In a 2019 website post, the Produced Water Society estimated that the Permian Basin produces between 9 million and 15 million barrels of water per day. To put that in perspective, 15 million barrels equals 1933.4 acre feet, and Austin’s Lake Travis has a capacity of 1,135,000 acre feet. At that rate, Permian water production would fill the Lake to capacity in just over a year and a half (587 days, 1.6 years).
Current estimates are that around 10 percent of that produced water is recycled for frac use, meaning 90 percent is injected into saltwater disposal (SWD) wells. It is no shock that this volume is being tied to rising seismic activity in the Permian and in other producing basins such as Oklahoma’s SCOOP/STACK. This has led regulatory agencies in Texas, New Mexico, and Oklahoma to limit or prohibit injections in certain geographic areas in some cases, and certain formations in others, by identifying them as Seismic Response Areas (SRAs).
The exact cause of tremors, reaching as high at 4.5 on the Richter scale in December, near Stanton, is in debate. What is not debatable is the worrisome rise in their intensity and frequency, and the need for something to change. Some blame growing pressure in receiving formations while others tie seismicity more to the depth of the injection than the quantity.
Causes and Solutions
With Permian water-to-oil ratios ranging from 6-1 to as high as 10-1, producers have a dilemma. That water must go somewhere, and if SWDs are curtailed, there is little current option other than to equally curtail production. Every water conference over the last five years has grappled with this issue, and a variety of options are in development. But most of them face two huge hurdles: reaching economic viability and passing muster with regulators tasked with insuring water quality.
NGL’s Executive VP of Produced Water Solutions, Doug White, believes one key lies in injection depth, based on the company’s experience in Colorado’s DJ Basin. NGL’s midstream operations include transporting fresh and produced water mostly through pipelines in several basins, including the Permian. Water treatment is also in their tool box.
In 2014 the company experienced unusual earthquakes near a newly drilled SWD in a formation that was relatively deep for the DJ Basin. The company was concerned that they had drilled too deep, possibly into the pre Cambrian layer or “the basement.” Working with the University of Colorado’s geology department and other groups, they learned that they had indeed drilled into the pre Cambrian.
“We then cemented the wellbore back 400 feet to get away from the basement,” White recalled. “Subsequently, seismicity really has subsided almost wholly. It took about a year to get through all that.”
Taking that lesson to heart, the company began deploying a seismic array in each of their facilities starting in 2015. Arriving in the Lone Star State soon thereafter, White said the company’s seismic caution surprised most Texans. “People thought we were kind of crazy, I think.”
In the northern Delaware the company switched to shallow disposal wells, which some larger producers felt would produce seismicity. NGL’s hypothesis was, “Drilling deep wells closer to the basement, as we’ve experienced it, creates seismic risk. Now those companies have come to us and said, ‘Maybe you guys were right.’”
As for the idea that quantity contributes to seismic activity, White noted, “I think it makes common sense that it could lead to seismicity.” He added that after reaching a certain pressure level due to injections, “at some point in time will the earth move because of additional pressures? The answer is yes.”
To that point he asked whether seismicity in lightly populated areas was as much of a concern as it is near cities.
White is encouraged by the fact that industry stakeholders are taking the matter seriously, pooling efforts to find solutions. Managing solutions from the inside instead of waiting for regulatory mandates opens the door for, “opportunity that’s being created currently for the industry to learn and understand the genesis of the seismicity and how it can be managed on a portfolio basis over certain areas of a group of stakeholders.”
Recycling for frac use constitutes about 10 percent of the water the company handles, but interest in recycling has shot up in recent years, some of which is due to New Mexico’s greater use of the stick than the carrot. Restrictions on use of fresh or brackish water for fracturing has forced producers to turn to recycling options. Now, almost 50 percent of fracs use recycled water in that state.
“It’s the right angle, it’s the right approach,” White said. Their “stretch” goal is to recycle/reuse 100 million barrels in 2022 in New Mexico, but he thinks a 50-60 million barrel level is quite reachable.
Irony 101: Recycling Produced Water for Fracturing Only Produces More Water
Kelly Bennet, co-founder and CEO of B3 Insight, agrees that above all the other water issues, seismicity tops the list. Recycling for frac use is important, but there’s only so much water that can be absorbed that way. “It requires a healthy completion schedule [but] we don’t see an epic run up in capex plans from a lot of the big players. There is some natural restraint on demand for that water.”
There is an irony even there, he observed. “When you have wells that are producing, particularly in the Delaware, so much water per new well, you’re putting recycled water downhole to get multiples of that recycled water back.” Using produced water in that way actually creates more produced water.
Water disposal is being challenged by several hurdles, including political, regulatory, legal and economic. “What we [B3] are focused on is how do all these pieces fit together,” he said.
