Emissions from flaring, or burning of natural gas, methane and hydrogen sulphide associated with oil production, have risen in each of the last three years as drillers increased activity and the government failed to implement new industry targets.

“There’s no new absolute target to reduce flare or vent emissions,” said James Vaughan, who works at the Alberta Energy Conservation Board’s surveillance branch, in an interview. “The economics for conserving gas just doesn’t seem to be there” because of a decline in natural gas prices.

Flaring by companies including Husky Energy Inc. (HSE) is rising even as the Canadian government touts the country’s efforts to limit emissions to win support for TransCanada Corp. (TRP)’s Keystone XL pipeline. Prime Minister Stephen Harper met his European counterparts last week in Paris and London, appealing for them to stop EU plans to single out Alberta as a source of high-polluting energy.

Environmental groups such as 350.org and the Sierra Club have lobbied President Barack Obama to reject the Keystone XL pipeline, which would carry crude from Alberta to U.S. Gulf Coast refineries, saying that oil-sands production has a larger climate-change impact. Globally, about 5.3 trillion cubic feet of gas is flared annually, the equivalent of 25 percent of U.S. consumption of the fuel, according to the World Bank.

Surging Production

With bitumen production expected to surge to 6.7 million barrels a day by 2030, flaring and venting will continue to rise without new regulations, said Chris Severson-Baker, managing director of the Pembina Institute, a Calgary-based environmental research group and consultancy.

Flaring and vented gas from crude oil and bitumen production increased 66 percent between 2009 and 2011, the most recent figures available, according to ERCB data. The upward trend continued last year, according to preliminary data from the regulator.

Previous declines from 1996 to 2009 resulted from the implementation of recommendations from an alliance of non-governmental groups, industry, the public and government, known as the Clean Air Strategic Alliance, helping Alberta achieve the most “comprehensive” enforcement rules to manage flaring globally, according to a 2004 World Bank report.

Negative Impacts

Emissions from flaring in Nigeria have “negative impacts” on lung function, according to a report in the Research Journal of Environmental Earth Sciences published on March 8, 2012. Inhaling vapors associated with heavy-oil production may result in nose and throat irritation, headaches and nausea, Baytex Energy Corp. (BTE), a Calgary-based producer, said on its website.

A 2005 report by the Environmental Rights Action and Climate Justice determined gas flaring in Nigeria’s Bayelsa State likely causes 49 premature deaths and respiratory illnesses in 5,000 children annually.

Alberta, home to Canada’s oil and gas industry, relies on companies to determine whether capturing, burning or releasing gas, known as venting, is “economically viable,” said the ERCB’s Vaughn. A combination of measures, including a previous emissions target for the industry, allowed Alberta regulators to slash flaring emissions by 80 percent between 1996 and 2009.

Progress Imperiled

That progress is at risk without stiffer regulations and targets, said Severson-Baker.

“We knew because of industry trends that flaring and venting was likely to start climbing upwards,” he said in an interview. “When it came right down to it, industry wasn’t able to spend more money on flaring and venting abatement and the government wasn’t prepared to push any further.”

Canadian Natural Resources Ltd. (CNQ) was responsible for the largest volume of flared and vented gas in the province in 2011, followed by Husky, according to regulatory data. Smaller companies including Manitok Energy Inc. (MEI) flared more gas as a proportion of their production.

Massimo Geremia, chief executive officer of Manitok, didn’t respond to a request for comment. Husky spokeswoman Kim Guttormson declined to comment. Canadian Natural Resources declined to comment.

Alberta’s energy regulator is tabling new rules, expected by the end of the year. An increase in operators drilling oil wells with small volumes of associated gas, which is difficult and expensive to capture, has also contributed to the rising flaring and carbon dioxide emissions, said Vaughn.

Open Wounds

“We are looking at expanding the test to look at other parameters to take into account something outside of economics,” he said. “When the public comes to us and asks why isn’t this facility conserving and we go back to them and say the economics aren’t there, that’s a hard pill for the public to swallow.”

Those issues have surfaced in the Peace River district in an area called Three Creeks. For Thera Breau, the increased heavy oil production and flaring has coincided with open wounds and eye problems for her four sons, all under the age of seven.

“My baby had a red spot behind his knee and by the end of March the blotch spread to the other leg,” Breau, a 36 year-old physiotherapist, said in an interview. “All the gas is free-vented and free-flared. The regulations are lagging.”

Leaving Home

Breau is among half a dozen families who have left their homes in the Peace River area to get away from the fumes and bad smells, she said. Neighbors Marcel and Vivianne Laliberte in October left their farm where family members have grown grains since 1928 after suffering from bleeding noses, headaches and swollen glands.

