Justin Kringstad, director of the North Dakota Pipeline Authority, said the companies were building pipelines “at an incredibly fast rate.”
More than 2,400 miles of pipeline, most for natural gas gathering, were built in 2012, a pace that “has caught up to the pace of drilling and now is actually a little bit faster.”
At the same time, processing plant capacity has doubled since 2010 and six gas processing plants will be either built or expanded in North Dakota in the next few years, increasing processing capacity from a current 1.01 million cubic feet of processing capacity to nearly 1.7 million cubic feet of capacity by the end of 2015.
Nevertheless, producers are flaring three times as much gas as only two years ago, even as the percentage of produced gas flamed into the sky has decreased to 29 percent, from 36 percent.
“The production and development is outpacing the safeguards to the environment,” said Wayde Schafer, conservation organizer for the Sierra Club in North Dakota.
Under current North Dakota law, oil companies can flare gas for the first year of a well’s production, which is often the time when the most gas bubbles up. If they can show that it is not economically feasible to connect to a pipeline after the first year, they can get an extension and continue flaring.
“It will take a combination of entrepreneurship, the companies being embarrassed and tighter regulation,” said Connie Triplett, a Democratic state senator pressing for tighter controls. She characterized a recent move by the Legislature to offer tax incentives to companies that capture rather than flare gas as “a baby step” in the right direction.
“I always worry about regulations,” said Mr. Langford, Statoil’s vice president. “If we need to hyper-focus, then let’s really hyper-focus on flaring now and accelerate. We’ll end up with technologies that hopefully we can pass on.”
The railroad giant BNSF, which now ships the majority of Bakken crude oil out of the state, is preparing to test North Dakota’s abundant and cheap natural gas as an alternative fuel to far more expensive diesel for its locomotives. And two companies have begun planning construction of two giant fertilizer plants, representing nearly $3 billion in investments in the state, which would use North Dakota’s natural gas as a feedstock and supply farmers in the Dakotas, Minnesota, Montana and Canada.
Michael Hosford, global general manager for unconventional resources at G.E. Oil and Gas, said he hoped to quickly work out the kinks in G.E.’s venture with Statoil and expand it globally. “It’s not North Dakota-bound; it is all over the world,” he said. “It’s China; it’s Nigeria. It’s very much an international concern.”
Natural gas flaring around the world results in emissions of 400 million tons of carbon dioxide a year, according to the World Bank. That is equivalent to the emissions of 77 million cars, and much of that wasted gas is produced in countries where natural gas could provide power to people who subsist without electricity.
But the problem here in North Dakota remains nettlesome.
The effort to stem flaring is complicated by the sheer size of the Bakken — which at more than 15,000 square miles is the most extensive oil field in the country — and the frenzy of drilling that has doubled oil production in the last two years to a million barrels a day.
So many wells are being drilled that energy experts expect an additional 40 percent increase in the gas produced in the field by the end of 2015.
Industry executives say they will eventually bring the flaring under control, though that might not happen until the 2020s. “By the end of 2015, you’ll see a significant decrease in flame volumes,” said Brad Borror, a spokesman for Oneok, the leading gas pipeline and gas processor company in the Bakken.
The first step of the process is to strip out of the gas valuable natural gas liquids like butane and propane, which can be used for petrochemical production. The liquids can then be put in pressurized tanks and delivered by truck to processing plants. The rest of the gas can be compressed and stored in what G.E. calls “C.N.G. in a box.”
The device was originally designed to be a mobile natural gas station to fill up cars, trucks and buses. But Statoil plans to use the boxes to fuel equipment, particularly drilling rigs that have already been converted to replace 40 percent of the diesel they burn with gas.
By Statoil’s calculations, if all the rigs in the Bakken were converted to run even partly on natural gas, more than 60 million cubic feet of natural gas — or roughly a fifth of the gas now being flared — could be saved every day.
Statoil is also bringing new equipment to the Bakken for fracking — the high-pressure injection of water, sand and chemicals that forces open the deep underground shale rock — that can also run on a mix of diesel and natural gas.
The costs of the program are modest. A General Electric compression box costs about $1.1 million, and the mobile processor costs about $500,000, according to Statoil executives. The company hopes to get the first pilot running by early January and have up to eight compression units running by the end of 2014.
