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Msg  113769 of 131655  at  7/17/2010 11:33:57 AM  by


Roger Butler's invention of steam assisted gravity drainage (SAGD

Roger Butler's invention of steam assisted gravity drainage (SAGD

From Black Bonanza

From Black Bonanza, with additional material from Bill Sande and others:

  • "Roger Butler's invention of steam assisted gravity drainage (SAGD) has had a staggering economic impact. It will eventually change the whole geopolitics of oil in the world." - Tom Harding, head of chemical and petroleum engineering, University of Calgary

Neil Camarta doesn't have too much respect for bitumen bearing sands - he calls it "Dirt". But Camarta's true love is gas and he recently went back to his roots. After building Shell's colossal oil sands mine, then coming out of retirement to work for Petro-Canada, he got hired as VP Gas of Suncor Energy company. Natural gas is the primary fuel in oil sands extraction.

When I talked to him about the prospects for SAGD - Steam Assisted Gravity Drainage - he said it is the future of the Sands, and is well on the way to producing more bitumen than mining. Camarta mentions that in about 1985 he visited the first successful SAGD site, an actual underground mine tunneled right into the limestone under the Sands, to try and perfect the process.

SAGD Diagram
SAGD Diagram
SAGD is all about directional oil well drilling, which to me is a form of rocket science. Today's technology was first developed by Schlumberger and others to fracture (or "frac") gas seams. It gives operators the incredible ability to drill down vertically and then using a gyroscope and GPS, steer the drill bit, while watching above in real time, and then change direction and tunnel horizontally in any direction or angle they desire. At the same time, they can monitor on a computer screen the position and boundaries of the formation and make fine adjustments to stay inside the zone. Like mechanical versions of the giant sandworms in the Dune or Tremors movies. But directional drilling is also a godsend for SAGD, which requires precision placement of the wells.[1]

With the SAGD process, you drill two horizontal wells, one about 5 meters above the other, and lay down perforated pipe for distances of about 800 meters. You have to precisely control the positioning of these wells relative to each other and to the boundaries of the target formation. You then inject warm vapor into the upper well at constant pressure, but not high enough to fracture the growing steam chamber and escape. The heat rises and spreads, melting the surrounding bitumen off the sand. Then gravity takes over, draining the warm oil and water down through sand where it seeps into the perforations of the lower producer well. Submersible pumps designed to handle hot fluids then lift the bitumen and condensed water to the surface. Over several months the chamber grows both vertically and laterally as the cycle continues until the chamber flattens out and clean sand remains in place.

You can recover between 25% and 75% of the bitumen using SAGD, and recycle about 90% of the water. And after recovery, you inject water into the bitumen-drained area to maintain the stability of the deposit.

SAGD Shafts and Tunnels, Underground Test Facility (UTF), 1985 (AOSTRA)
SAGD Shafts and Tunnels, Underground Test Facility (UTF), 1985 (AOSTRA)
The mine Camarta visited was the Underground Test Facility (UTF) at Dover River now operated by Northstar Energy Ltd. It was built in 1984 by the Alberta Oil Sands Technology and Research Authority (AOSTRA) a Government of Alberta body set up to promote R&D in for oil sands and heavy oil production, and particularly to test the SAGD process developed by Dr. Roger Butler of the University of Calgary.

Roger Butler, Genius

There are quite a few Canadian inventors who have changed the course of the world. Abraham Gesner's invention of kerosene in 1854 killed the sperm whaling industry, lit the world for fifty years and gave birth to the Rockefeller fortune. Canadian cable and tool drilling techniques helped open North America's first commercial crude oil well in 1854, a year before Pennsylvania, and Canadian drillers struck oil in Iran for the Anglo-Persian oil company (today's BP) in 1906.

In 1892, Canadian botanist Charles Saunders invented frost resistant Marquis wheat, perhaps one of the most valuable products in the world, which opened up millions of colder acres around the globe for wheat production. Two Canadian crop scientists, Baldur Stefansson and Richard Downey, patiently developed the fabulous Canola seed from rapeseed between 1958 and 1974, carefully breeding out the grain's heart clogging trans fats. Canola (from "Canadian oil") is now a huge world crop. Canada's Mike Lazaridis gave the world the BlackBerry, and Calgary's James Gosling the Java programming language.

