Oil, gas commission approves injection well near Platteville despite protest — The Greeley Tribune

July 29, 2014
Deep injection well

Deep injection well

From The Greeley Tribune (Sharon Dunn):

Platteville rancher Roy Wardell was asking questions long before an earthquake shook the ground around Greeley. The oil and gas wastewater injection well proposed near his ranch would be the sixth in the immediate proximity to his small operation. It only made sense that adding another high pressure well in a line of other high pressure wells would tempt fate. Then came May 31. An earthquake rattled Greeley for a second or two, and his fears were confirmed.

“This is a concentration of wells that doesn’t exist anywhere else in Weld County,” Wardell told the Colorado Oil and Gas Conservation Commission in Greeley on Monday. “My concern is you cannot confidently say there’s not a seismic risk. It flies in the face of logic.”

He was asking that an injection well near his ranch proposed by High Plains Disposal be denied, given its proximity to other injection wells. Injection wells have been linked to earthquakes across the country. The majority of them operate for years without incident, while a few others don’t.

Oil and gas well wastewater is injected into deep underground wells into porous formations. Seismic activity occurs when water slips through geologic structures, allowing movement. The process of injection is considered more environmentally friendly than the process a decade ago of dumping used well water into pools at the well site.

All injection wells in Colorado undergo testing for a variety of concerns, including seismic activity. At present, there are 28 injection wells in the county, with another 20 in the permitting process.

The operator of the Greeley well, out by the Greeley-Weld County airport, is under investigation for potential violations after researchers, in a 20-day period in which NGL was required to stop injecting water, isolated the well as the cause of the earthquake and about a dozen smaller ones since. That well is 18 miles north of the proposed well near Wardell’s ranch.

In a hearing before the COGCC, state officials and representatives of High Plains Disposal discussed their plans to ensure safety, including placing seismic monitoring equipment at the well to act as an early-warning system of any induced activity. They said the Greeley well had different circumstances than the one High Plains had proposed, including drilling into a different formation.

Commission members stated while the concern is there, they felt comfortable with approving the well.

“If I were a landowner, I’d have the same concerns that there is a possibility for seismic activity,” said Commissioner Bill Hawkins. “All the technical testimony given today indicates it is not likely, and there really isn’t any reason we can see other than the fact that a well 20 miles away had seismic activity. Certainly seismic activity is of concern to the public and a large part of the county, and it’s a concern to the commission. If there is any activity we would definitely stop, (it is) injections.”

Commissioner Mike King agreed, stating that if there is any seismic activity associated with the well, they would respond just as they did with the Greeley well, and shut off injections immediately.

“Things change,” said King, also the director of the state Department of Natural Resources. “We found out in other wells there were some factors that weren’t as clear … (and it) caused us to take a 20-day timeout, to see what we missed, what things needed to change. … I’m comfortable, although in the last month, I’ve become less comfortable in general. I’m OK with being a little more on edge until we get more information.”

Wardell knew he was fighting a losing battle.

“I feel heard,” he said after the meeting.

More oil and gas coverage here.


COGCC requires changes at injection well after review finds potential linkage to seismic activity

July 20, 2014

Deep injection well

Deep injection well


From the Colorado Oil and Gas Conservation Commission (Todd Hartman):

The Colorado Oil and Gas Conservation Commission has required operators of a wastewater injection site in Weld County to make changes to their well and adjust their disposal activities after determining actions at the location are potentially related to low-level seismic activity nearby.

On June 23, the COGCC directed NGL Water Solutions DJ LLC* to stop disposing wastewater into the well for a 20-day period while the agency worked with the operator and a team of University of Colorado researchers to determine whether deep injection at the site may be tied to recent seismic activity detected within the general vicinity. Following a 3.2 magnitude event on May 31, seismometers placed by CU recorded other small earthquakes, including one of magnitude 2.6 on June 23.

