New type of earthquake discovered

by Ruhr-Universitaet-Bochum

 DECEMBER 6, 2021

Rebecca Harrington is an expert in analysing induced earthquakes. Credit: RUB, Kramer

A Canadian-German research team have documented a new type of earthquake in an injection environment in British Columbia, Canada. Unlike conventional earthquakes of the same magnitude, they are slower and last longer. The events are a new type of induced earthquake that have been triggered by hydraulic fracturing, a method used in western Canada for oil and gas extraction. With a network of eight seismic stations surrounding an injection well at distances of a few kilometers, researchers from the Geological Survey of Canada, Ruhr-Universität Bochum, and McGill University recorded seismic data of approximately 350 earthquakes. Around ten percent of the located earthquakes turned out to exhibit unique features suggesting that they rupture more slowly, similar to what has previously been observed mainly in volcanic areas.

The group headed by Hongyu Yu—first at RUB, later at the Canadian Geological Survey of Canada—and RUB Professor Rebecca Harrington describes the results in the journal Nature Communications, published online on 25 November 2021.

Several theories on the origins of earthquakes

To date, researchers have explained the occurrence of earthquakes in the hydraulic-fracturing process with two processes. The first says that the fluid pumped into the rock generates a pressure increase substantial enough to generate a new network of fractures in the subsurface rocks near the well. As a result, the pressure increase can be large enough to unclamp existing faults and trigger an earthquake. According to the second process, the fluid pressure increase from injection in the subsurface also exerts elastic stress changes on the surrounding rocks that can be transmitted over longer distances. If the stress changes occur in rocks where faults exist, it can also lead to changes that cause the fault to slip and cause an earthquake.

Recently, numerical models and lab analyses have predicted a process on faults near injection wells that has been observed elsewhere on tectonic faults. The process, termed aseismic slip, starts out as slow slip that does not release any seismic energy. The slow slip can also cause a stress change on nearby faults that causes them slip rapidly and lead to an earthquake. The lack of seismic energy from aseismic slip and the size of the faults involved make it difficult to observe in nature. Researchers have therefore not yet been able to document aseismic slip broadly with any association to induced earthquakes. The work of the current study, provides indirect evidence of aseismic loading, and a transition from aseismic to seismic slip.

Modifying the hydraulic fracturing process

The German-Canadian research team interpret the recently discovered slow earthquakes as an intermediate form of conventional earthquake and aseismic slip—and thus as indirect evidence that aseismic slip can also occur in the vicinity of wells. The researchers therefore dubbed the events hybrid-frequency waveform earthquakes (EHW).

"If we understand at which point the subsurface reacts to the hydraulic-fracturing process with movements that don't result in an earthquake and, consequently, cause no damage to the surface, ideally we could use that information to adjust the injection procedure accordingly," as Rebecca Harrington, head of the Hydrogeomechanics Group at RUB, describes one implication of the study.

Not all quakes spread at the same rate

"We'd assumed that induced earthquakes behave like most other earthquakes and have roughly the same rupture speed of two to three kilometers per second," explains Rebecca Harrington. But that doesn't always seem to be the case. While the shaking from a conventional earthquake of magnitude 1.5 in the researchers' data set had died down after about seven seconds, an EHW earthquake of the same magnitude continued to shake for more than ten seconds.What happens underground during hydraulic fracturing

More information: Hongyu Yu et al, Fluid-injection-induced earthquakes characterized by hybrid-frequency waveforms manifest the transition from aseismic to seismic slip, Nature Communications (2021). DOI: 10.1038/s41467-021-26961-x

Journal information: Nature Communications 

Provided by Ruhr-Universitaet-Bochum 

 The Big One: Canada floods show British Columbia is not ready for a powerful earthquake

As the province rebuilds after the atmospheric river, experts hope for a heightened focus on future quake hazards

A bridge in Merritt, British Columbia, was damaged in the flooding. 

Photograph: Canadian Press/REX/Shutterstock

Leyland Cecco in Victoria, British Columbia
Sun 19 Dec 2021 

Canada’s largest port is shut down. Highways have snapped, buckled and crumbled. Bridges are washed into raging rivers and landslides rumble down mountainsides, burying cars and stranding travellers. Rail lines linking the west coast to the rest of North America are damaged. Oil pipelines cease operating.

Three years ago, officials at Vancouver’s main transport hubs were told to prepare for a scenario in which nearly 3 million people in south-western British Columbia were cut off from the rest of the country.

Those warnings became a reality in mid-November when the region was hit by record rainfall, flooding and landslides. But in their meeting, officials had gathered to plan for a far more devastating disaster: a powerful earthquake, known as the Big One, that has long been predicted to strike the region.


Floods and wildfires are now normal life in small-town Canada

The widespread destruction from the flooding has highlighted the vulnerability of the region’s infrastructure, but experts warn that if the province fails to learn from the current crisis, it faces larger, deadlier and costlier disasters in the future.

Houses and farms became islands after record rainfall in Abbotsford, British Columbia. Photograph: David Pemble/AFP/Getty Images

Geologists say a massive earthquake will almost certainly hit south-western British Columbia in the coming years, with the odds as high as 30% over the next half-century. Residents have long feared the Big One, a rupture of the Cascadia subduction zone far offshore that will unleash a tsunami and inflict widespread destruction.As many as 10,000 people could die in southern British Columbia and the Pacific north-west of the United States. Fires alone could cause as much as C$10bn in damage. Water lines will be severed. First responders could be unable even to leave their stations.