But a Canadian invention that may prove more valuable than all the rest combined was Steam Assisted Gravity Drainage, a method of getting heavy oil and bitumen out of the ground, perfected at Fort McMurray in 1987 by chemical engineer Roger Butler. His technique is usable anywhere in the world where heavy oil and bitumen are found.

Since the oil industry could only get at less than 10% of the Athabasca Sands using surface mining, early extraction was confined to the Athabasca River valley where the overburden was thin. The arrival of SAGD in the 1990s meant that companies could now take out the majority of the Athabasca bitumen at a very competitive cost. In the Athabasca Sands alone, the advent of SAGD makes at least 330 billion more barrels readily accessible, and could yield over a trillion barrels of synthetic crude.[2]

It's a colossal number to be sure. But if Roger Butler's invention can tap two thirds of the Sands that are out of reach of mining, it can also help ramp up heavy oil production in places like Venezuela and Russia. It just about doubles proven petroleum reserves in the world, estimated at 1.292 trillion barrels. In addition, it may have instantly tripled our planet's known recoverable oil resources, making Butler one of the true benefactors of humanity.

Butler's Theory

Roger Butler earned his PhD in chemical engineering at London’s Imperial College of Science and Technology in 1951. He taught at Queen’s University in Kingston, Ontario, then joined Imperial Oil in 1955. Butler first pondered the SAGD process and developed his theory in about 1969 when he was working at Imperial's Sarnia refinery, at the time the company had discovered a huge heavy oil deposit at Cold Lake, Alberta, near the Saskatchewan border.

Imperial OIl's Heavy Oil Extraction Process using Cyclic Steam Stimulation or CSS ("Huff and Puff")
Imperial OIl's Heavy Oil Extraction Process using Cyclic Steam Stimulation or CSS ("Huff and Puff")
Butler had already tinkered with a process for mining Saskatchewan potash, by injecting water down a well to dissolve the potash and salt. Gravity does the work. "Heavy brine falls to the bottom and the light water rises to the top. You end up with a turnip-shaped cavity in which the heavy material keeps falling while the lighter water goes to the top." He calculated that "if we made the well longer, we could draw as much as 1,000 barrels a day. We'd be in business."[3]

“I was really very impressed with the mechanism of this,” Butler recalled. One day, he was having a beer with a friend when the thought struck him - maybe his potash process could be applied to heat the molasses-like heavy oil at Cold Lake and create the same kind of steam chamber. The heated oil would flow down to the bottom of the chamber where another well would collect it and pump it to the surface.[4]

Butler wrote a patent memo on his gravity drainage concept in 1969, but it wasn't until 1975 when Imperial Oil moved him to Calgary to lead their Heavy Oil Research Department that he was able to tackle the concept. Apparently Imperial head Jack Armstrong wanted "a new pair of eyes at Cold Lake."[5]

During the late 1970s Imperial was testing a thermal Cyclic Steam Stimulation (CSS) process, aka "huff and puff" in the Clearwater formation at Cold Lake. In this three step process, you inject steam downhole at high pressure for several weeks, followed by several weeks of soaking to reduce the oil's viscosity, then you pump the heavy oil up using the same well.

Butler's radical notion for producing heavy oil by gravity drainage was at first scoffed at by the old hands at Cold Lake, but Butler wasn't deterred a bit. He was after a more efficient system that used continuous heating and production, rather than the six- to 18-month cycles with CSS, and one that lost less heat.

"Perhaps the steam will rise and the warm oil will fall," he mused.