Since the shutdown, the COGCC has further analyzed data associated with the injection well, as well as seismic data recorded by a local network of instruments placed and maintained by CU geophysicists. While seismic activity in the area around the well continued during the shutdown period, it occurred at a lower energy level, according to the CU researchers.

Flow rate tests conducted by NGL indicated a high permeability zone near the bottom of the well that created a preferred pathway for injected wastewater. As a result of the findings, NGL, with approval and oversight from the COGCC, has plugged the basement of the well from a depth of 10,770 feet to 10,360 feet in order to seal off the preferential pathway and to increase the distance between the zone of injection and “basement” rock. These measures are expected to mitigate the potential for future seismic events.

Beginning Friday, July 18 the COGCC will allow NGL to resume limited injections, at lower pressures and lower volumes, under continued seismic monitoring, to ensure the facility is operating safely. Specifically, the operator will be permitted to inject at an initial maximum rate of 5,000 barrels per day with a maximum pressure of 1,512 psi. After 20 days, the maximum injection rate may be increased to 7,500 barrels a day at the same pressure.

Continued use of the injection well will be reviewed and may be halted if seismic events within a 2.5-mile radius of the well occur at or above a magnitude of 2.5 – the U.S. Geological Survey’s default threshold for displaying seismic events. CU geophysicists will continue to monitor the location, and the COGCC has required NGL to install a permanent seismometer near the well to allow for real-time monitoring. The company is also required to provide access to the monitor and all its data to the COGCC and any third parties authorized by the agency.

“We are proceeding with great care, and will be tracking activities at this site closely,” said Matt Lepore, director of the COGCC. “We’re moving slowly and deliberately as we determine the right course for this location.”

The COGCC is also reviewing a potential violation of the operator’s permitted injection volumes. The matter remains under investigation and any further information on possible enforcement would be contained in a Notice of Alleged Violation from the agency. Such a determination could result in financial penalties against the company.

The well, SWD C4A, is located east of the Greeley-Weld County Airport. It was permitted by COGCC in March 2013 and injection began in April of 2013.

More oil and gas coverage here.


Water Lines: Colorado needs a better water plan — Jim Pokrandt #ColoradoRiver #COWaterPlan

July 16, 2014


From the Glenwood Springs Post Independent (Jim Pokrandt):

It’s almost time for football training camps, so here’s a gridiron analogy for Colorado River water policy watchers: Western Colorado is defending two end zones. One is the Colorado River. The other is agriculture. The West Slope team has to make a big defensive play. If water planning errs on the side of overdeveloping the Colorado River, the river loses, the West Slope economy loses and West Slope agriculture could be on the way out.

This is how the Colorado River Basin Roundtable is viewing its contribution to the Colorado Water Plan ordered up by Gov. John Hickenlooper. A draft plan will be submitted this December and a final plan in December 2015. The Roundtable is assessing local water supply needs and environmental concerns for inclusion into the plan and there is plenty of work to consider in the region. But the big play may very well be the keeping of powerful forces from scoring on our two goal lines.

Here’s why: Colorado’s population is slated to double by 2050. Most of it will be on the Front Range, but our region is growing too. Mother Nature is not making any new water. We still depend on the same hydrological cycle that goes back to Day 1. So where is the “new” water going to come from? Right now, there seems to be two top targets, the Colorado River and agriculture (where 85 percent of state water use lies in irrigated fields). Colorado needs a better plan.

The Colorado Basin Roundtable represents Mesa, Garfield, Summit, Eagle, Grand and Pitkin counties. This region already sends between 450,000 and 600,000 acre feet of water annually across the Continental Divide through transmountain diversions (TMDs) to support the Front Range and the Arkansas River Basin.

That water is 100 percent gone. There are no return flows, such as there are with West Slope water users. On top of that, this region could see another 140,000 acre feet go east. A number of Roundtable constituents have long-standing or prospective agreements with Front Range interests wrapped around smaller TMDs. Existing infrastructure can still take some more water. That’s the scorecard right now. We assert another big TMD threatens streamflows and thus the recreational and agricultural economies that define Western Colorado, not to mention the environment.