The last large quake in the area – the Cascadia megathrust in 1700 – was strong enough for its effects to be felt all the way across the Pacific in Japan.

But the Cascadia plate boundary has been “eerily quiet” for many years, said Edwin Nissen, a seismologist at the University of Victoria. “Most people here likely haven’t actually felt an earthquake in their lifetime. And so they’re a bit disconnected from what could happen.”

Even a smaller quake could prove catastrophic if it strikes closer to an urban centre.

“The danger is that there could be a bullseye hit on one city,” said Nissen, pointing to the 2011 quake that struck Christchurch, New Zealand, the effects of which are still visible a decade later. “A localized quake could be far more devastating even than the Big One.”

But experts also say the recent flooding in the province has given the region a rare glimpse into its fragility – and a chance to fix that.


Before and after: how the 2011 earthquake changed Christchurch

“People don’t appreciate the importance of critical infrastructure until you see a flaw in it,” said Jean Slick, head of the disaster management program at Victoria’s Royal Roads university. “When they’re in our own back yard, it gives us this opportunity to understand the threat in a completely different way.”

Officials in British Columbia have faced criticism for never activating the mobile emergency alert system even as it became clear that days of heavy rain would have a devastating effect on communities. Meanwhile, evidence suggests the province knew its diking system, which failed, wasn’t up to standard. Residents forced from flood-ravaged areas detailed days of confusion when searching for shelter.

Houses in Abbottsford were uninhabitable. 

Photograph: Jennifer Gauthier/Reuters

One month after the floods, British Columbia remains in a state of emergency. Gas is rationed in major coastal cities and at least one major highway system will take months to fully repair and thousands have lost their homes. Landscapes have been altered and the route of at least one major river has changed.

But as the province begins the difficult task of cleaning up and rebuilding, experts hope the floods will also help the public understand the risks that emerge from urban planning decisions.

“When you get the premier and ministers saying this is a natural disaster, we’re left thinking that nature did this to us. But there are no natural disasters. Flooding is a natural hazard. We build and live and work in floodplains. We’re the ones that create disaster risk,” she said. “The question is, how do we live with risk?”

Slick, who served as an expert adviser on the BC auditor general’s report into the province’s earthquake preparedness, says recent events have had a “focusing” effect on how people understand natural hazards and risk. Empty store shelves and panic buying from both the pandemic and floods have exposed the costs of ignored warnings and the importance of preparing for future crises.

“When we rebuild, let’s not put blinders on and just focus on floods. Let’s make sure that we’re considering all hazards, like climate risks and earthquakes,” she said.

But rebuilding often comes with an eagerness to return to normal as quickly as possible.

“There’s going to be a rush to rebuild, and [there’s pressure] to put things back the way they were before,” said Glenn McGillivary, managing director of the Institute for Catastrophic Loss Reduction. “But is anybody going to stop and say, ‘Hey, wait a minute, why don’t we build this thing better, so we’re not doing this again in two more years?”

Even simple changes can lead to outsized benefits. As one of the province’s natural gas providers upgrades its metering system, McGillivary and others have called for seismic shut-offs to be installed on every line, as is common in Japan, to prevent fires after an earthquake.

But previous studies suggests British Columbia remains unprepared for a large tremor.

“We know that there will be a big earthquake, but we’re still not as prepared as we should be. And scientists are saying atmospheric rivers will get much stronger due climate change and flooding would get much worse,” said Nissen.

“That next big earthquake could be 100 years away. That’s not even in our lifetime. It almost feels hypothetical,” he said. “The cost of doing something is astronomical. But the cost of doing nothing is even worse.”

Geologist says cause of Manitoba earthquakes unknown

Written by Taylor Brock Thursday, Aug 12 2021

Two earthquakes did not cause much of a racket on Tuesday. (Volcano Discovery)

Two earthquakes lightly shook parts of Manitoba over the course of one day.

Overnight Wednesday at 4:34 a.m., an earthquake occurred near Spy Hill, Saskatchewan, on the cusp of the Manitoba border. It was a light earthquake of a 4.2 magnitude, according to the USGS National Earthquake Information Center. The closest Manitoba town is Binscarth, a village approximately 15 kilometres west of the earthquake's epicentre. It also could have affected Russell-area residents.  

(Volcano Discovery)

The second quake occurred the same day, at 8:25 p.m., with a 4.0 rating. It occurred roughly in the same area as the first quake.

Dr. Simon Pattison, the chair of Brandon University's geology department, says many people in the area would have felt these rumblings.

"There were some reports in the immediate area of buildings. homes that were shaking. There were reports of people already in bed and they felt their beds moving around," Pattison says, noting these reports range from light to strong shaking.

Earthquakes in this area are quite rare, maybe once every few years and ones of this magnitude occur once every five to 10 years, on average because of the geological location.

"It's a rare event and certainly piqued my interest."