“If we can show a successful pathway to adopting natural gas in high-horsepower applications — rigs, frack crews, heavy duty trucking, railways — that will increase demand,” said John Westerheide, the strategic marketing leader for unconventional resources at G.E. Oil and Gas. And if demand goes up, energy economists say, natural gas prices will also go up and further increase incentives to capture it.
Other companies already have their own plans to make the gas more of an economic asset.
From NY Times
December 17, 2013
Applying Creativity to a Byproduct of Oil Drilling in North Dakota
By CLIFFORD KRAUSS
WATFORD CITY, N.D. — Viewed from outer space, the 1,500 blazing oil well flares burning off excess natural gas illuminate the plains of western North Dakota more brilliantly than Minneapolis hundreds of miles away.
The gas being burned in the Bakken field is a byproduct of a frenzy of oil drilling in isolated areas where there are too few gas-gathering lines and few limits on drilling. In total, the excess gas could heat a million homes, releasing roughly six million tons of carbon dioxide into the atmosphere every year — roughly equivalent to three medium-size coal-fired power plants.
That level of emissions is three times as great as only two years ago, outraging environmentalists, encouraging landowners to sue oil companies and prompting lawmakers to push for tighter regulations.
But for A. Lance Langford, Statoil’s vice president for Bakken development and production, and other energy executives, the flaring problem can be the mother of invention. “You take a problem and you turn it into an opportunity,” he said. “We’re trying to think outside the box.”
Oil companies and other industries are intensifying their efforts to stem the flaring, like building more pipelines and gas processing plants, planning new fertilizer factories that use natural gas as a feedstock and converting rigs and other equipment to use natural gas as a fuel.
But so far, the companies have been losing ground, and will probably not reduce the amount of flaring to the level of other oil-producing states for at least another five years.
Statoil, the Norwegian oil giant, is teaming up with General Electric here in the wheat fields of McKenzie County, the heart of the Bakken field, on a low-cost prototype it hopes will be used as far away as Africa and Asia, where gas now flared could be gathered for cooking and other uses.
TransCanada Expects to Start Southern Leg of Keystone Pipeline Jan. 22
Also Known as Marketlink, the Line Is the Southern Leg of the Keystone XL Project
By Chester Dawson
CALGARY— TransCanada Corp. TRP.T -0.13% said Tuesday it expects Jan. 22 to start crude-oil shipments on its Gulf Coast oil pipeline, which will take oil from the pricing and storage hub in Cushing, Okla., to refiners in Texas.
The line, also known as Marketlink, is the southern leg of the controversial Keystone XL project that would take hundreds of thousands of barrels of crude from Canadian and U.S. oil fields, such as the Bakken in North Dakota, to the Gulf Coast.
"This is another important milestone for TransCanada, our shippers and the refiners on the U.S. Gulf Coast who have been waiting for this product to arrive," the company said in a statement.
TransCanada said it began informing its customers about the startup date late in the day Monday.
Earlier this month, the pipeline operator filed documents with the Federal Energy Regulatory Commission saying it expected to begin crude shipments as early as Jan. 3.
That FERC filing prompted U.S. oil prices to a one-month high.
The Calgary-based company, however, said Jan. 3 was never meant to be the official start date for Marketlink.
In November, crude oil stored in Cushing hit its highest level since July. U.S. oil production is booming, as hydraulic fracturing and horizontal drilling techniques have enabled energy producers to access crude trapped in shale rock.
At the same time, infrastructure growth, including pipeline expansions, to carry the crude to the refineries along the Gulf Coast has been limited, allowing supplies to build up in Cushing and keeping U.S. oil prices low.
On Tuesday, U.S. oil futures declined as traders wait on an announcement from this week's Federal Reserve meeting. Light, sweet crude for January delivery settled 26 cents, or 0.3%, lower at $97.22 a barrel on NYME
North Dakota, the nation's No. 2 oil producer behind Texas, is on pace to surpass 1 million barrels daily early in 2014.
North Dakota oil began being shipped by trains in 2008, when the state reached its then-capacity for pipeline shipments. Helms said that he expects as much as 90 percent of the state's crude will move by rail in 2014, up from about 60 percent at present.
North Dakota oil drillers increasing are tabbing trains to ship crude due to lack of pipelines or to reach more lucrative markets not served by them.
About a dozen mile-long oil trains, which typically consist of up to about 100 railcars laden with about 60,000 barrels of crude, are leaving North Dakota daily, Kringstad said. Each tank car can carry about 650 barrels, or more than 27,000 gallons of oil, he said.