“It’s a heart-breaking situation,” said Vivianne Laliberte, in a phone interview. “Proper monitoring is not being done and people’s concerns are being disregarded.”

Baytex voluntarily halted its drilling program in the area near Three Creeks about a year ago and added equipment to capture gas and a pipeline system to use or sell about 1 million cubic feet of gas daily that would have previously been vented, said Brian Ector, a Baytex spokesman.

“We’ve put a lot of time and effort into reducing the amount of venting and reducing the emissions and reducing the odors up at Peace River,” he said.

Baytex captured almost 95 percent of the gas produced during oil extraction at its operations across Alberta, better than the industry average, according to ERCB data from 2011.

“We have always been fully compliant with the ERCB regulations, but we want to go above and beyond that,” Ector said.

North Dakota

Alberta isn’t the only jurisdiction in North America wrestling with rising flaring and venting emissions.

Oil production in North Dakota has tripled since 2010 to 718,790 barrels a day in March and companies are flaring about 30 percent of the associated gases, said Ryan Salmon, director of the oil & gas program at Ceres, a network of investors that promotes sustainability through the adoption of environmentally friendly business practices.

“You can’t underestimate how much is going up in flames-- $1 million a day alone in North Dakota,” he said. “Reluctance on the part of companies comes down to near-term economics of getting infrastructure in place. You need to have both voluntary actions and regulation.” Ceres represents investors with $11 trillion worth of assets.

Oil producers can reduce flaring by connecting the produced gas to pipelines and selling or using the gas. If that’s not economic or practical, the “next best” option is to make sure the waste gas is combusted at the well site using high-efficiency gas incineration equipment to destroy volatile organic chemicals, said Audrey Mascarenhas, chief executive officer of Calgary-based Questor Technology Inc. (QST), which manufacturers gas-incineration equipment.

“Many will see the waste gas as still being combusted, however, when combusted at high efficiency the waste gases are being reduced to benign elements,” she said. “That is not happening now.”

Every fracking job requires 2 million to 4 million gallons of water, according to the Groundwater Protection Council. The Environmental Protection Agency, or EPA, has estimated that the 35,000 oil and gas wells used for fracking consume between 70 billion and 140 billion gallons of water each year. That’s about equal, EPA says, to the water use in 40 to 80 cities with populations of 50,000 people, or one to two cities with a population of 2.5 million each.

Some of the most intensive oil and gas development in the nation is occurring in regions where water is already at a premium. A paper published last month by Ceres, a nonprofit that works on sustainability issues, looked at 25,000 shale oil and shale gas wells in operation and monitored by an industry-tied reporting website called FracFocus. Ceres found that 47 percent of these wells were in areas “with high or extremely high water stress” because of large withdrawals for use by industry, agriculture, and municipalities. In Colorado, for example, 92 percent of the wells were in extremely high water-stress areas, and in Texas more than half were in high or extremely high water-stress areas.

“Given projected sharp increases in production in the coming years and the potentially intense nature of local water demands, competition and conflicts over water should be a growing concern for companies, policymakers and investors,” the Ceres report concluded. It goes on to say that:

Prolonged drought conditions in many parts of Texas and Colorado last summer created increased competition and conflict between farmers, communities and energy developers, which is only likely to continue. … Even in wetter regions of the northeast United States, dozens of water permits granted to operators had to be withdrawn last summer due to low levels in environmentally vulnerable headwater streams.

Another recent study by the University of Texas looked at past and projected water use for fracking in the Barnett, Eagle Ford, and Haynesville shale plays in Texas, and found that fracking in 2011 was using more than twice as much water in the state as it was three years earlier. In Dimmit County, home to the Eagle Ford shale development in South Texas, fracking accounted for nearly a quarter of overall water consumption in 2011 and is expected to grow to a third in a few years, according to the study.

Moreover, an April report by the Western Organization of Resource Councils found that fracking is using 7 billion gallons of water a year in four western states: Wyoming, Colorado, Montana, and North Dakota. “Fracking’s growing demand for water can threaten availability of water for agriculture and western rural communities,” said Bob Leresche, a Wyoming resident and board member of the group.

The national oil and gas trade association, American Petroleum Institute, correctly notes that the “industry’s water use is small when compared to other industrial and recreational activities.” But even though hydraulic fracturing usually accounts for just 1 percent or 2 percent of states’ overall water use, the Ceres study notes that “it can be much higher at the local level, increasing competition for scarce supplies.”

New ways to frack

Not surprisingly, the oil and gas industry, along with companies drawn by the opportunity to profit from a better way to frack, are all seeking ways to reduce and even eliminate fracking’s thirst.

A new company in Texas, Alpha Reclaim Technology, sees using treated wastewater from municipal sewage-treatment plants as part of the answer. Founded in 2011, the company has signed up cities to provide about 21 million gallons of treated wastewater a day and is negotiating with oil and gas exploration and production companies to make the switch in the Eagle Ford shale play.

