A lot of us remember vividly the drought of 2011. It was the driest year in history, and cost the agricultural industry almost $8 billion. Entire towns lost their water supplies. Although we haven’t seen the non-stop 100-degree days to the extent we did in 2011, the drought is still with us. According to the Texas Water Development Board, the state’s reservoirs are only 63 percent full. That’s a continuing problem for agriculture, household water supplies, and energy.
That problem is compounded by the use of water in hydraulic fracturing, the process of injecting water and other chemicals under extremely high pressure into an oil well, cracking open the underground rock formations to free up the oil and natural gas deposits. A University of Texas study found that fracturing used 28 billion gallons of water in 2012, and predicted that water use would go up to 40 billion gallons by 2020. In some counties, fracturing accounts for a third of the total water use.
A Texas CEO Magazine Enlightened Speakers Series event in Houston featured three experts on different aspects of the water-energy nexus – Laura Capper, president of CAP Resources; Russell Johnson, a partner at McGinnis Lochridge; and, Dr. David Burnett, Director of Technology at Texas A&M’s Global Petroleum Research Institute.
Ground Water & Surface Water – Permits, Permits, Permits
Attorney Russ Johnson said the legal basis for using water comes from Texas’ unique classification of water: groundwater and surface water. Surface water is owned and regulated by the state; groundwater is owned by the landowner. But groundwater is also regulated at the local level, by one of the state’s 97 different groundwater conservation districts. Those districts, he said, can and do limit access to groundwater and regulate production from groundwater resources.
Traditionally, oil and gas operators have been exempted from getting permission to use groundwater for drilling activities. “The idea was that it shouldn’t delay
an operator in the process of completing a well by having to go to a groundwater conservation district for a permit,” Johnson said.
But that was before hydraulic fracturing came along. Now, Johnson said, about a dozen groundwater conservation districts say the exemption does not apply to groundwater used for fracturing.
“Operators need to pay attention to the legal requirements to access water,” Johnson said. “It’s the wild, wild West.” In some cases, operators are buying surface water if it’s available, without heeding the legal requirements for use of that water. The water might not be permitted for oil and gas operations.
“With the drought and the kind of scrutiny you’re seeing from the press, this question of where you got the water is going to become extremely relevant,” said Johnson.
Dr. David Burnett of Texas A & M said there’s plenty of water available “but it’s not exactly the kind we want and not exactly what we need.”
The industry has three sources of water for fracturing: groundwater, which is also used by municipalities to provide drinking water to people, and by agriculture to irrigate crops; brackish water containing small amounts of salt; and recycled water that’s been recovered from fracturing. Chemicals and rock debris are removed from the flowback, which leaves water that is still not usable for drinking or agriculture, but that can be reused in other fracturing operations.
One way for the industry to deal with the water issue is to make greater use of brackish water, said oil and gas consultant Laura Capper. Brackish water has a salt content of about five to 10,000 parts per million. While that level of salt wouldn’t be suitable for consumers, it will work well in the oil industry, Capper said.
Salinity levels vary widely across the oil-producing basins of the United States. They can range from relatively low levels in the Fayetteville shale formation of Arkansas to more than 25 percent (250,000 ppm) in the Marcellus play in Pennsylvania.
“That’s a big thing, a huge thing, to deal with,” Capper said.
In water-poor areas of West and South Texas, brackish water is being eyed as a new source of municipal drinking water. But the regulatory environment may throw a monkey wrench into that plan.
“With the advent of brackish water use, most of the groundwater conservation districts are taking the position they need to regulate the use of brackish water, too,” Johnson said. “Just because it’s brackish doesn’t mean it’s not regulated.”
“I can go to Carrizo Springs and tell them they have a drought proof water supply less than 6,000 feet away,” said David Burnett of Texas A & M. “I can do desalination and give them the fresh water and take the concentrated salt water and give it to the oil and gas companies who can use it with very, very little waste.”
But he said it’s not being done yet, because of the regulations Johnson referred to.
However, Burnett predicted that within five years, the oil and gas industry will not be using fresh water for fracturing.
“There’s zero reason to not be using brackish water now,” Capper asserted.
One of the biggest complaints about hydraulic fracturing is that water used for the procedure usually winds up in a disposal well, Johnson said. Texas has about 50,000 disposal wells. The Texas Railroad Commission, which regulates oil and gas, has recently amended recycling rules making it much easier for operators to recycle on site and on their own. “If you’re an operator and want to recycle, you don’t need to obtain a permit,” Johnson said. “We need to be serious about recycling and reusing water.”
Capper said Texas is already ahead of other states. “We have decent regulations here,” she said. “It’s horrific in Pennsylvania because many of their regulations prevent recycling.”
In Texas, Capper said about 60 percent of oil producing basins are in drought conditions, and high drought risk affects a lot of the more prolific basins. “We have to save the water and we have no choice but to reuse the water,” she said.
But reusing water from oil and gas wells is different than municipal water treatment. For years, Capper said, we’ve been able to treat the “nasty stuff” that comes out of our houses, and recycle it for reuse. That influent is consistent in grade – everything gets mixed together.
Oil and gas is different, because the influent from the wells is “lumpy,” as she put it. It’s made up of two distinct types: water used in the fracturing process and produced water with high salt content.
“One day a truck will pull up with drill water, another time it’s got produced water, another time it could be some type of completion fluid, so if you’re in the treatment business, you don’t typically get to be selective and say, ‘I’ll take X and Y,’ you take what’s presented to you and it’s very lumpy quality water,” Capper said.
In addition, one well might be tapping four or five different geologic strata, each with a different quality of water. The petroleum industry doesn’t have acres of settling ponds to treat water, Capper said. Water must be moved to the next well, where it can be reused.
Operators are spending $400,000-$450,000 per well to move water in the Permian Basin, Capper said. The best way to solve that problem is to replace trucks with pipelines. “Pipelines are not the enemy – trucking is,” said Capper. Although people might be up in arms about pipelines, Capper said they’re far preferable to thousands of trucks moving water.
Water management costs are just shy of $50 billion, Capper said, and 70 percent of that is going to trucking. “How do we use our resources more effectively?” she asked.
Burnett said oil and gas companies need to be good neighbors and be environmentally responsible. To put the environmental picture in perspective, Burnett said each well being drilled in South Texas, the Permian Basin and Barnett Shale is equivalent to a city of 4,000. “It’s comparable in the use of power, water, and the budget is about the same,” he said.
The Global Petroleum Research Institute at Texas A & M rates drillers based on their environmental performance. Companies can get five stars by using the best management practices for air emission reduction, water handling, footprint, remediation and safety, biodiversity and societal issues.
But, Burnett added, “Even though the industry is making a lot of money, you can’t sell environmental services unless they impact the bottom line positively.” For example, the Department of Energy has a research project to recover heavy metals from high salinity water, but no commercial company is involved because they can’t make money from it.
“What the Texas Recyclers Association is trying to do is to incentivize regulation,” Burnett said. “This may be the only time you hear ‘progressive’ and ‘Texas’ in the same sentence. The regulations that Texas is developing to incentivize recycling could be the model used by other states.”
Compared to agriculture, the oil and gas industry has a good story to tell, Johnson added. “A farmer growing 200 acres of corn is going to use ten times that amount of water every year, compared to a fracturing job that will use one-tenth that amount of water only once,” he said. “The industry has done a poor job of explaining the limited water impact of that process.”
Nov 14, 2015 Comments Off on 2016 Economic Forecast: Houston
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