Oil patch flares -- their flames lighting the darkness or their plumes sometimes smudging a blue Prairie sky -- have been a part of the Alberta landscape for years. Like the smoke belching from chimne...
Oil patch flares — their flames lighting the darkness or their plumes sometimes smudging a blue Prairie sky — have been a part of the Alberta landscape for years. Like the smoke belching from chimneys in industrial heartlands, flares have been comforting signs of a humming economy.
These days there are fewer flares at Alberta’s upstream oil production sites, but that does not signal less oil sector activity. Rather, it reflects efforts by industry — sometimes nudged by regulators and public opinion — to reduce the amount of solution gas flared.
One factor driving this reduction has been the public’s concerns about the health and environmental effects. When Wiebo Ludwig went on trial last year, the whole country learned of his suspicions about the harmful effects of sour gas flaring. The Hythe-area farmer believed that local flaring had caused miscarriages among the women in his family and his cattle. He was convicted for attempting to sabotage the property of neighbouring oil producers. Whether Ludwig’s fears are well founded or not, governments intend to investigate the health ramifications of flaring. The Alberta Environment ministry announced in April that the four western provinces will sponsor a three-year, $20.5 million study of the effects of oil and gas flares on humans and animals.
Whence the problem?
Solution gas rises from crude oil as it is pumped out of the ground and sent to batteries of holding tanks. More than 90% of the gas is captured and piped off to natural gas processing plants for sale, but when quantities are too small or too distant from collection points, the gas is a waste product.
Province-wide, about one third of the solution soup is “sour gas,” i.e. gas that is high in hydrogen sulphide, has a rotten egg smell, and is toxic and corrosive. Flaring converts the solution gas to less harmful gases such as carbon dioxide and sulphur dioxide, and while these gases may not be particularly desirable from a greenhouse and acid rain point of view, they are less immediately toxic than hydrogen sulphide.
A problem with flaring, however, is that the combustion is inconsistent and the burning efficiency may vary. The result is that hydrogen sulphide may be released along with hydrocarbons such as methane (a much more potent greenhouse gas than carbon dioxide) and benzene. Benzene has been linked with causing various types of leukaemia, lymphoma and blood diseases.
The energy factor
There are also concerns that oil patch flaring wastes energy. To encourage conservation, therefore, the search is on for alternative ways to make use of the gas, and some of these efforts may open opportunities for consulting engineers. Efforts are being put into increasing the amount of gas that is collected and piped to plants, for example, and also the gas is being used in microturbines to generate electricity. To encourage these types of recovery projects, the Alberta government gives a royalty holiday on the recovery of solution gas that is otherwise not economic to capture.
In July 1999, the Alberta Energy and Utilities Board issued the Upstream Petroleum Industry Flaring Guide, Guide 60. It set targets for the overall reduction of flaring — based on 1996 levels — of 15% by the end of 2000, and 25% by the end of this year. With last year’s target exceeded, and this year’s expected to be met, the Board is pushing for further reductions. Guide 60 imposes more stringent reporting requirements for gas flaring, as well as for gas venting (release without burning).
Though Guide 60 existed only for part of the period, between 1996 and 1999 the percentage of solution gas flared or vented and not conserved declined from 8% (1.8 billion cubic metres) to 6% (1.3 billion cubic metres). And between 1998 and 1999 there was a 5% reduction in the number of Alberta crude oil and bitumen batteries flaring or venting solution gas, to approximately 4,500 flares.
So far, the Energy Utility Board has relied on persuasion to make its point on Guide 60, and producers have reduced flaring mainly by adjusting existing systems. What is required is further innovation and site-specific solutions.
Despite the familiar presence of flares, until recently relatively little was understood about how their combustion efficiencies varied under differing atmospheric conditions. Dr. Larry Kostiuk, P.Eng., of the University of Alberta’s Department of Mechanical Engineering, leads an industry-government supported flare research project to understand better how fuel mixtures and ambient conditions affect flaring efficiencies.
“There is a need for better understanding of the selection of equipment for specific applications,” says Ian Potter, the Alberta Research Council’s manager of climate change technologies. He believes that some producers would have more confidence if there were clearer performance standards for equipment.
Realistically, some flaring is expected to continue, partly in connection with well testing, as a safety measure and at some remote production sites. Potter is seeking funding for a flaring mitigation centre. He sees the centre working toward improved guidelines and standards for flaring equipment and incinerators, as well as for microturbines and other alternatives to flaring.
Finding new ways to use the gas
“Guide 60 is causing a lot of producers to examine their flaring practices,” says Dan Motyka, P.Eng., president of Questor Technology, a Calgary company producing high-efficiency, portable incinerators for the petroleum industry. If venting is on the lowest rung of the ladder in terms of desirable ways of dealing with solution gas, these specially designed incinerators rank in the middle. They produce no visible flame and provide more complete and controlled combustion of the solution gases, so helping to get rid of odour problems. Incinerators are preferable to venting, but less desirable than collecting the gas and using it for electrical generation.
Aided by Alberta’s electrical de-regulation, which permits even small power producers to sell into the provincial grid, companies are using solution gas to generate electricity. Since this spring, PanCanadian Petroleum, for example, has had a dozen 30 kW Capstone microturbines burning 9,000 cubic feet of solution gas daily. The microturbines operate either as stand-alone units to supply power for pumps or other field operations, or as parallel systems feeding power into the grid.
Terry Becker, P.Eng., senior electrical engineer with PanCanadian Energy Services, dismisses skepticism about microturbines’ reliability and sees a double-win situation. “You can get rid of the flare and vent gas, and get some revenue at the same time,” he says. Since starting up its first units in November 1999, PanCanadian’s microturbines have racked up more than 40,000 cumulative hours in operation. Depending on the installation (grid parallel or stand-alone prime power), the units have run 95% of the time and produced electricity costing an average of 0.8 cents per kWh. Becker continues to work toward a reliable use of microturbines fuelled by sour gas. Importantly, the Capstone microturbines used by PanCanadian can be adjusted to run on a mixture containing up to 7% hydrogen sulphide.
Meanwhile, Mercury Electric Corporation, an independent power producer, positions skid-mounted microturbines at oil batteries. The Calgary company installs, operates and owns the units. By early this summer, Mercury expects to have installed about 60 of these Honeywell Parallon 75kW microturbines.
Microturbines are effective in dealing with relatively low volumes of solution gas. But with approximately 50 oil wells in the remote Gift Lake in north-central Alberta producing up to half a million cubic feet of gas a day, Northstar Energy Corporation installed a 750 kW-turbine manufactured by Solar Turbines. Other large producers have acquired turbines of similar size.
Stringing power lines to connect to the grid is a cost-effective alternative to trenching a gas gathering system. But thanks to the Guide 60 “stick” and the royalty relief “carrot,” more solution gas is bein
g gathered and piped out. Last fall, Talisman Energy, with Colt Engineering Corporation as its consultant, spent $11 million for piping and compressor systems to gather gas from 10 batteries serving 350 wells in its Chauvin field south of Lloydminster. The company sells 1.7 billion cubic feet of gas a year, gas that otherwise would be vented or flared.
These efforts by the oil industry to make better use of a by-product mean even fewer flares. And as the beacons are extinguished, one hears little of the sort of nostalgia voiced around the demise of another fast-disappearing Prairie icon, the country grain elevator.
Nordahl Flakstad is a freelance writer based in Edmonton.