He first tried injecting steam through one vertical well, letting the reservoir heat up and drain, then pumping the recovered oil to the surface through another vertical well. The results weren’t promising. He reckoned that the oil was trickling down through the sand in an ever-narrowing cone, and more sand was plugging up the well used to pump oil to the surface. "When you're extracting oil from in situ oil sands, the chamber (created by steam injection) is full of sand," Butler said. "The oil has to move through the sand and gather on the bottom of the chamber ... but gravity won't assist the flow on a vertical well." So Butler had his “Eureka!” moment, that vertical well production rates were too low to make SAGD economically viable. But a perforated horizontal well might be the ticket.

Butler then asked Imperial to drill a horizontal production well low in the reservoir, just above the limestone bedrock, with numerous drainage points along its entire length to capture the oil. “I could get a thousand barrels a day out of one of these wells on my paper calculations."

1982 SAGD Patent (University of Calgary)
1982 SAGD Patent (University of Calgary)
In 1978, Butler had numbers to support his idea, but Imperial moved like molasses, prompting him to get up in a high-level meeting and exclaim: "What the hell's the point of doing all this research if you fellas won't do something in the field?"[6]

Butler finally persuaded Imperial to drill what was the world’s first modern horizontal oil well paired with a vertical steam-injection well. The horizontal well was about 150 meters long, and “The oil came out at about the right rate—I felt pretty damn good!” But a thousand barrels a day from 150 feet was too marginal for Imperial. Oil prices were dropping, most Cold Lake engineers were wedded to CSS, and Imperial put Butler's project on the back burner.

Butler grew convinced that vertical wells were the problem, but with little further support from the company[7], he took early retirement and joined his friend Clem Bowman at the Alberta Oil Sands Technology and Research Authority (AOSTRA) for about a year, where he convinced them to test and refine the SAGD process at the organization’s Underground Test Facility (UTF) near Fort McMurray. In 1983, Butler was appointed to the University of Calgary's first Endowed Chair in Petroleum Engineering.

Full Steam Below

In their first SAGD experiment, in 1987, UTF engineers drilled three of Butler's proposed twin horizontal wells from mine shafts 200 meters down, just above a tunnel dug in the limestone underburden. The first tests immediately proved the feasibility of twin well SAGD, and there was some quiet excitement in the industry when the UTF crew found they could recover about 60% of the bitumen in place. The UTF even went into the black in 1992, achieving positive cash flow producing at a rate of about 2000 barrels a day from 3 well pairs.

Another image of the UTF
Another image of the UTF
Several years of testing followed. The engineers injected steam at various pressures, and then went under the wells to measure the actual results of their work. They finally got the best results - over 60% extraction - when they injected steam at below fracture pressure. This way it stayed contained within the depletion zone or steam chamber, which got bigger as the warm bitumen drained out, just like Butler's old Saskatchewan potash well. This further enhanced SAGD's heating efficiency. They also found that the parallel orientation between the injector well and the producer well had to be precisely controlled, and kept about five meters apart. Refining the process further, they also came up with ways to control sand infiltration and prevent steam from entering the producing well bore. Beginning in 1996, the UTF engineers moved up to the surface, where they drilled several well pairs, and found to their delight that they performed as well as those drilled from the tunnels.

These AOSTRA tests gave far better results than expected and the timing of the SAGD discovery was perfect as well. While Butler was testing his process, oils service companies like Schlumberger were coming up with very sophisticated directional drilling technology. Suddenly you could drill horizontal wells accurately, cheaply and efficiently. So with this drilling revolution, lower capital costs and the very high recovery rates Butler's process was showing, the majors as well as many independent oil companies started to move quickly in the direction of SAGD. You could get into the oil sands business for $30,000 per flowing barrel, compared to $126,000 per flowing barrel for an integrated mine and upgrader.[8]

At the same time, AOSTRA developed a computer simulation program that it provided to companies so they could optimize the design and operation of their own thermal projects.

