Last fall, Texas Railroad Commissioner and former Midland resident David Porter appointed an Eagle Ford Task Force to discuss water quantity and usage as it relates to oil and gas production in the burgeoning Eagle Ford Shale in South Texas.
It is a critical issue facing all major producing basins in North America, including the Permian Basin, where a year-long drought has made the availability of water an important—if not the most important—topic of discussion for cities, agriculture, and industry, as well as the oil and gas business.
Porter’s 26-member task force came to a conclusion, based on information presented, that the Carrizo Wilcox Aquifer in South Texas appears to contain enough water resources to support oil and gas drilling activities, including hydraulic fracturing, in the Eagle Ford Shale while meeting all other projected uses.
The Texas Water Development Board, however, delivered its 2012 State Water Plan to Gov. Rick Perry on Jan. 5. The report conveyed a simple but somber message: Texas does not have enough water in drought conditions.
So what about the Permian Basin? Is there enough water to support the booming Wolfberry and Bone Spring plays at a time when lakes are drying up and cities like Midland are worried about running out of drinking water?
That is a difficult question, according to L. Peter Galusky, an environmental engineer who owns Texerra, a consulting firm with offices in Midland and Monument, Colo. Galusky was the lead speaker at the Permian Basin Oil and Gas Industry Water Use Symposium held in December at Midland College.
“I presented a summary of work I did a year-and-a-half ago for the Texas Water Development Board with an estimate of water use by the oil and gas industry,” he stated. “But that work didn’t encompass or foresee water use by these new fracs. So, really absent of having a handle on how much fresh water the industry is using in these new plays, I don’t have an estimate.”
Galusky said he simply tried to lay out the situation in his presentation to hopefully motivate the industry to address the issue.
“The good news in the Permian Basin is that everyone is in it together,” he continued. “Whether you work in the oil and gas industry or in a grocery store, everyone is tied to the oil industry in West Texas. The industry is a good friend of the community and I anticipate a level of cooperation.”
Galusky said he will know more in the coming months as the industry collectively begins to put its heads together in seeking a solution to the evaporating water supply.
“It is a matter of water availability to the oil and gas industry,” he emphasized. “It is not an environmental issue per se. It is much more fundamental. Everyone is stepping up to the plate to address environmental compliance, but the availability of water for normal drilling activity as well as hydraulic fracturing is as important as reservoir pressure. This is not only a public relations issue. It is that and much more. The industry needs water.”
Although it is estimated that the oil and gas industry uses only 1.6 percent of the available water in Texas, Galusky said the industry is working hard to develop solutions to water shortage in the drought-stricken Lone Star State.
To reduce the amount of fresh water required for hydraulic fracturing, the oil and gas industry has a couple of options. One, it can treat flowback or produced water for re-use in fracking. Or two, it can drill into other formations for brackish water that can’t be used for drinking water but can be possibly treated or mixed with fresh water to be used in hydraulic fracturing.
“Maybe we could all do without oil or gas,” said Daryl McCracken, product
launch manager, water management for service company Baker Hughes, “but we would get really thirsty quickly if there wasn’t any drinking water available. We have to take care of our water supply. Because of that, Baker Hughes has been proactive in looking at solutions.”
McCracken pointed out that there are nine barrels of water produced for every barrel of crude oil produced in the United States, so the ability to treat flowback and produced water is the obvious answer for the oil and gas industry to reduce its fresh water requirements. Thus, Baker Hughes started its trademarked H2prO service, which McCracken said “strives to bring the best solution to meet industry needs.”
Because the water characteristics of each well are different, he claimed there is “not a single, magic-bullet solution.” As part of it H2prO service, McCracken said Baker Hughes provides pre-job analysis to determine the best solution to minimize an operator’s footprint and cost.
He listed three different technologies as the main solutions that Baker Hughes is employing as part of its H2prO service. The first one is electrocoagulation.
“It is a proven technology although it is new to the oil field,” McCracken explained.
“It is highly mobile, so we come to you. We can have it up and running in an hour. A single unit can treat up to 8,600 barrels per day, and it is very easy to use multiple units. It can be integrated with our other solutions and services, such as our pressure pumping.”
He added that electrocoagulation can be the most cost-effective method to remove just the contaminants that can cause problems. By treating the water on site for reuse, McCracken contended it not only trims operating costs but it also reduces HSE (health, safety, and environmental) impact. Fewer trucks on the road going to disposal wells mean less pollution, he noted.
The second technology that the H2prO service is using, according to McCracken, is chlorine dioxide, another proven technology that is actually used in grocery stores to wash grapes. It targets specific bacteria or contaminants.