Geology professor Simon Pattison says he does not know what caused Wednesday's earthquakes, noting they were stronger and deeper than usual. (Screenshot: Zoom)

Pattison says at first he thought it could have been the results of potash deposits disintegrating in groundwater, but quickly learned that was not the case.

"I started looking at the data so it's like 'oh ok, that's kind of pointing towards something potentially something different, much deeper than the potash deposits," Pattison says. "That got me quite intrigued, and you know somewhat excited because since I've been teaching here at Brandon University I'm not aware of any deeper-seated earthquake that we've had kind of in this region." 

Pattison says this layer is much deeper than his original potash theory. Because of the location on top of a tectonic plate, the prairie regions do not often have many earthquakes, let alone 10 kilometres underground in the "very-old pre-Cambrian basement rock." He says this is all speculation with the data he has, saying these earthquakes do not fit the usual pattern, and the geologist cannot definitely say what caused the earthquakes.   

The longest-known earthquake lasted 32 years

A 32-year-long undersea quake was recorded in coral. 

• Flora Graham

• Twitter

Coral microatolls, such as this one, cannot grow when exposed to air, so their fossilized bodies record elevation changes that push them up out of the water.Aron Meltzner/Earth Observatory of Singapore

Coral scars show 32-year-long earthquake

A devastating earthquake in Indonesia in 1861 was the crescendo of a 32-year-long clash between the tectonic plates below the island. It is the longest such ‘slow slip event’ ever recorded, and it left its mark in the bodies of the long-lived corals that inhabit the seas above. Researchers analysed growth patterns in corals on Simeulue Island, which were periodically exposed to the air as the land rose up and down. The corals record decades of vertical movement at the fault, from 1738 to the moment they died when thrust up by the 1861 quake. The findings will help seismologists to better understand some of the most dangerous quakes on Earth: the 2004 Indian Ocean earthquake and tsunami that killed more than 220,000 people were preceded by a slow slip.

Scientific American | 4 min read

Go deeper with geoscientist Daniel Melnick in the Nature Geoscience News & Views article.

Reference: Nature Geoscience paper

Australian Team Probes Southern Ocean in Deep-Water Earthquake Research
November 23, 2021 
Phil Mercer

A humpback whale jumps out of the water in the western Antarctic peninsula, on March 5, 2016.

SYDNEY —

A mission is underway to retrieve scientific data from the rugged ocean floor in the Southern Ocean, formerly known as the Antarctic Ocean, that could explain what triggers underwater earthquakes and tsunamis.

Some of the world's most violent underwater earthquakes are unleashed beneath the hostile waters of the Southern Ocean, but researchers don’t know why. Sophisticated noise and motion sensors could help unlock the secrets of how Tectonic plates - or pieces of the Earth's crust - start to collide, a process known as subduction.

For the past year, an array of 27 seismometers positioned on the ocean floor has formed a giant telescope pointing to the planet’s core. The instruments are now being retrieved.

Professor Hrvoje Tkalčić, a chief scientist from the Australian National University’s Research School of Earth Sciences hopes the study will help to explain how and why earthquakes occur.

“We cannot predict when exactly they will happen, how large they will be. But we can understand better their physical mechanism and we can also understand better the Earth’s structure in that area, and this is critical to predict the propagation of the seismic waves from the hyper-center of these earthquakes to any other point on the Earth’s surface, including a possible generation of tsunami,” Tkalčić said.

Scientists hope the study will give them a better understanding of how earthquakes and tsunamis might affect Australia and New Zealand, which lies within the seismically active region known as the “Pacific Ring of Fire.”

The expedition is scouring some of the world’s steepest underwater mountain ranges to depths of more than 3.5 miles in a remote area known as Macquarie Ridge, halfway between New Zealand and Antarctica.

Researchers say the techniques could also be applied to other oceans.

The international study is a collaboration with various Australian institutions, the University of Cambridge and the California Institute of Technology.

The three-week voyage began in Wellington, New Zealand on November 10.

Earthquakes and the H.B. Robinson Plant: A Case Study of the NRC’s Failure to Learn from the Fukushima Accident

Ed Lyman

Director, Nuclear Power Safety

UNION OF CONCERNED SCIENTISTS 

October 22, 2020

In response to the 2011 Fukushima Daiichi triple-meltdown accident in Japan, the Nuclear Regulatory Commission (NRC) ordered nuclear reactor owners to conduct studies to revise and update the seismic hazard profiles at their sites. After nearly a decade, the results are in. Which nuclear plant in the United States has the reactor (or reactors) most susceptible to melting down after an earthquake? If you guessed the answer is the two-unit Diablo Canyon, the only nuclear power plant currently operating in seismically challenged California, you would be wrong.

The “winner” (or more accurately, “loser”) is apparently—wait for it—the H.B. Robinson Unit 2 reactor near Hartsville, South Carolina, owned by Duke Energy Progress (“Duke”). There is only one nuclear reactor at the site: Unit 1 is a shut-down coal-fired plant. Duke’s risk assessment found that, on average, there is a one in 7,700 chance per year that an earthquake could cause a meltdown at Robinson—five times higher than the average estimated risk for each of Diablo Canyon’s two reactors.