Kringstad said North Dakota's 22 railed oil loading facilities have the capacity to ship about 900,000 barrels daily. Two additional rail facilities under construction will increase the capacity to more than 1 million barrels next year, he said.
North Dakota mulls study of state's oil volatility
North Dakota mulls study to disprove that trains hauling state's oil are dangerously explosive
By James Macpherson, Associated Press
BISMARCK, N.D. (AP) -- North Dakota officials are considering crafting a report that the state's top oil regulator says would disprove that hauling crude by rail from the rich Bakken and Three Forks formations is dangerously explosive.
Lynn Helms, director of the state Mineral Resources, told North Dakota lawmakers last week that some people are attempting to raise fears about railing North Dakota crude, after a train hauling it derailed and exploded in a small Quebec city in July, killing 47 people and destroying much of the town.
Helms, a chemical engineer, said his agency and the state Pipeline Authority are working to create a white paper that would study the characteristics of the state's oil "to dispel this myth that it is somehow an explosive, really dangerous thing to have traveling up and down rail lines."
State Mineral Resources spokeswoman Alison Ritter said the agency is unaware of any studies that have been done to compare North Dakota crude to other oils hauled by train.
"We don't have data that says it's more volatile or that it's not as volatile," Ritter said. "Until we have data that reflects otherwise, crude is crude and it's been moved by train for a long time."
Ritter and Justin Kringstad, director of the North Dakota Pipeline Authority, said the funding and authorship of the report have yet to be finalized.
"It's just discussion, at this point," Kringstad said. "We don't have anything official yet. It could go nowhere."
is there any way to check MDU nat gas production. with nat gas prices rising, can MDU bring to market/online more nat gas in short time frame? they have storage in Baker..... I wonder how that can be brought into play? of course if hedged sale of price on nat gas recent increased price doesn't really help....
Oil exports would help with the U.S. trade balance, but far more important is that they would allow energy markets to operate more efficiently. Surging domestic production has led to a mismatch between the oil produced in U.S. fields and the types needed by U.S. refiners. The booming new U.S. fields often produce lighter crude that doesn't match the heavier, lower-quality crude from abroad that U.S. refiners typically handle. Without being able to export oil, U.S. drillers have a more restricted market for their high-quality crude and less incentive to expand production.
Opponents of exporting oil claim that lifting the ban would raise U.S. gasoline prices, but that misunderstands that oil is a global market. U.S. pump prices would continue to rise or fall with world oil prices regardless of exports. But lifting the ban would lead to more domestic production, which means more jobs in oil drilling and services and everything that goes along with such growth. See the booming Williston Basin in North Dakota or the Eagle Ford Formation in South Texas.
The opposition to lifting the ban will also play the energy "independence" card, but the best protection for America's energy supply is more domestic production that exports would induce. Some of the opponents don't want such production precisely because they want to stop the U.S. oil boom so world prices rise and renewable energy can replace fossil fuels. That's what motivates Senator Ed Markey (D., Mass.) and others on the environmental left.
The oil export ban is an example of self-defeating resource nationalism that hurts U.S. investment and the living standards of American workers. It was a bad idea in the 1970s, and today it is merely one more obstacle to America's energy renaissance.
Editorial from WSJ
Review & Outlook
Exporting American Oil
Moniz breaks the taboo against selling U.S. crude overseas.
Dec. 15, 2013 6:58 p.m. ET
The happy paradox of U.S. energy markets is that the domestic fossil-fuels boom has been overwhelming destructive federal government policy. The latest example of emerging common sense is Energy Secretary Ernest Moniz's suggestion last week that the U.S. may need to reconsider its 40-year ban on most oil exports.
"Those restrictions on exports were born, as was the Department of Energy and the Strategic Petroleum Reserve, on oil disruptions," Mr. Moniz told reporters at the Platts Global Energy Outlook Forum in New York. "There are lots of issues in the energy space that deserve some new analysis and examination in the context of what is now an energy world that is no longer like the 1970s."
Thank you, Mr. Secretary. The oil export ban was one result of the oil-price political panic of the 1970s, which created the worst energy policy in U.S. history until the Pelosi Congress arrived in 2007 to repeat some of the same mistakes. Mr. Moniz is right to raise the issue, and we hope his comments will spur Congress into action.
The U.S. oil boom driven by private investment and ingenuity has transformed North American oil markets, and the International Energy Agency estimates America will surpass Saudi Arabia and Russia as the world's largest oil producer by 2015. Yet with a few exceptions, U.S. producers are barred from exporting crude oil without a license from the Commerce Department.