With regard to water use and fracking, Jeremy Osborne, the company’s vice president and general counsel, says, “We are really in a collision course here in Texas”—a course he says is accelerated by drought and population growth.

But Jillian Ryan, Alpha Reclaim Technology’s vice president for government affairs, said changing longstanding practices in the oil and gas industry can be a challenge. While the industry talks a good game about conserving water, Ryan says, “We can have a hard time getting oil and gas companies to live up to what they are talking about. Nobody wants to change. It’s easier to drill a water well where they are drilling [for oil and gas].”

Another player in this oil and gas niche is GASFRAC Energy Services, a Canadian company that says it has successfully fracked about 2,000 wells using liquid propane gas in place of water. Most of these wells are in Canada, but about 100 of them are in Texas.

Environmentalists and fracking critics, however, are alarmed at the thought of fracking with propane. Prompted by the possibility that GASFRAC would be employed in New York state and could evade a state moratorium on fracking by using propane instead of water, environmental groups, including the Sierra Club and the Natural Resources Defense Council, protested to the commissioner of the state’s Department of Environmental Conservation. Similar to water-based fracking, the groups said, fracking with propane also requires “the addition of toxic chemicals.” Because GASFRAC’s method is proprietary, the groups said in their letter that “there is little publicly-available information on the process” and the exact chemicals it uses.

Propane is also very flammable, and in two cases in Alberta in 2011, fires broke out during GASFRAC fracking operations, injuring a total of 15 workers.

Cornell University engineering professor Anthony Ingraffea is among those who are very skeptical of fracking in shale formations with propane and other alternatives to water. Ingraffea has been studying fracturing since doing research for his doctorate in the 1970s. He finds that even modern fracking practices, using millions of gallons of water per well to yield what he says is just 10 percent to 15 percent of oil and gas out, are “very inefficient and inelegant.”

Using propane or a propane-butane combination, Ingraffea says, has a positive side in that it eliminates a key problem with water-based fracking: the disposal of vast quantities of flowback water that returns to the surface after fracking is completed and is often contaminated with things such as salts and radioactivity.

But, he added, no one has yet clearly demonstrated that fracking with propane or some of the other alternatives—such as using a nitrogen or carbon dioxide gel—can compete on economics with water. Propane, he said, “is expensive and nobody really knows how much it takes to develop a typical shale gas well with a lateral that is a mile or two long.”

Oil and gas service companies such as Halliburton and Schlumberger have thrown a lot of money and bright minds at seeking efficiencies over many years, said Ingraffea, and if there was a “silver bullet you would think those companies would have hit it very hard.”

As the Ceres report concludes:

Shale energy development highlights the fact that our water resources were already vulnerable before additional demands were introduced. Regulators, water managers and ultimately all significant economic players who rely on abundant supplies of water must double-down their efforts to better manage this limited and most precious resource.

Tom Kenworthy is a Senior Fellow at the Center for American Progress.

“Given projected sharp increases” in the production of oil and gas by the technique commonly known as fracking, the report from the group Ceres said, “and the intense nature of local water demands, competition and conflicts over water should be a growing concern for companies, policy makers and investors.”

The overall amount of water used for fracking, even in states like Colorado and Texas that have been through severe droughts in recent years, is still small: in many cases 1 percent or even as little as a tenth of 1 percent of overall consumption, far less than agricultural or municipal uses.

But those figures mask more significant local effects, the report’s author, Monika Freyman, said in an interview. “You have to look at a county-by-county scale to capture the intense and short-term impact on water supplies,” she said.

“The whole drilling and fracking process is a well-orchestrated, moment-by-moment process” requiring that one million to five million gallons of water are available for a brief period, she added. “They need an intense amount of water for a few days, and that’s it.”

One of the options that oil and gas drillers have is recycling the water that comes back out of wells, which is called “produced water.” But the water injected into wells is laced with a proprietary mixture of chemicals and sand, and the water returning from thousands of feet below the surface can also contain natural pollutants or even radioactivity. Recycled water must therefore be treated, which can be expensive.

An earlier report done by engineers at the University of Texas, Austin, showed that 8,800 acre-feet — nearly 2.9 billion gallons — were used for fracking in 2011 in Tarrant County in North Texas, where Fort Worth is located and which has gone to the Supreme Court to get access to Oklahoma’s water.

And in the Eagle Ford shale formation in South Texas, particularly in Webb County, some researchers estimate that the amount of water used for fracking represents as much as one-third of the area’s annual groundwater recharge, the amount of surface water that percolates back to the underground aquifer supplying the region.

But the Ceres report notes that drillers in the Eagle Ford formation are also expanding their use of brackish, undrinkable water in place of fresh water.