This shouldn’t be a big surprise. South Carolina, where the city of Charleston suffered a devastating earthquake in 1886, is one of sixteen states with the highest seismic risk, according to the United States Geological Survey. But this danger is compounded at Robinson—partly because of poor plant design and partly because of a phenomenon known as liquefaction: the potential for ground shaking to cause the underlying soil to lose strength and its ability to support buildings and other structures. Of particular concern is the possible failure of the adjacent Robinson Dam, which was built to create Lake Robinson, the major source of cooling water for the plant’s radioactive fuel and critical safety equipment such as emergency diesel generators.

Robinson was one of seventeen nuclear plants that the NRC identified as having the largest differences between the severity of the seismic hazards revealed by the new studies and the original hazards that were assumed when the plants were designed and licensed. The NRC required this group of plants to performed detailed analyses called “seismic probabilistic risk assessments.”

The ten US nuclear reactor sites with the highest likelihoods of meltdown triggered by an earthquake are listed in Table 1, in order of decreasing risk. UCS compiled this list from plant seismic probabilistic risk assessment reports and NRC reviews of those reports. The NRC itself does not provide such information to the public in a form that would facilitate ranking the safety of different plants.

As Table 1 shows, the Robinson reactor has the highest mean (or average) likelihood of experiencing an earthquake-induced meltdown of all the reactors that were required to conduct seismic probabilistic risk assessments. One of the reasons for this is that much of the risk does not come from the most severe earthquakes believed to be possible at the Robinson site, but from relatively mild (and more frequent) earthquakes. This is “atypical,” according to the NRC, since nuclear plants are supposed to be able to withstand small earthquakes by design.

Not every core meltdown accident will result in significant radioactive contamination off-site. However, Duke calculated that there was a 1 in 40,000 risk that a seismic event at Robinson could cause not only a core meltdown but also a large near-term release of radioactivity to the surrounding area, which includes the city of Florence, South Carolina (within thirty miles) and the cities of Columbia, South Carolina, and Charlotte, North Carolina (within eighty miles).

While these may seem like small numbers, they are large in the context of nuclear plant safety. The NRC has concluded that “the risk from seismic events at Robinson is high.” The agency considers a core damage frequency of one in 10,000 per year from all potential accidents—including pipe breaks, fires, and floods—to be the upper limit for acceptable reactor safety risk. Similarly, it considers the highest acceptable frequency of a large near-term (“early”) release of radioactivity to be one in 100,000 per year. (These are called the Safety Goals.) But at Robinson, the risks due to earthquakes alone exceed the Safety Goals.

However, the NRC’s Safety Goals are non-binding targets and not regulatory requirements. Accordingly, the NRC has not ordered Robinson to shut down or to make structural modifications to mitigate the high seismic risk, such as reinforcing the plant’s seismically vulnerable turbine building, which could collapse and disable critical backup cooling systems needed to keep the reactor’s fuel from overheating.

Instead, Duke has committed on a voluntary basis, to make upgrades only to the emergency backup safety systems that the NRC required nuclear plants to acquire after Fukushima. This less-than-half measure simply is not sufficient to mitigate the risk. Given that Robinson may operate for at least another thirty years, the NRC should revisit this decision.

The lessons of Fukushima

The Fukushima accident, which resulted in three nuclear reactor meltdowns, was triggered by a massive earthquake that generated tsunami waves far higher than the plant was designed to withstand. As it happened, the reactors were not seriously damaged by the earthquake itself, but the catastrophic flooding from the tsunami damaged the plant’s emergency power supplies and electrical systems, causing a near-total loss of electrical power and disabling the pumps that provided critically important cooling water to the hot nuclear fuel.

Two of Fukushima’s main lessons were that (1) nuclear plants need to have additional means of coping with a prolonged loss of electrical power; and (2) plant owners need to ensure that their assessments of external hazards such as earthquakes and floods are accurate and up-to-date, and then implement additional measures where necessary to protect the plants from these hazards.

Following the Fukushima accident, the NRC required, among other things, that all US plant owners (1) develop plans and acquire emergency (“FLEX”) equipment to provide backup power and cooling if power is lost for long periods; and (2) reevaluate the earthquake and flooding hazard profiles at their sites based on updated information and methods.

The hazard reevaluation studies that plant owners conducted found that nearly all nuclear plants were vulnerable to more severe earthquakes and floods than they were prepared to withstand. However, the NRC, inexplicably, has not required a single plant to upgrade its defenses in response to these findings despite having the regulatory authority and responsibility to do so.

(1) The Vogtle plant in Georgia was required to conduct a seismic probabilistic risk assessment, but unlike other plants, the value of the seismic meltdown frequency does not appear in the public documentation on the NRC website. Thus it is not publicly known how Vogtle’s seismic risk compares with the plants on this table. (2) This is the annual likelihood that a single reactor will experience a core melt following an earthquake. The total site risk is actually the cumulative risk considering the possibility of multi-reactor accidents. However, the NRC’s (irrational) policy is to consider only a single reactor accident when evaluating nuclear plant safety in the context of its Safety Goals. (3) The risk values of different reactors at multi-unit sites are not always the same. In those cases, the highest site values are reported. (4) Unlike other plants, the publicly available Peach Bottom seismic documentation only specifies the point value of the meltdown frequency, not the mean value over the uncertainty distribution, which would be higher.