In the bigger picture, the Colorado River Compact of 1922 requires Colorado to bypass about 70 percent of the river system to the state line to comply with legal limits on depletions so six other states can have their legal share of the water. Failure to do so, by overdeveloping the river, threatens compact curtailments and chaos nobody wants to see. For one thing, that kind of bad water planning could result in a rush to buy or condemn West Slope agricultural water rights.

The Roundtable has heard these concerns loudly and clearly from its own members across the six counties as well as from citizens who have given voice to our section of the water plan, known as the Basin Implementation Plan (BIP). A draft of the BIP can be viewed and comments offered by going online to http://coloradobip.sgm‐inc.com/. It is under the “Resources” tab.

Jim Pokrandt is Colorado Basin Roundtable Chair.

More Colorado Water Plan coverage here.


Garfield County Commissioners approve deep injection well

July 15, 2014
Deep injection well

Deep injection well

From The Grand Junction Daily Sentinel (Dennis Webb):

Garfield County commissioners on Monday approved an oil and gas wastewater injection well near Battlement Mesa after the company responded to concerns that it could trigger earthquakes.

Duke Cooley, senior geologist at Ursa Resources, told commissioners there’s been no correlation between oil and gas injection wells and earthquakes in northwest Colorado’s Piceance Basin.

The Battlement Concerned Citizens group and the Battlement Mesa Service Association, a homeowners group for the unincorporated community, had raised the seismic issue amid mounting concern about an apparent correlation between oil and gas injection wells and earthquakes in several states. Last month, the Colorado Oil and Gas Conservation Commission suspended operation of an injection well in Weld County after a 3.4 magnitude earthquake struck in the Greeley area May 31, followed by smaller quake in June.

“It was a wake-up call. It was the first seismic event there in 30 years,” Doug Saxton of Battlement Concerned Citizens told Garfield commissioners.

He cited what he said is a lack of adequate earthquake monitoring by the U.S. Geological Survey.

“Nothing under 4.0 (magnitude) really gets their attention,” Saxton said.

Monitoring sites

He said the agency’s closest monitoring site is 75 miles from Greeley, and the nearest to Battlement Mesa is in the Paradox Valley. He called for the installation of monitoring equipment in the Battlement area and for Ursa to cease injection activity if a quake occurs.

But Cooley said a local monitoring station isn’t necessary because Geological Survey equipment can detect quakes of less than 1 magnitude hundreds of miles away.

Garfield County already has 60 approved injection wells, and injection has occurred in 26 of them since 2013, according to the county’s oil and gas liaison, Kirby Wynn. Saxton said Ursa’s would be the seventh within 10 miles of Battlement Mesa.

Cooley said seismic activity occurs where there has been geological folding, which in the case of the Piceance Basin is around its margins.

He also said quakes can occur when water is added that reduces friction along a fault plane where geological compression is occurring, in places like Greeley and Oklahoma. The Piceance Basin, by contrast, is now undergoing geological relaxation after previously having been “folded up,” he said.

State oversight

Garfield County has surface authority over injection wells but the state oil and gas commission regulates technical “downhole” aspects of the wells such as injection pressure. Lindy Gwinn of Grand Junction, who consults for the industry, told Garfield commissioners Monday, “I can assure you they turn them down when they are not technically correct and there is any risk.”

She noted that the commission recently did just that in Mesa County. In 2012 it turned down a proposal for an injection well southeast of Grand Junction out of concern it could contaminate ground and surface water due to its shallow depth, and possibly induce earthquakes at the U.S. Department of Energy’s uranium mill tailings disposal site a few miles away.

That well would have been less than 2,000 feet deep. Ursa’s would be more than a mile deep.

In agreeing to approve the well, Garfield Commissioner Mike Samson said, “The COGCC, they kind of go over these injection wells with a fine-tooth comb. … I have faith in the COGCC and their very strict regulations that they have.”

Commissioner Tom Jankovsky agreed, and said if seismic activity did occur in the area, the county would ask companies to cease all injections until the cause could be determined.