While the local effects in Texas have been sufficient to spur the state’s Railroad Commission, which regulates the oil and gas industry there, to encourage recycling by loosening rules governing that process, it is Colorado that faces the most widespread potential conflicts between fracking and other water uses, according to Ceres’s new report.

Kenneth H. Carlson, an engineering professor at Colorado State University, saw little difference between drillers buying needed water and cities buying water from farmers. “It’s a private commodity that people can do with what they want,” he said. “We’re not going to go thirsty. We’re just going to have to pay more.”

A new Ceres research paper on water use in hydraulic fracturing operations shows that a significant portion of this activity is happening in water stressed regions of the United States, most prominently Texas and Colorado, which are both in the midst of prolonged drought conditions. It concludes that industry efforts underway, such as expanded use of recycled water and non-freshwater resources, need to be scaled up along with better water management planning if shale energy production is to grow as projected.

The report, announced today, is based on well drilling and water use data from FracFocus.org and water stress indicator maps developed by the World Resources Institute (WRI). The research shows that nearly 47 percent of the wells were developed in water basins with high or extremely high water stress. The research was based on FracFocus data collected on 25,450 wells in operation from January 2011 through September 2012.

“These findings highlight emerging tensions in many U.S. regions between growing hydraulic fracturing activity and localized water supply needs,” said Ceres president Mindy Lubber, in announcing the report, Hydraulic Fracturing & Water Stress: Growing Competitive Pressures for Water, at Ceres’ annual conference in San Francisco.

FracFocus.org was launched in 2011 as a voluntary national hydraulic fracturing chemical registry. The database provides the location and date that each oil and gas well was developed and the chemical additives and total volume of water injected down each well.

WRI’s water stress indicator maps are part of a recently launched Aqueduct Water Risk Atlas, which provides a comprehensive, high-resolution picture of water-related risks worldwide. The baseline water stress indicator maps show the level of competition for water in different U.S. regions by measuring total annual water withdrawals against the percentage of water that is available.  Extremely high water stress means over 80 percent of available water is already being allocated for municipal, industrial and agricultural uses.

By linking the two datasets together through matching latitude and longitude coordinates, the report provides valuable insights about the extent and distribution of well production activity in regions with water competition challenges.

Colorado and Texas showed the highest  exposure to water stress. In Colorado, 92 percent of the wells were in extremely high water stress regions. In Texas, which accounts for nearly half of the total wells analyzed, 51 percent of the wells were in high or extremely high water stress regions. In some Texas counties, water use for hydraulic fracturing accounted for more than 20 percent of the region’s total water use. In Pennsylvania, 70 percent of the wells were in medium to high water stress water basins and only 2 percent were in high water stress basins.

“Given projected sharp increases in shale oil and gas production in the coming years, competition over water should be a growing concern to energy companies, policymakers and investors,” the report concludes, noting a projected doubling of oil and gas fracturing production in the coming years. “Shale energy development cannot grow without water, but in order to do so the industry’s water needs and impacts need to be better understood, measured and managed.”

As the report outlines, the industry has made progress in boosting the use of recycled water and other alternative water sources for fracturing wells. Operators are starting to use non-freshwater alternatives such as wastewater, saline water, seawater and acid-mine drainage. “Overall water recycling and the use of non-freshwater sources must increase considerably to have a significant impact,” the report says.

The report includes key recommendations for companies and regulators, among those:

• Comprehensive mandatory disclosure by companies of how much freshwater, non-freshwater and recycled water they are using region by region as well as how much water is returning to the surface and where it is ending up.
• Requirements for companies to set quantifiable water use targets, including recycling and non-freshwater use targets.
• Ensure that both companies and local regulators are conducting sufficient water management planning.
• Ensure that companies have a local stakeholder engagement process in place on water issues.

Other investor focused initiatives, such as the Interfaith Center for Corporate Responsibility and the Investor Environmental Health Network's Extracting the Facts (see their goal 6) have been pushing for better water sourcing disclosure along with other engagement recommendations on mitigating environmental and community impacts.

Today’s report is part of a larger, more comprehensive study Ceres is undertaking to analyze water risks across the entire hydraulic fracturing lifecycle – from water sourcing to final treatment and disposal of wastewater – across different regional basins in North America. The research is aimed primarily at investors who have financial stakes in operators and support services in these regions.

About Ceres

Ceres is an advocate for sustainability leadership. Ceres mobilizes a powerful coalition of investors, companies and public interest groups to accelerate and expand the adoption of sustainable business practices and solutions to build a healthy global economy. Ceres also directs the Investor Network on Climate Risk (INCR), a network of 100 institutional investors with collective assets totaling more than $11 trillion. For more information, visit http://www.ceres.org