The risk of a meltdown at Robinson

In the case of Robinson, the NRC’s decision not to take regulatory action is clearly misguided. The NRC noted in its review of the Robinson seismic study that “the risk, using present-day information and more sophisticated tools, is an order of magnitude [factor of 10] higher and more consequential than previously known.” Particularly alarming was the revelation that Robinson is not only at risk from earthquakes that exceed its current design requirement—the so-called “Safe Shutdown Earthquake”—but also from smaller earthquakes that the reactor should have been able to withstand.

For example, the study estimates that there is a twelve percent chance a Safe Shutdown Earthquake would cause the dam to collapse and the lake to drain due to liquefaction, causing a loss of the primary water source relied on to remove heat from the reactor. Therefore, Duke’s plant is not in compliance with the NRC’s fundamental requirements for earthquake protection.

Another high-risk scenario is the collapse of the building containing the plant’s turbines, which was not built to be highly seismically resistant. This could result in multiple safety system failures by disabling critical electrical equipment and emergency pumps, including the recently acquired FLEX equipment that was intended to be used as backup in loss-of-power scenarios caused by natural disasters. Without these pumps and other equipment, plant workers would have no means to provide water to the steam generators and remove heat from the nuclear fuel in the reactor core, eventually resulting in a meltdown.

Duke’s mean seismic meltdown risk estimate of one in 7,700 per year is the sum of the risks of these and other potential accident initiators. One should note that these risk values are only rough estimates— predicting the chance of an earthquake is an uncertain business and error bars are large. Taking those uncertainties into account, Duke calculated that there was a five percent chance the actual meltdown risk could be four times greater than the mean value, or about one in 2,000 per year.

Robinson’s license to operate, which has already been renewed for an additional twenty-year term for a total of sixty years of operation, is slated to expire in 2030. However, Duke has announced that it is planning to apply for subsequent twenty-year license renewals for its entire fleet, including Robinson. If approved, the likelihood of a seismically induced meltdown at Robinson over its remaining lifetime would be about 0.4 percent on average, and could be as high as 1.5 percent.

An inadequate response

The most straightforward way to reduce the high seismic risk at Robinson is for Duke to reinforce the turbine building and other vulnerable structures so that they are less likely to collapse if an earthquake occurs. But that option is apparently too costly for Duke.

Though Duke plans to make modifications to reduce the vulnerability of the emergency backup (FLEX) equipment and emergency water sources so that they would have greater chances of surviving an earthquake, this is a poor substitute for structural reinforcements. While this action could increase the survivability of the emergency equipment that personnel could use to mitigate earthquake destruction, it would not help prevent that destruction from occurring. While functional mitigation capabilities are important, they require actions by site personnel, which introduces additional risks—for example, if workers are injured or are prevented from setting up and using the emergency equipment in time to restore core cooling because of earthquake damage at the site. It is far preferable to reduce the likelihood of structural damage in the first place.

The limited benefit of these changes is apparent from Duke’s own analysis, which found they would reduce the risk of core damage from earthquakes by only forty percent. When other accident initiators, such as fires, are taken into account, the total core meltdown risk would be about one in 7,750 per year—which still fails to meet the NRC’s one in 10,000 per year Safety Goal.

So why did Duke decide to pursue this alternative approach? Because of the price tag. Duke told the NRC that the “Class III [Turbine Building] structural modification and other dominant risk contributor modifications were not being pursued based on the comparison of the modification cost estimates to the proposed modification strategy cost estimate.” In other words, Duke decided beforehand on the amount of money it was willing to spend to fix the problem, and the NRC acquiesced.

But that’s not the way the process should work. The NRC should require that the plant meet its safety goals, regardless of cost. And Duke should consider the cost of the necessary seismic upgrades relative to investments in safer, less risky low carbon alternatives like energy efficiency and renewable energy.

What the NRC should do

The NRC has determined that Robinson is out of compliance with original assumptions about the plant’s seismic risk. In fact, the reactor has been vulnerable to earthquakes that it was supposed to have been designed to withstand since it began operation in 1970. Unfortunately, this issue was not considered when the NRC renewed Robinson’s license in 2010, because the agency’s license renewal regulations do not require a comprehensive review of plant safety and a confirmation of the validity of the original licensing assumptions.

The NRC should not repeat that mistake—and should not approve a second license renewal, allowing Robinson to operate until 2050, unless Duke rectifies this long-standing and dangerous situation.

Other nuclear plants seeking subsequent license renewals, such as North Anna in Virginia and Oconee in South Carolina (see Table 1), also have seismic risks high enough so that their overall meltdown risks likely exceed the NRC Safety Goals. The NRC should thoroughly assess the need for seismic reinforcements as part of its review of license renewals for these plants

About the author

MORE FROM ED

Edwin Lyman is an internationally recognized expert on nuclear proliferation and nuclear terrorism as well as nuclear power safety and security. He is a member of the Institute of Nuclear Materials Management, and has testified numerous times before Congress and the Nuclear Regulatory Commission.

FRACKQUAKES

Risk of earthquakes caused by oil and gas operations in New Mexico rising

Adrian Hedden
Carlsbad Current-Argus

Multiple magnitude (M) 4 or 5 quakes were felt in the Midland area, leading the Texas Railroad Commission to declare a seismic response area (SRA) earlier this fall in the Gardendale region, calling for reductions in water disposal injection volumes.

