capital: until you’ve constructed the shafts and tunnels you can’t do any drilling at all. Also, of course, some reservoirs simply don’t have the geological features needed to make the system work.

In the latter 1990s the UTF was acquired by Devon Energy, which then sold it to Petro-Canada. When Suncor Energy acquired Petro-Canada, it also acquired the UTF – now known internally as its “Devon Project.” Petro-Canada developed abandonment plans for the facility, and unconfirmed reports say the ERCB approved them. It’s still intact, ‘though its future is in question. 
Post a Comment