Commerce has been granting more licenses, albeit fitfully, and the U.S. has been exporting a little less than 100,000 barrels a day on average, mainly to Canada. But this is far less than oil producers would be able to export if they didn't have to submit to such ad hoc bureaucratic review.
Senator Edward J. Markey, Democratic of Massachusetts, said in a statement this week, “The growing chorus from the oil industry to change longstanding U.S. law to permit the export of American crude oil is a disturbing trend.” He added, “This oil should be kept here in America, to benefit our consumers and to reduce our dependence on imports from the Middle East.”
The lobbyists argue that such exports could lower global oil prices, which would bring relief for American consumers. But others, including influential members of Congress, say that oil exports would actually raise domestic gas prices and threaten domestic oil supplies during times of crisis in the Middle East or in Africa.
Mr. Moniz’s remarks were welcomed by oil company executives as a sign that the administration may be moving in their direction on exports.
“If the Department of Energy and others push on Commerce, then maybe they can get it over the hump,” said Chip Johnson, president and chief executive of Carrizo Oil and Gas, a midsize Texas-based oil company active in the shale oil fields. “I think we should keep national security first, but we should export oil just like anything else.”
Oil companies are already beginning to export more oil to Canada since those export licenses are relatively easy to obtain. Canada is the largest exporter of oil to the United States, but since many grades of American oil are selling at a discount to global benchmarks, eastern Canadian refiners are buying American crude to process into diesel and gasoline.
Over the first 10 months of the year, the United States exported an average of 95,000 barrels of crude oil a day, mostly to Canada, according to the Energy Department. Over the same period in 2012, the United States exported an average of 67,000 barrels a day and 23,000 barrels a day in 2007, when American oil production began its expansion.
Some analysts predict that exports to Canada will soon approach 200,000 barrels a day.
But some Democratic lawmakers are already voicing concerns about exports.
Energy Secretary Voices Concern Over Dated Oil Export Restrictions
By CLIFFORD KRAUSS
Published: December 13, 2013
Houston — Signaling a possible break with 40 years of energy policy, Energy Secretary Ernest Moniz has suggested that it may be time for the Obama administration to reconsider the nation’s ban on exporting domestically produced crude oil.
Congress made most oil exports without a license illegal in the 1970s to conserve supplies at a time when OPEC oil embargoes produced long lines at gas stations and threatened the American economy. But over the last five years a frenzy of oil drilling in shale rock formations in Texas and North Dakota have produced a glut of crude in the Midwest and Gulf of Mexico states.
“Those restrictions on exports were born, as was the Department of Energy and the Strategic Petroleum Reserve, on oil disruptions,” Mr. Moniz said in remarks to reporters at the Platts Global Energy Outlook forum in New York on Thursday. “There are lots of issues in the energy space that deserve some new analysis and examination in the context of what is now an energy world that is no longer like the 1970s.”
The Energy Department does not have the power to relax restrictions on exports but Mr. Moniz said the it would be willing to produce technical analysis on the issue for the Commerce Department which issues the export licenses.
Oil companies are lobbying to allow exports, arguing that the United States could substantially increase export earnings from selling high-quality crudes abroad. That type of crude oil is not always easily refined by American refineries that were outfitted for processing lower-quality crudes imported from Mexico, Venezuela and the Middle East.
"I'm reluctant to call a top" to the current rally, said Lee Kayser, portfolio manager at Russell Investments, whose Russell Commodity Strategies fund manages $1.2 billion in assets. The fund tracks the Dow Jones-UBS Commodity Index. However, Mr. Kayser is underweight gas futures, meaning he holds less than the index as a share of his portfolio.
To be sure, some investors say they have seen short-lived winter rallies before. Natural-gas prices typically rise at this time of year, as traders anticipate higher demand, only to fall when temperatures climb. Supplies are still high by historical standards, while production continues to grow.
Many investors are "overzealously adjusting end-of-season storage models," and are downplaying production growth, said Michael Kuchta, a trader at Battalion Capital Management LLC, a Plainsboro, N.J., firm that manages $10 million in assets. He said he is betting natural-gas prices will decline in the next two to four weeks.
Emil van Essen, head of commodity trading adviser Emil van Essen LLC, said he is betting gas prices in March will be higher than in April, a wager he said will profit from any rush into the market when temperatures drop. However, he said gas prices will have difficulty rising above $5/mmBtu given high inventory levels.