Earthquakes at M 4 are generally felt but are known to cause minor damage. When recorded at M 5 or above, they may cause increasingly severe damage to structures and risk public safety.

Quakes below M 2.5 are not typically felt on the surface.

Injections rates for existing disposal wells - where water created as a byproduct of oil and gas drilling is disposed of by pumping it underground - were reduced to 10,000 barrels per day, while operators were required to report daily injection volumes and pressures to the Commission each month.

More:New Mexico's oil and gas water research studies economics, toxicity

Wells permitted but not in service would not be allowed to begin injection, and the Railroad Commission said it would not issue any new permits in that area.

Then, in October the Railroad Commission announced it was creating a second seismic response area in northern Culberson and Reeves counties, just along the border with southeast New Mexico.

The Gardendale area is about a two hour drive to New Mexico cities like Carlsbad and Hobbs, but the recent SRA was closer and was more likely to impact operators in New Mexico.

More:Pioneer Resources exits Delaware Basin, New Mexico in $3.25B sale of oil and gas assets

In its announcement of the Culberson and Reeves counties SRA, the Railroad Commission pointed to 15 M 4 or greater earthquakes along the state line since Jan. 1, 2020, with six of those reported between Sept. 3 and Oct. 3, 2021.

That meant almost half of the heightened seismic activity in the area since last year occurred in the last month.

More:Lujan Grisham's pledge to cut carbon emissions attacked by New Mexico oil and gas supporters

The Railroad Commission referred to this as an “unprecedented” level of activity. The latest SRA called for coordinated action in reducing disposal volumes and thus seismic activity. The Commission included with its announcement a list of 89 disposal wells in the area and proposed reductions in volumes.

The list included industry leaders like Chevron U.S.A. and Cimarex Energy, calling for injections to be reduced by more than half in some cases from the permitted amount.

In one case, a well owned by Chevron was asked to observe a maximum of 30,000 barrels per day (bbl/d), despite being permitted for 100,000 bbl/d.

More:Feds move forward with sale of southeast New Mexico public land to oil and gas industry

The Commission said if its recommendations were not successful in reducing seismicity, it was prepared to act as it did in Gardendale and require that companies reduce their volumes of water injection.

Success to the commission, per the announcement, meant no more M 3.5 earthquakes in the next 18 months.

“Staff will use available public data and trends (for example, earthquake count, earthquake magnitude, and disposal volume) to evaluate the efficacy of a response plan,” read the announcement.

“Absent a coordinated industry response, RRC staff is prepared to implement its own seismic response action plan (SRAP) for the NCR SRA after 90 days.”

Permian Basin source of almost a third of U.S. oil production. Companies capitalize on growth

'They need to start addressing it.'

Michael Hightower, director of the New Mexico Produced Water Research Consortium at New Mexico State University – a project established in 2019 by the State to study and attempt to implement alternate uses of produced water beyond the oil and gas industry – said it was clear Texas’ earthquake problem was spreading toward New Mexico.

More:U.S. Rep. Herrell hopes bill will protect oil and gas industry from species conservation


“We know there’s a lot of water coming over from Texas,” he said. “If you inject all that, you’re going to have seismicity problems. We’ve been following the seismicity. Most of the seismicity being observed is due to saltwater disposal wells. They seem to be at the depths saltwater disposal is at. People think they’re coming from over-pressurization.

“It’s getting closer and closer to us. Absolutely.”

The Consortium worked closely with Texas regulators, Hightower said, aiming to devise technology that could treat produced water and recycle it for uses like agriculture or even drinking water – harnessing a new, plentiful source of water in the arid region.


Many oil and gas companies already recycle produced water for subsequent fracking operations, but Hightower said expanding the potential for its reuse presented an economic opportunity and a way to address environmental and water scarcity concerns tied to fossil fuels.

More:Permian Basin poised to ramp up oil and gas production as mergers cool and prices rebound

“The big issue is how do you reduce the volume of produced water you’re disposing of. That is the exact mission of the consortium,” he said. “There are a lot of companies trying to look at reducing the volume they dispose of.”

The State, through the consortium – made up of scientists, state agencies and energy companies – was targeting a goal of a 30 to 60 percent reduction in produced water disposal, Hightower said.

He said the economics could also make sense to the private sector, as the price of injection continued to climb in recent years, and companies hoped to reduce their environmental impacts in response to investor concerns.


“A lot of companies are looking at reusing that produced water and putting it to beneficial use,” Hightower said. “Generally, industry understands it’s probably the over-pressurization from saltwater disposal wells. They need to start addressing it. Treatment and reuse is one of those options.

Abandoned: New Mexico could risk $10 billion in failing to plug unused oil and gas wells

“What we’re hoping we can do for the Permian Basin is work with counties on both sides of the border so we can come up with strategies in the future.”

Jason Jennaro, chief executive officer at Breakwater Midstream, a company specializing in transporting produced water, treating it and redelivering the cleaner water back to the oilfield, said the recent seismic activity made finding alternatives to disposal injection increasingly urgent.

The growing trend in seismicity meant big business for Jennaro and Breakwater. The company recently announced its second commercial-scale water recycling facility, meaning it can aggregate waters from multiple companies in the Midland Basin with a capacity of about 200,000 barrels per day.