The firm believes disposal will get more expensive as it will require an infusion of capital to expand logistics and capacity as flows increase.
nnet says there is one issue related to formation cramming that keeps him up at night. “One of the effects of the move away from deep disposal is the race to develop more shallow capacities, and there are already places in the Permian where overuse of shallow disposal options has created operational issues for oil companies who need to drill in those areas.”
The challenges are not just seismic, Bennet said. When a formation has received too much injected water, “You’re drilling into a much higher pressure environment than you otherwise would.” Upgraded string casing and other considerations create significant additions to drilling costs.
Fracturing and even EOR will likely never absorb more than a fraction of produced water, Bennet says, seeing the industry instead looking to non-oil-related options. Those include non-food crops, discharge, or others. And while some of the obstacles there are economic, the biggest ones may be legal and regulatory. Getting all parties to agree on liability and safety standards will be a Herculean task.
Then there’s the political arena. “From the EPA standpoint, I am skeptical that the Biden administration is going to have any kind of EPA commissioners that are really keen to help the oil and gas industry deal with its problems,” he said with a chuckle. Federal government agreement is necessary because of the Waters of the U.S. (WOTUS) rule as issued by the Obama-era EPA in 2015. The 1972 Clean Water Act authorized the EPA to regulate such waters and to define what they were. Until the 2015 ruling, the definition has centered around navigable waters only. That ruling expanded the EPA’s oversight to include any stream or body of water that emptied into a navigable stream, a definition that includes almost every body of water the the United States.
The Big Picture
Over the last few years the Environmental, Social. and Governance (ESG) focus for oil and gas has centered almost exclusively on reducing methane emissions, which can be solved by better plumbing and monetized by selling the otherwise lost gas into the pipeline. The next phase will be to include water in that equation, which will also involve better plumbing, but without the financial incentive.
Helping form a 10-company coalition called the Oilfield Water Stewardship Council, B3’s goal is to establish operating standards that would create “firm, well-defined, very specific standards for operations that basically signify operational excellence as it relates directly to water stewardship,” he said.
Guidelines will monitor the entire lifecycle of water, not just fresh vs. produced volumes.
To make research data more available the company has also started a data hub in connection with a large Permian producer. The hub will collect blinded datasets that companies can share across the industry, allowing benchmarking and knowledge pooling in order to develop deeper insight into problems and solutions. “Collaborative work is going to be the name of the game,” he said.
Senate Bill Authorizes Collaboration
Collaboration is also the goal of State Senator Charles Perry, R-Texas, of the 28th District. The district includes 51 counties, many of which are oil and gas producers.
Perry is a primary sponsor, along with representative Dustin Burrows, of Senate Bill 601, whose title states, “Relating to the creation and activities of the Texas Produced Water Consortium.”
Explained Perry, a CPA in private life, “It’s charging us to bring stakeholder groups, environmental groups, anybody that’s impacted by fresh water supply conversations” together to study produced water as a potential water source for other use in a historically dry area.”
Quoting statistics showing that since 2009 the state’s oil and gas industry had handled more than 27 million acre-feet of produced water, he said, “That’s too big of an opportunity for a water source, potentially,” to be ignored, he said. The bill passed into law in June 2021 and took effect immediately.
He listed three main goals for SB 601.
Its first goal is to determine whether technology currently exists that is capable of treating produced water enough to make it a potable water source. “If not, what’s the next best use for it, be it ag or other?”
Noting that he believes the technology itself does exist, the second goal of the bill is to encourage industry to find an economic model making such technology cost-effective. “What would be the cost-recovery model, how would that look, and what would it be able to do?” he asked.
The third goal is to learn if such water would be distributable to appropriate end users. “Is there a network of pipelines and recharge zones and things like that, that could actually move it down a river basin for other state uses down south or move it into a potable water aquifer that cities and municipalities in West Texas already pull from? This is what I expect a report to give me clarity on.”
The research has been put under the oversight of Texas Tech, in Perry’s hometown of Lubbock. Its scheduled report date is August of 2022, timed to give Perry and other legislators opportunity to evaluate the findings to determine possible next steps available to the 2023 session of the legislature. He hopes the report will provide “The basis for a bigger, broader conversation.”
Whatever that research suggests, Perry shares Bennet’s concern about getting all pertinent regulators on the same page. “It’s not going to come without constant legal battles and embroilment,” he said. Especially under the current administration.
Poet Samuel Taylor Coleridge, in his “Ryme of the Ancient Mariner,” could have described the current produced water conundrum:
“Water, water, everywhere, and not a drop to drink.”
In 2022, more and more industry groups, think tanks, and regulators will be trying to change that for the better. Movers and shakers are realizing that the ground is already moving and shaking.
Paul Wiseman is a freelance writer. His email address is firstname.lastname@example.org.