SAGD Growth
SAGD Growth
In 1985, EnCana, already a fan of horizontal drilling for gas, was first off the mark, starting its own advanced SAGD projects at Foster Creek and Christina Lake with partner ConocoPhillips. Petro-Canada followed with its MacKay River project, ConocoPhillips had a SAGD operation at Surmount, Suncor at Firebag, and OPTI Canada/Nexen at Long Lake, not to mention over a dozen smaller operations. It was soon found that one of the keys to high profit SAGD production is to have thick cap rock (usually shale, as in the Kirby Lease) to keep in the steam. Some companies were soon reporting high end recovery rates of over 70% of the bitumen in place. The first SAGD bitumen made it to market in late 2001.

SAGD technology also offered the oil patch some major advantages over the "huff and puff" in situ process, including lower steam-oil ratios and lower pressure needs, which cuts operating costs. SAGD has also allowed thermal recovery to be extended far beyond the thicker and deeper pay zones such as Cold Lake and Peace River.

The SAGD experience however has not all been rosy. When Suncor's 90,000 barrels a day Firebag project opened, engineers miscalculated the amount of sulphur the bitumen would produce during upgrading, and an "odor problem" resulted. The Alberta Energy Resources Conservation Board ordered a 50% cutback until the problem was fixed. Suncor is now building its huge $20.6-billion Voyageur project, which will cost $9 billion for SAGD wells and surface facilities at Firebag and $12 billion for an upgrader. Production should rise to 370,000 barrels a day, rivaling the volume produced at the strip mine, when the project is complete in 2012.

MacKay River Wellhead
MacKay River Wellhead
Suncor is now the owner of the MacKay River SAGD site, with its purchase of Petro-Canada. Phase 1 performed well, with output rising toward 30,000 barrels a day. But with rising costs and Alberta’s decision to raise royalties, Phase 2 is in a holding pattern.

Husky Energy’s Tucker project also had problems with positioning its first wells, leading to "massive thermal inefficiencies, with heat being lost to the water at the bottom of the reservoir rather than soaked up by the bitumen in the pay zone," according to engineers at Calgary-based Ross Smith. Husky has learned from its experiences, and is fixing the problem, expecting to recover about 352 million bbls of bitumen over the next 35 years.

Encana has been getting good results by growing in consecutive phases of 30,000 barrels a day, and is aiming for production of 435,000 barrels a day (gross) by 2016, including 180,000 bbls a day from Foster Creek and 220,000 bbls a day from Christina Lake, both owned 50/50 with ConocoPhillips, plus EnCana’s wholly owned Borealis project coming on-stream in 2015, which will produce 35,000 barrels a day. Encana also operates the Senlac project in Saskatchewan.

Perhaps the worst SAGD experience happened at Total’s Joslyn SAGD project in northeastern Alberta in May 2008, when pressurized steam burst up through the thin cap rock, blasting out a crater 20 meters wide and five meters deep. No one was hurt in the blast.

The Ongoing Steam Problem

Firebag Well Pad
Firebag Well Pad
The major downside of SAGD and CSS is that they are voracious consumers of natural gas. In a mine like Syncrude more and more of the energy consumed is self-generated fuel gas and coke produced from upgrading. As Syncrude's Jim Carter says, "We could get off the natural gas pipeline. By just gasifying more of the heavy end of the barrel, we'd likely take out asphaltinenes. We can gasify those. But it's big capital investment and it doesn't make sense as long as gas prices are in the range that we are seeing them in today."[9]Syncrude mainly imports natural gas to provide hydrogen for upgrading its heavy crude. But most SAGD companies have to import gas to make steam for melting oil off sand, to generate electricity for their operations, and to create the hydrogen needed if they upgrade the bitumen.

Producers need to be near a source of fresh or brackish water and build large water recycling facilities to generate the copious amounts of needed hot water and steam. However, SAGD is proving more environmentally friendly than mining, and only disturbs only about 15% of surface land in the area. Drill pads and other facilities are laid on gravel pads, and the whole operation, including gravel, can be moved when the deposit is steamed out. No additional surface or groundwater is needed, and there is no need for tailings ponds. Suncor's Firebag also husbands energy, by recycling water in a closed system to generate steam.

A mine like Syncrude reuses 88% of all the water required for extraction. It currently pulls 36 million cubic meters from the river, but also uses its stored 256 million cubic meters of water that it continuously cycles through the extraction process.