The Morita Commercial Recycling Facility will enter Breakwater's network of pipelines intended to transport produced water away from seismically active areas in the oilfield for treatment, and then back out to well sites for reuse.

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Together with Breakwater's other commercial-scale facility, the 360,000-barrel Big Spring Recycling System, the company estimated it could treat and distribute more than half a million barrels of produced water a day for the Midland Basin.


"Operators are looking for environmentally sustainable alternatives to disposal within these SRAs and seismic clusters, which is why system interconnectivity and commercial recycling is central to sensible stewardship of the water," Jennaro said.

Regulatory action from the Commission, he said, will severely impact operations and force the industry to seek alternatives.

“It impacts what people can do operationally,” Jennaro said. “That’s why operators are very concerned about this. They know when an SRA is declared on top of them, it has the potential to materially impair the value of their leasehold.”

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New Mexico begins to tackle issue

Another harbinger of the growing problem, Jennaro said, was also the proliferation of smaller earthquakes, often not felt on the surface but indicative of increased activity.

He said this activity began to increase in 2017, when oil and gas boomed in the region, up to about three per day recently.

In 2021, records show the region was on track for more than 1,200 earthquakes between M 1 and M 4.

“We’re getting thousands of earthquakes per year. We just didn’t see anything like this in the past. It’s a call for environmental stewardship and for folks to be better managers of our water resource,” Jennaro said. “That calls for not relying on disposal in areas of high seismicity and recycling more water.”

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The more induced seismicity in Texas, Jennaro said, the more regulators were likely to seek curbing injection volumes.

That could mean sending more water over the border to New Mexico to avoid Texas’ increased regulatory action and continue pumping water underground.

“When disposal is limited on one side of the border, it will have the impact of pushing water in Texas back up to New Mexico and impacting disposal there,” Jennaro said. “It will impact the hydrodynamics of water flow all around the SRA.”

Adrienne Sandoval, director of New Mexico’s Oil Conservation Division (OCD), the State’s main oil and gas regulator, said her agency is encouraging operators recycle and reuse water instead of injecting.

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To avoid over-pressurization, Sandoval said the OCD implemented well-spacing requirements as a condition of permitted disposal wells.

While New Mexico has yet to see the seismic activity observed and acted upon in Texas, Sandoval said the State is closely watching what’s happening over the border, collecting data, and hoping to be proactive to prevent the problem from forcing its regulatory hand.

“We have seen some induced seismicity on the New Mexico side. It’s sort of along the Texas line and along the Lea and Eddy county line. We’re working with operators to gather data,” she said. “We want to ensure we’re being protective and managing things in proactive way so we can minimize seismic activity as much as we can.”

A new approach to preventing human-induced earthquakes

Applied in the field, a new model reduced quakes from oil and gas processes; could help manage seismic events from carbon sequestration.

Jennifer Chu | MIT News Office
Publication Date :July 28, 2021

Researchers have found a way to reduce earthquakes triggered by wastewater injection following oil and gas processes such as drilling and fracking.

When humans pump large volumes of fluid into the ground, they can set off potentially damaging earthquakes, depending on the underlying geology. This has been the case in certain oil- and gas-producing regions, where wastewater, often mixed with oil, is disposed of by injecting it back into the ground — a process that has triggered sizable seismic events in recent years.

Now MIT researchers, working with an interdisciplinary team of scientists from industry and academia, have developed a method to manage such human-induced seismicity, and have demonstrated that the technique successfully reduced the number of earthquakes occurring in an active oil field.

Their results, appearing today in Nature, could help mitigate earthquakes caused by the oil and gas industry, not just from the injection of wastewater produced with oil, but also that produced from hydraulic fracturing, or “fracking.” The team’s approach could also help prevent quakes from other human activities, such as the filling of water reservoirs and aquifers, and the sequestration of carbon dioxide in deep geologic formations.

“Triggered seismicity is a problem that goes way beyond producing oil,” says study lead author Bradford Hager, the Cecil and Ida Green Professor of Earth Sciences in MIT’s Department of Earth, Atmospheric and Planetary Sciences. “This is a huge problem for society that will have to be confronted if we are to safely inject carbon dioxide into the subsurface. We demonstrated the kind of study that will be necessary for doing this.”

The study’s co-authors include Ruben Juanes, professor of civil and environmental engineering at MIT, and collaborators from the University of California at Riverside, the University of Texas at Austin, Harvard University, and Eni, a multinational oil and gas company based in Italy.

Safe injections

Both natural and human-induced earthquakes occur along geologic faults, or fractures between two blocks of rock in the Earth’s crust. In stable periods, the rocks on either side of a fault are held in place by the pressures generated by surrounding rocks. But when a large volume of fluid is suddenly injected at high rates, it can upset a fault’s fluid stress balance. In some cases, this sudden injection can lubricate a fault and cause rocks on either side to slip and trigger an earthquake.

The most common source of such fluid injections is from the oil and gas industry’s disposal of wastewater that is brought up along with oil. Field operators dispose of this water through injection wells that continuously pump the water back into the ground at high pressures.