If natural-gas prices go "too high, I want us to be short this market because I do not think we are going to run out of gas," said Mr. Van Essen, who manages $175 million. "I think the [natural-gas] market is going up, but then it's coming down."
The sharp gains reflect a rare instance of tightening supplies in a market that has seen record-high production in recent years. A domestic shale-gas boom, driven by technology breakthroughs including hydraulic-fracturing and horizontal-drilling techniques, has boosted U.S. output, overwhelming demand and filling underground storage caverns around the country. Even after recent gains, gas prices remain well below the average price of more than $6/mmBtu seen in the mid-2000s, before shale production took off.
Now these caverns and storage facilities are being drained. Supplies are down 7.2% from a year ago, according to the EIA.
Other forces are driving up demand as well. Years of cheap gas have prompted many power plants to switch from coal to gas as their main source of energy. Additionally, vehicles that run on natural gas have become more popular.
This year, wintry weather arrived early, with arctic air sweeping into the Midwest and Northeast—the two main regions that rely on gas for heating—before Thanksgiving. Heating degree days, a measure of demand that rises when temperatures are colder, reached their highest level for November since 2000, according to the National Weather Service.
Bentek Energy, owned by McGraw Hill Financial Inc., estimates that natural-gas demand averaged 111 billion cubic feet a day between Dec. 6 and Thursday, the second-highest figure since the company began tracking consumption in January 2005.
Supplies have been further stretched as the chill froze equipment in gas fields across Texas and other states, limiting production.
This December could be one of the coldest since 1983, the "benchmark for cold Decembers," said Jim Southard, meteorologist for Frontier Weather Inc. in Tulsa, Okla. Midwestern states could see temperatures as low as 30 degrees below average in the days leading up to Christmas, helping support natural-gas prices, he said.
Natural-Gas Prices Heat Up
By Nicole Friedman And Brett Philbin
Dec. 12, 2013 7:43 p.m. ET
The big chill gripping the U.S. is heating up the natural-gas market. Prices climbed to a two-and-a-half-year high on Thursday as one of the coldest autumns in more than a decade has kept stoking demand for the heating fuel.
The run-up has helped investors who bet that gas prices would rise once temperatures fell. But it is bad news for utilities, which use gas to fuel power plants but are prevented in many states from immediately passing higher prices along to consumers. If the rally is sustained, it will spell relief for producers, which have struggled with low prices for years as output has soared.
As cold weather set in across the Midwest and Northeast in November, utilities have been forced to use more gas, sending prices up more than 26% since Nov. 1. The added demand has sapped supplies. Gas in storage dropped by 81 billion cubic feet last week to their lowest level for this time of year since 2008, the Energy Information Administration said Thursday.
Natural-gas futures rose 7.2 cents, or 1.7%, to $4.409 per million British thermal units Thursday, the highest price since July 2011. Natural gas is the best performer this year among the 22 commodities in the Dow Jones-UBS Commodity Index.
Investors say gas could keep climbing for as long as the cold spell lasts—potentially through December, according to some forecasters. Supplies are down from a year ago, while demand is rising as power plants switch from coal to gas.
"There's a lot of people that are getting bullish at these levels," said Jason Williams, a commodity broker for Coquest, a brokerage in Dallas. "People are worried about supply." He said he thinks prices can rise another 10% by the end of the year.
The new legislation alters the constitution to permit non-Pemex companies to join in exploration and production projects for oil and gas. Foreign companies will even be allowed to take control of produced oil. Mexico will have to make sure that the law's implementing rules are written in a way that gives investors certainty that they can capitalize on their investment. But if they are, then Mexico will begin to emerge as a global energy powerhouse the way that Canada and parts of America have.
The surge in economic activity—in energy and related indutries—will add wealth and jobs for the Mexican people, who inhabit an economy that has underachieved for decades. The energy law continues a trend that began with a series of pro-market presidents and continued with the North American Free Trade Agreement in 1993.
Speaking of underachieving, the U.S. can't even muster the political will to welcome the economic boon that would come from building a single pipeline to carry crude oil from Canada to Texas refineries. We don't need fist fights in Congress to approve the Keystone XL pipeline. Just a simple yes from one U.S. President. Who's a dinosaur now?
editorial from WSJ
Review & Outlook
The Mexican Model
A new energy law will be a boon to all of North America.