Cost by Recovery Type (NEB)
Cost by Recovery Type (NEB)
Gas is a major governor of the industry, and higher gas prices have the potential to seriously slow down Sands development. A gas cost of US$5.00 per barrel of SAGD bitumen is decent, but SAGD economics don't look very good at twice the price, unless of course the price of oil goes up concurrently.

In 2007, oil sands producers sucked in 13% of Canada’s natural gas, enough to heat six million average-sized homes. With the rise of SAGD, demand from the Sands has nearly tripled to 1.1 billion cubic feet (bcf) a day. Natural Resources Canada estimates that by 2030 the Sands could consume five times more - up to 60% of Canada’s annual natural gas supply. This pinpoints the urgent need to engineer new upgrading and energy technologies.

Nuclear is being talked about for power, but most people in the oil patch prefer to invest in gasification. They don't trust the nuclear option, and think it's too expensive. However, Calgary's Canadian Energy Research Institute (CERI), says that 20 to 25 nuclear reactors could serve all the industry's needs. French oil company Total says that to produce its planned 200,000 barrels a day, it will need at least 3,300 metric tonnes of steam per hour, or the output of a 2,600 megawatt power plant.

The fuel would be easy to get - the nearby Key Lake mine in Saskatchewan is the largest uranium milling operation in the world and can supply 16% of global production. Ontario's Bruce Power and French nuclear giant Areva are standing by, waiting for the call.


Thermal Solvent Process (Laricina)
Thermal Solvent Process (Laricina)
Since natural gas makes up nearly two-thirds of the entire operating expense of a SAGD facility, the threat of rising prices has prompted a search for sustainable ways to generate and recycle heat. Several newer steamless in situ technologies have been tried out as well, and several patented. Roger Butler also developed the VAPEX process - vapor-assisted petroleum extraction - that injects cold solvents like ethane or propane, instead of or along with higher cost steam, to displace oil and reduce its viscosity in a vapor chamber. When the heavy oil surfaces, the solvents are stripped off and recycled. VAPEX requires no water, no processing nor any recycling and is 25% lower in capital costs than the SAGD process. Operating costs seem to be 50% less than the SAGD process.

In Situ Combustion (ISC) is another way forward. One patented process, ET-DSP, uses electrical heating to get bitumen to flow into simple vertical wells. The process involves passing an electrical current through large vertical underground electrodes placed in a grid pattern. Supporters claim this technology can produce an equivalent volume of bitumen in a tenth of the time required by SAGD, while using substantially less energy and water.

Petrobank Energy is using a promising ISC approach, called THAI (for Toe to Heel Air Injection), which also relies on horizontal wells, and uses no water for production. The operator injects compressed air to generate a slow fire flood underground that drives oil to the extractors. The THAI process may have higher recovery rates and lower costs than SAGD, due to the minimal use of natural gas and water. It also has lower greenhouse gas emissions. THAI technology can also operate in reservoirs that are lower in pressure or quality, or have more shale.

Petrobank Whitesands THAI (Toe to Heel Air Injection) Project
Petrobank Whitesands THAI (Toe to Heel Air Injection) Project
“Combustion has always been seen as the Holy Grail because it’s more efficient,” says Chris Bloomer, Petrobank VP and director of heavy oil. “But it’s hard to manage.” The company found that vertical wells didn't work out because “In a vertical injection well, you don’t produce combustion air,” Bloomer said. “You have to keep injecting more and more air to keep up a steady flow.” Under these conditions, the combustion heat dropped, failing to completely consume all the oxygen. “That led to oxygenated hydrocarbon compounds—emulsions—that were difficult to process.”