“There’s a lot of water produced with the oil, and that water is injected into the ground, which has caused a large number of quakes,” Hager notes. “So, for a while, oil-producing regions in Oklahoma had more magnitude 3 quakes than California, because of all this wastewater that was being injected.”

In recent years, a similar problem arose in southern Italy, where injection wells on oil fields operated by Eni triggered microseisms in an area where large naturally occurring earthquakes had previously occurred. The company, looking for ways to address the problem, sought consulation from Hager and Juanes, both leading experts in seismicity and subsurface flows.

“This was an opportunity for us to get access to high-quality seismic data about the subsurface, and learn how to do these injections safely,” Juanes says.

Seismic blueprint

The team made use of detailed information, accumulated by the oil company over years of operation in the Val D’Agri oil field, a region of southern Italy that lies in a tectonically active basin. The data included information about the region’s earthquake record, dating back to the 1600s, as well as the structure of rocks and faults, and the state of the subsurface corresponding to the various injection rates of each well


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This video shows the change in stress on the geologic faults of the Val d’Agri field from 2001 to 2019, as predicted by a new MIT-derived model. Video credit: A. Plesch (Harvard University)



This video shows small earthquakes occurring on the Costa Molina fault within the Val d’Agri field from 2004 to 2016. Each event is shown for two years fading from an initial bright color to the final dark color. Video credit: A. Plesch (Harvard University)

The researchers integrated these data into a coupled subsurface flow and geomechanical model, which predicts how the stresses and strains of underground structures evolve as the volume of pore fluid, such as from the injection of water, changes. They connected this model to an earthquake mechanics model in order to translate the changes in underground stress and fluid pressure into a likelihood of triggering earthquakes. They then quantified the rate of earthquakes associated with various rates of water injection, and identified scenarios that were unlikely to trigger large quakes.

When they ran the models using data from 1993 through 2016, the predictions of seismic activity matched with the earthquake record during this period, validating their approach. They then ran the models forward in time, through the year 2025, to predict the region’s seismic response to three different injection rates: 2,000, 2,500, and 3,000 cubic meters per day. The simulations showed that large earthquakes could be avoided if operators kept injection rates at 2,000 cubic meters per day — a flow rate comparable to a small public fire hydrant.

Eni field operators implemented the team’s recommended rate at the oil field’s single water injection well over a 30-month period between January 2017 and June 2019. In this time, the team observed only a few tiny seismic events, which coincided with brief periods when operators went above the recommended injection rate.

“The seismicity in the region has been very low in these two-and-a-half years, with around four quakes of 0.5 magnitude, as opposed to hundreds of quakes, of up to 3 magnitude, that were happening between 2006 and 2016,” Hager says.

The results demonstrate that operators can successfully manage earthquakes by adjusting injection rates, based on the underlying geology. Juanes says the team’s modeling approach may help to prevent earthquakes related to other processes, such as the building of water reservoirs and the sequestration of carbon dioxide — as long as there is detailed information about a region’s subsurface.

“A lot of effort needs to go into understanding the geologic setting,” says Juanes, who notes that, if carbon sequestration were carried out on depleted oil fields, “such reservoirs could have this type of history, seismic information, and geologic interpretation that you could use to build similar models for carbon sequestration. We show it’s at least possible to manage seismicity in an operational setting. And we offer a blueprint for how to do it.”

This research was supported, in part, by Eni.

Earthquakes on Record-Breaking Pace in U.S. Shale, Study Finds

David Wethe
Publishing date: Jun 10, 2021

(Bloomberg) — The number of earthquakes rattling the U.S. shale patch is growing exponentially as producers pump massive amounts of dirty water from their oil and gas wells back underground.

Tremors registering at least a 2 on the Richter scale quadrupled from 2017 levels to a record 938 last year and are on pace to top that this year, according to a Rystad Energy analysis of data in Oklahoma, Texas, Louisiana and New Mexico. Though earthquakes have long been linked to activity related to shale production, the report provides more evidence of the connection in the U.S. Southwest, where oil drilling has intensified in the past decade.

Last year’s jump in earthquakes came even as production tumbled amid the pandemic and the amount of wastewater injected into disposal wells slipped. But water disposal — the biggest culprit behind earthquakes in oil and gas fields — climbed sharply from 2011 through 2019 to more than 12 billion barrels, creating conditions that can make the ground more unstable overall.

The increased tremors and huge volumes of wastewater have added to environmental concerns surrounding oil and gas production from shale fields. Drillers have come under increasing scrutiny in recent years, with companies under pressure from investors to disclose climate risks and reduce greenhouse gas emissions.

“Earthquakes are not the only environmental issue caused by water disposal,” Ryan Hassler, an analyst at Rystad, said Thursday in a report. “Fresh water sourcing in arid regions of West Texas and New Mexico threaten the water supply of local communities and essential agriculture activities, while environmental concerns surrounding the chemical composition of produced water serve only to fan the flames of public antipathy.”

Tremors in shale fields can also be caused by fracking, or blasting apart rock to release oil and gas. Most of those earthquakes, though, are imperceptible. The real danger is that if the oil field is situated along a geological fault, the fractures can cause a chain reaction and trigger a bigger seismic event.

To maintain water disposal at 2020 levels, the industry has to treat and recycle it, which could cost producers more than $1 billion a year, Hassler said.