Dec. 12, 2013 7:34 p.m. ETUSA stands for United States of America—the world's No. 1 superpower. Yet USA has a national government that can't reform its anti-economic tax code, can't reform its ancient entitlement programs and can barely eke out a de minimis budget deal.
So it is a pleasant surprise, and frankly a bit embarrassing, to draw attention to a remarkable political event down Mexico way. On Thursday, Mexico's Congress passed what could be the most transformative economic legislation there in a century. The members had a few fist fights and some screamed "treason," but the lower House still voted to expose the state oil company, Petroleos Mexicanos, to the free market. And at 354-134, the vote wasn't close.
It is hard to overstate what this means, both as a political accomplishment and potential boon to the economy of Mexico and North America. For most of the past century, Mexico has treated its state-owned oil company, Pemex, as part of the national patrimony. Permitting participation by foreign oil companies or investors in developing Mexico's huge oil reserves was regarded as, well, unpatriotic. Reforming Pemex, like reforming America's Social Security system, was the "third rail" of Mexican politics. Which meant that Mexico's oil wealth sat underdeveloped.
Mexican President Enrique Peña Nieto was elected last year on a promise to change the status quo. This would be like the Democrats leading a real reform of the U.S. entitlement state. Mr. Nieto's party, the PRI, was known for decades as "the dinosaurs."
Oklahoma does have natural seismic activity, he noted, and has had a few powerful quakes in the past, including one with a magnitude of 5.5 in 1952 and one estimated at about a magnitude of 7 that the geological record shows occurred 1,300 years ago. He also thinks changes in the water level of a large nearby lake may be responsible for some of the quakes around Oklahoma City, although he says this is not the most likely explanation.
The swarm of quakes has state regulators concerned, but cautious.
“We have to look at what data and scientific evidence supports some connection,” before deciding on steps to manage the risk, said Dana L. Murphy, a commissioner with the Oklahoma Corporation Commission. Theoretically, at least, the commission could order some wells to be shut.
Already the commission has reached an agreement with a disposal well operator in Love County, about 100 miles south of Oklahoma City, to reduce the amount of wastewater injected into his well. The facility had been operating for only two weeks, injecting up to 400,000 gallons of water a day from nearby fracking operations, when earthquakes started occurring in September, including one that toppled a chimney and caused other damage.
All the shaking in the state has people talking about what to do if a bigger one were to hit. “I’ve been through a lot of tornadoes — you can go hide from them,” said Bill Hediger, whose home in Edmond, just north of Oklahoma City, shows cracks in the walls from the magnitude 5.6 quake. “But you can’t hide from an earthquake.”
Dr. Holland said that given the geological record, he could not rule out the possibility that a larger quake may occur in the state.
Ms. Sexton said she was not against the oil and gas industry, but added that if the quakes in her area were definitively linked to disposal wells, they should be shut down.
“It would hurt oil and gas,” she said. “But it’s oil and gas hurting homeowners and making people fearful.”
The practice of hydraulic fracturing, or fracking — injecting liquid at high pressures into shale rock — causes very small tremors as the rocks break, releasing trapped oil or gas. The technique has also been linked to a few minor earthquakes — in Oklahoma about a year ago, and in England and British Columbia. Yet unlike the continuing clusters of quakes elsewhere, the fracking-related earthquakes occurred only over short time periods, scientists say.
Of greater potential concern, scientists say, is wastewater disposal — from fracked or more conventional wells. Disposal wells linked to quakes have been shut down in a few states, including Arkansas and Ohio.
Along with oil and gas, water comes out of wells, often in enormous amounts, and must be disposed of continuously. Because transporting water, usually by truck, is costly, disposal wells are commonly located near producing wells.
The oil and gas industry points out that many of Oklahoma’s disposal wells are in areas with no earthquake activity, and that the practice of injecting wastewater has been going on for years.
“We’ve been doing this for a long time and it hasn’t been an issue before,” said Chad Warmington, president of the Oklahoma Oil and Gas Association.
But Dr. Frohlich said that what had changed was where the disposal was occurring. With the boom in production of oil and gas from shale formations, he said, “People are disposing of fluids in places they haven’t before.”
Still, it is difficult to show a definitive link between a group of quakes and nearby disposal wells, and Dr. Holland thinks there may be other explanations for some of the recent quakes, including the largest one, which occurred on a known fault line about 50 miles east of Oklahoma City.