In the early 1990s, Malcolm Greaves, professor of chemical engineering at the University of Bath, found that a vertical injection well at the toe of a horizontal production well at the bottom of the reservoir could control the combustion air and use it as a way to lift the oil. Says Bloomer “You’re always having fresh air, so you can sustain high temperatures and can manage the combustion front more efficiently.” Petrobank has done two successful pilot projects so far, starting with electricity off the Alberta grid to power its air compressors. The THAI process partially upgrades hydrocarbons in the reservoir by burning through the lowest-grade fraction, especially coke, which saves diluent costs during processing. It also releases gases that can be used to fuel the compressors. “In a larger, commercial project, we will be self-sustaining," says Boomer, "We’ll produce upgraded oil and our own power."[10]

The Nexen/OPTI Solution

Nexen-Opti's OrCrude Closed-Loop SAGD (Animation HERE)
Nexen-Opti's OrCrude Closed-Loop SAGD (Animation HERE)

One of the most promising ways out of the natural gas dilemma is a closed loop SAGD process Nexen is perfecting at Long Lake.

The Long Lake SAGD and upgrading project, a 50/50 joint venture of Nexen Inc. and OPTI Canada Inc., was sanctioned in February 2004, with a projected cost of $3.4 billion. It uses patented technology to produce its own fuel from gasified bitumen.

Unfortunately the project ran into serious delays and a huge cost overrun, to over $6.1 billion, mostly due to the construction boom and the cost of labor and services. But the company also decided it had to add more steam generation capacity and a sulphur recovery unit at a cost of $400 million. When it started up in August of 2008, Long Lake was only producing half the bitumen needed by the upgrader, and had to buy from other producers.

Long Lake’s 81 well pairs have an intended capacity of 72,000 bbls of bitumen a day, which will be converted to 60,000 bbls a day of synthetic crude oil.

Unlike conventional SAGD operations, Long Lake uses feedstocks derived from its own bitumen to fuel the project, which will give Long Lake the SAGD industry’s lowest operating costs, and perhaps point the way to a more self sustaining industry.

Today there are now more than 50 SAGD operations in the Sands, learning by doing, and moving up the learning curve. It's estimated they will be producing more than a million barrels of bitumen a day by 2012.

Roger Butler RIP

So what of the inventor, the Father of SAGD? There are those in the engineering community who speak Roger Butler's name with hushed reverence, but Butler was always modest about his fantastic discovery. He was quite proud of what he had done, and often cracked that Imperial Oil had missed the bucket by not continuing his research. Butler always showed visiting reporters and pilgrims to his home two bottles filled with sticky black liquid. One contained the first heavy oil from Cold Lake; the second, a bottle he calls "more precious than all the finest scotch on the planet". It held the very first heavy oil produced in the world using Steam Assisted Gravity Drainage.[11]

Dr. Roger Butler, the inventor of the SAGD and related VAPEX processes, died in May of 2005. He was on vacation in Hawaii with his wife, who had Alzheimer's Disease, when he suffered a stroke and fell to the ground. His cell phone had fallen out of his pocket, and thinking quickly, he speed-dialed his son Peter in Vancouver and told him to dial Honolulu 911. He was taken to hospital and given treatment, then airlifted to Calgary, where he suffered a final fatal stroke.


  1. See for example, Schlumberger Directional Drilling
  2. Bitumen is not equivalent to oil: it takes 1.2 barrels of bitumen to make one barrel of synthetic crude.
  3. Tom Kayser. Roger Butler: Father of SAGD. Energy Processing Canada, March 1 2005
  4. Mark Lowey. An Interview with Roger Butler, Alberta Oil Magazine, April 1, 2006
  5. Conversation with Bill Sande, who was Butler's director at the time.
  6. Tom Keyser. Roger Butler: Father of SAGD. Business Edge, May 2, 2005
  7. Imperial suspended the $12 billion Cold Lake project in 1981, and scaled it down for a time, but ramped it back up again when prices rebounded.
  8. Cambridge Energy Research Associates. Growth in the Canadian Oil Sands (2009), 18
  9. Marsden, Stupid to the Last Drop, 162.
  10. Bridget Mintz Testa, "Tar on Tap", Power & Energy, December, 2008
  11. An Interview with Roger Butler, Alberta Oil Magazine, April 1, 2006

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