By: Carlsbad Current-Argus – Oklahomans in 2015 probably felt like Californians as their homes were rocked by strong earthquakes.
But Californians were better off.
United States Geological Survey data shows there were only 130 earthquakes of a magnitude 3.0 or greater there. Oklahomans experienced 901 at least that strong, or stronger.
Why then, and why in Oklahoma?
Researchers determined most of those stronger earthquakes involved injection wells disposing of water produced by oil and gas wells into the Arbuckle formation, subsurface rocks as deep as 30,000 feet underground. Almost the entire state sits atop the Arbuckle.
For more than a century, the federal- and state-approved industry practice had worked as intended, with billions of barrels of wastewater produced by hundreds of thousands of wells disposed of using more than 3,000 disposal wells across the state.
But after Oklahoma’s oil and gas industry adopted the practice of drilling and producing larger, horizontally-drilled wells, including some targeting saltwater saturated formations, the amount of produced water needing to be injected drastically climbed.
Eventually, the water saturated the Arbuckle, increasing its internal pressure and stressing dozens if not hundreds of previously unknown underground faults that spiderweb their way across Oklahoma.
The number of earthquakes began rapidly climbing in the next few years, with the largest earthquake ever recorded in Oklahoma — a 5.8 magnitude earthquake near Pawnee — happening in September 2016.
Today, the underground disposal of produced water from oil and gas wells continues, but the practice is much more closely regulated using restrictions that limit both how much and where the wastewater can be injected.
Further, seismographs deployed across the state actively alert officials of “swarms” of weaker earthquakes indicative of potential trouble spots.
Oklahoma’s Corporation Commission, an agency created when Oklahoma became a state to oversee its oil and gas industry among others, also created an Induced Seismicity Department, which monitors and regulates all oil and gas activities correlated with seismic activities across the state. Its staff organizes and participates in meetings involving industry representatives, academia, federal organizations, and regulators in other states to address induced earthquake issues across Oklahoma and elsewhere.
Over time, collaborators including the commission, the Oklahoma Geological Survey, and industry partners achieved real success — only 30 earthquakes that were a magnitude 3 or greater happened inside of Oklahoma in 2022.
Oklahoma’s shaking attracted scrutiny from scientists across the country after a magnitude 5.7 earthquake — the strongest seen in the Sooner State, to date — happened about 60 miles east of Oklahoma City late one November evening in 2011, damaging numerous homes across a mostly rural area near Prague.
Nothing was known then about the potential link between Arbuckle disposal wells and earthquakes, prompting regulators to begin working with those researchers to figure out potential causes.
Then in September 2013, southern Oklahomans living in Love County were rocked by more than 30 earthquakes over three months after an Arbuckle disposal well located amidst that swarm, the Love County Disposal #1, started operating.
Geologists and pollution abatement specialists at the commission, along with Oklahoma’s seismologist, worked with the well’s operator who agreed to voluntarily close the well, ending the swarm. The sequence eventually became one of the first documented cases of earthquakes tied to wastewater disposal in Oklahoma.
Governor appoints study group, regulators issue regional, local directives
In late 2014, then-Oklahoma Governor Mary Fallin asked the corporation commission, energy industry representatives, the Oklahoma Geological Survey, university scientists, Oklahoma’s Secretary of Energy and Environment, and others to form the Coordinating Council on Seismic Activity, a non-public body that gathered regularly to discuss seismic issues correlated to oil and gas activities.
Many industry representatives who previously had rejected arguments there were any ties between wastewater injection and earthquakes were convinced to join the group by Kim Hatfield, the CEO of Oklahoma City-based Crawley Petroleum.
Hatfield, who at the time was regulatory chairman of the Petroleum Alliance of Oklahoma (known then as the Oklahoma Independent Petroleum Association), said industry leaders’ skepticisms were understandable, given the Arbuckle always had always been the best formation to use for the disposal of produced water because it had a lower per-square-inch pressure (and could take injected water more easily) than other, shallower formations.
Also, putting produced water in the Arbuckle reduced potential safety risks involved with drilling into shallower formations (mud formulas must be changed to prevent blowouts because of higher pressures and the presence of saltwater, making drilling more expensive).
“There were just a whole lot of people — smart people — who said, ‘Naw, you’re crazy.’ I told them they may be right, but I also told them that end of the day, we needed to study it before saying no, it’s not happening from injection, and here’s why,” Hatfield said.
“If we were to just come out with a statement that injection wasn’t causing seismicity and it turned out even one event was caused by injection, then we would have lost all credibility,” he said.
By mid-2015, ongoing research and other data prompted the commission’s Underground Injection Control Department to move from just taking actions to limit or close individual Arbuckle disposal wells associated with localized swarms of quakes to issuing regional directives impacting hundreds of wells.
These affected more than 500 Arbuckle disposal wells and reduced the volume of wastewater disposed in earthquake-prone areas across Oklahoma by about 800,000 barrels a day, compared to 2014.
From 2015 through 2018, additional flow and design restrictions on disposal wells were added to ensure well operators weren’t dumping water on the Arbuckle formation’s lowest level of basement rock. A requirement to report volumes being injected daily was among the new rules added.
Local and regional directives ultimately impacted operators of more than 1,400 disposal wells across a 15,000-square-mile area.
Industry advances reveal Oklahoma’s rocky underground
Hatfield said a major component of learning more about links between earthquakes and injection wells involves evaluating expensive seismic surveys undertaken by large oil and gas operators active across the state.
Those surveys, he explained, create proprietary three-dimensional images of underground formations typically used by companies to evaluate where wells should be drilled.
But they also captured images of observable faults in Oklahoma’s Arbuckle formation.