“The chlorine dioxide technology removes hydrogen sulfide (H2S), iron sulfide, and bacteria, all of which are very harmful to the next well,” he stated. “It is just as mobile as electrocoagulation and can be integrated with our pressure pumping service. It reduces logistical trucking and disposal issues by reusing the water. It is also a green biocide, which means it doesn’t need any special requirements.”
The third technology is called a mobile evaporator.
“It evaporates the water and re-condenses it in nearly pure form,” McCracken explained. “It produces treated water of only 300 parts per million of total dissolved solids. It produces near-drinking-water quality. It is perfect for extremely salty fluids.”
He added that the company’s goal is also “to not over-treat.”
“In any development, simple is better,” McCracken continued. “We want to employ solutions that are proven, rugged, reliable, and cost-effective.”
He said Baker Hughes can treat and reuse up to 100 percent of the flowback or produced water with its electrocoagulation and chlorine dioxide technology. The mobile evaporator can turn 70 percent of treated water into fresh water.
McCracken said the oil and gas industry’s goal is to eventually get to a closed loop system, which would be beneficial from both an economic and environmental standpoint.
“Droughts have a significant impact on the oil and gas industry,” he said. “Water is not created. It is finite, and our population continues to grow. There is a growing interest in our customers to build capacity to address the water issue.”
Water management services
Halliburton, one of the world’s largest providers of products and services to the energy industry, announced in January that operators working in the Permian Basin, Niobrara Shale, and Eagle Ford Shale can now take advantage of enhanced capabilities to reduce the amount of fresh water used for hydraulic fracturing while at the same time reducing their overall cost for water-related services.
Halliburton is offering CleanWave service, an enhanced water management program in the Permian Basin, the Rockies, South Texas, and North Dakota, which includes recycling and reusing flowback and produced water while also adding the ability to provide freshwater as needed in certain high activity areas.
“This new business venture for Halliburton is a result of our constantly striving to meet operators’ needs for improved operational efficiency and better performance of their assets,” explained David Adams, Halliburton’s Production Enhancement vice president.
The expanded service, according to a company news release, has been made possible by Halliburton’s investment in technology, water-related equipment and facilities, and development of high-performance fracturing fluid systems that can be formulated with recycled or produced water.
The CleanWave service uses electrocoagulation to remove suspended solids from water, making it into a clear brine suitable for fracturing and other well site applications.
In addition to recycling, Halliburton can also supply the volume of fresh water needed to supplement available recycled water and can manage the transport and storage of the required water volume. Halliburton’s Total Water Management Solutions (TMWD) water supply points are currently operating in Weld County, Colo.; Wilson County, Texas; and Lea and Eddy Counties in the Permian Basin in southeastern New Mexico.
“This service can help assure operators that they can complete their shale wells on schedule and with an improved environmental profile, recycling and reusing as much water as possible, while reducing their dependency upon fresh water,” said Clay Terry, Water Solutions manager for Halliburton. “It is a responsible strategy for operator and service provider alike.”
Mark Engle, a research geologist for the U.S. Geological Survey at the University of Texas at El Paso, said finding a solution is mandatory because Texas is running out of potable water.
One solution is drilling for brackish water that is available in other formations, but not of the quality to be drinking water, and using it for hydraulic fracturing or supplementing the freshwater needed for fracking. Engle said Pioneer Natural Resources, one of the largest operators in the Wolfberry play in the Permian Basin, is experimenting with using brackish water for its fracturing.
But Sam Hicks, a spokesperson for Pioneer, said the company declined to do an interview for the story, saying “it is too early” in its efforts to find another source of water.
Engle said much of his work has been done in other parts of the country, including the Marcellus Shale. He said operators in the Marcellus are using a mixture of fresh water and recycled flowback water.
“The Marcellus is way ahead of the Permian Basin in treating produced and flowback water,” Engle stated. “In West Texas, we have all these injection wells for disposal of the produced or flowback water. They don’t have that luxury in Pennsylvania and West Virginia.”
The drought in the Permian Basin has changed the need to treat produced and flowback water for reuse, according to Engle.
“The drought may actually help retool how fracking is done,” he said. “We need to make sure that hydraulic fracturing has no huge impact on water being available for other uses.”
Engle, however, said he believes the answers to recycling water for fracking will be found in the Permian Basin.
“There was a story recently in the London-based magazine The Economist that said that West Texas and the Permian Basin are developing new approaches to hydraulic fracturing with recycled water,” he said. “It suggested that the rest of the world will end up using whatever solution is found in the Permian Basin. What they come up with here will be the test case for hydraulic fracturing and not diminishing the fresh water supply. Everyone will be looking at the Permian Basin as the gold standard.”