What operators agreed to do, Hatfield said, was to provide the surveys to the geological survey, which uses them to create generic maps showing where vertical “basement” faults within the Arbuckle exist.
The geological survey agreed to serve as a “Switzerland of data,” keeping the proprietary information included within those surveys private, Hatfield said.
Operators, in turn, were asked to avoid putting disposal wells near fault locations.
While Hatfield said the data isn’t perfect — it can’t detect horizontal “slip” faults that only become evident after a nearby disposal well is activated — it still proves extremely valuable in minimizing potential problems.
“We got the operators to agree that even if they didn’t cause the problem personally, they were all in the boat and were going to sink or survive as an industry, together,” Hatfield said.
Disruptive shakes in Oklahoma attributed to fracking, too
Over time, regulators and scientists recognized less-intense, yet noticeable earthquakes also were happening near wells that were being completed but were not located close to any Arbuckle disposal wells.
In late 2016, regulators required operators to:
- Submit notifications of well-completion work at least 48 hours before it begins.
- Consult with regulators if 2.5-magnitude or greater events occurred within 2 kilometers during operations.
- Pause completion operations for at least six hours and review mitigation options with regulators if 3.0-magnitude or greater events occurred within 2 kilometers during operations.
- Suspend completion operations until an in-person technical conference with the corporation commission could be held to determine whether work could proceed if a 3.5-magnitude event occurred within 2 kilometers during operations.
In 2018, the commission further strengthened its well completions directives by requiring operators to:
- Adopt both monitoring (using both private and Oklahoma Geological Survey seismic arrays) and response plans for any potential seismic events as small as 2.0-strength that could happen within 5 kilometers of a well bore’s location while it was being completed.
- Pause completion operations for at least six hours and consult with regulators if a 2.5-magnitude or stronger event happened within 5 kilometers while completions were underway.
Data collected by regulators showed there were 333 instances where seismic events were connected to well-completion activities between 2016 and 2019.
Hatfield said larger operators with the most well-completion experience again played a pivotal role in working with regulators to develop the rules and to help educate other, less-experienced operators on how to monitor and manipulate their completion jobs when potential problems are detected.
“Smaller operators needed this information. Everybody would suffer if a large earthquake were caused by that, even if it were a smaller operator,” Hatfield said.
Most seismic activity inside of Oklahoma today is linked to well-completion work, he also said.
Technology, tools used to track problem evolved over time
Funding for the equipment and labor needed to develop Oklahoma’s response programs largely was provided through an appropriation of nearly $1.4 million made in early 2016 by Fallin from Oklahoma’s emergency fund.
Fallin authorized the appropriation after being told what was needed to attack the problem by the Oklahoma Corporation Commission and Oklahoma Geological Survey.
“I’m committed to funding seismic research, bringing online advanced technology and more staff to fully support our regulators at they take meaningful action on earthquakes,” Fallin said at the time.
The emergency funds allocated by the governor allowed the corporation commission to proceed with much-needed computer updates and hire two contract geologists and other staff to work on seismic issues.
The geological survey used its $1 million share of the appropriation to install additional seismic monitoring stations in western Oklahoma, plus update its monitoring and mapping systems.
Jeremy Boak, Oklahoma’s geologist and director of the Oklahoma Geological Survey from July 2015 until March, 2019, said the funds were badly needed.
While Oklahoma’s peak year for 3.0 magnitude or stronger earthquakes was in 2015, the peak year for cumulative releases of subsurface energy came the following year, when Oklahoma was impacted by three 5.0-plus magnitude earthquakes.
“We used the money to do a bunch of studies, looked at some core that reached into the basement where most of the seismic activity was going on at that time,” Boak said. “But I think the real driver for effective collaboration was Mike Teague, who was Oklahoma’s Secretary of Energy and Environment. He was effective, charismatic, and brought these state agencies (plus the industry) together and got them talking.”
Money also was used to add additional seismic monitoring stations across the state.
While Oklahoma’s working number of seismic monitoring stations could be counted on just one hand before 1990, the Oklahoma Geological Survey operated a network of 26 permanent stations, 69 temporary stations and pulled data in from an additional 38 stations in surrounding states operated by other entities by 2018, improving both the volumes and quantities of data gathered and analyzed.
That work paid off when the geological survey was added to the Advanced National Seismic System, a system that involves the U.S. Geological Survey and researchers from more than a dozen other universities across the country.
Working with the geological survey, the commission’s induced seismicity department now has a system that pulls in real-time data on seismic events, as well as data on disposal well and well completion activities via a dashboard that greatly reduces analysis and response times.
Another valuable tool the survey and industry representatives added in late 2016 was a system comprised of 15 former injection wells equipped with tools used to monitor subsurface pressures within the Arbuckle formation.
Hatfield said data from those wells, so sensitive that it monitors daily pressure changes caused by the moon’s planetary orbits, show pressures inside the Arbuckle have been declining over time.
It also has educated researchers about how a sudden stoppage and then restart of injection wells into the formation can generate an earthquake-causing shockwave and how the formation’s pressure can be impacted by stronger earthquakes, thousands of miles away.
“Before those monitoring wells were brought online, very little was known about Arbuckle formation pressures and how they might contribute to induced seismicity problems. The object of this whole exercise was to find these things, and they soon will be out there for scientists all over the world to study,” Hatfield said.
The experiment Oklahoma scientists and oil and gas operators have been going through the past decade is far from over, Hatfield also said.
“We need to get to a better understanding of how we can continue to use the Arbuckle safely. We think it can be done, but we have to be able to show that, through a test on a small scale. This is still very much an ongoing, learning process,” he said.