He also encouraged Ursa to install pipelines to the injection well as soon as possible to reduce truck traffic. Ursa officials indicated they hope to do that soon, and that reduced traffic resulting from being able to inject wastewater rather than otherwise dispose of it would be one of the benefits of the well.

Said Monique Speakman, who supports the proposal and lives on the property where the well will be operated, “It’s going to eliminate truck traffic, noise, dust levels.”

Battlement Mesa resident Mary Haygood said she had been concerned about both the truck traffic and seismic aspects of the well, but told Ursa officials Monday, “You have allayed my fears somewhat by your explanation and I thank you for that.”

Ursa already has spent $2 million to drill the well. It needed to do that to do testing required by the oil and gas commission before it can approve the well. The agency is continuing to review the proposal.

More oil and gas coverage here.


Climate change: “The fossil-fuel industry…has been able to delay effective action” — Bill McKibben

July 15, 2014

Inylchek Glacier Kyrgyzstan

Inylchek Glacier Kyrgyzstan


Here’s an essay about the risk of doing nothing about climate change from Allen Best writing for The Mountain Town News. Click through and read the whole thing. Here’s an excerpt:

Bill McKibben, a writer and activist, has made the most cogent arguments. Two years ago, after crunching the numbers, he concluded that private companies own five times more carbon in the ground than the world can possibly absorb. “On current trajectories, the industry will burn it, and governments will make only small whimpering noises about changing the speed at which it happens,” he wrote in an essay titled “A Call to Arms” that was published in the June 8 issue of Rolling Stone.

He identifies a clear problem. “The fossil-fuel industry, by virtue of being perhaps the richest enterprise in human history, has been able to delay effective action, almost to the point where it’s too late,” he wrote. [ed. emphasis mine]

McKibben’s 350.org has been fighting the Keystone XL pipeline, which would export Alberta’s bitumen to refineries along the Gulf Coast. It’s largely a symbolic fight, as Michael Levi points out in his book The Power Surge. The tar/oil sands would, if fully developed, elevate atmospheric concentrations of C02 by 60 ppm. At current rates of tar/oil sands mining, that would take 3,000 years, he says. Isolating the climate debate to Alberta’s bitumen, he says, is a mistake.

But Keystone XL represents business as usual. We need accelerated change. The United States should follow the lead of British Columbia in levying a carbon tax. My impression of B.C.’s tax is that it not precisely the best model. We need a revenue-neutral tax, accelerating over time, giving the private sector clear market signals to instigate changes.

Henry Paulson, the former treasury secretary in the Bush years, made this case in an 1,800-word essay in the New York Times on June 22. A few days later, a group that includes Paulson, former New York City Mayor Michael Bloomberg, Stanford’s George Schultz, who is another former treasury secretary, and a number of other high-profile individuals — including billionaire Tom Steyer — released a report titled “The Economic Risks of Climate Change in the United States.”

More climate change coverage here and here.


Rifle: “Many different eyes are on each [drill] pad each day” — Michael Gardner #ColoradoRiver

July 9, 2014

Rifle Gap

Rifle Gap


From the Rifle Citizen Telegram (Mike McKibbin):

Rifle City Council unanimously approved an amendment to the company’s original 2009 watershed district permit to allow the activity, subject to conditions. The 12-square-mile, 8,000-acre watershed, approximately 5 to 6 miles southwest of Rifle, is the source of 9 percent of Rifle’s drinking water. The vast majority of the city’s water comes from the Colorado River. Several years ago, the city established the district and considers permits for certain industrial activities to help protect the water source. The company would also need drilling permits from the Colorado Oil and Gas Conservation Commission.

Michael Gardner, WPX environmental manager, outlined the drilling plans and noted various companies had been active in and near the Beaver Creek watershed since 1999. WPX is currently the only active company in the district. A total of 44 producing wells have been drilled from 11 pads in the district since 1999, with 27 of those wells located on a pad outside the district boundaries, Gardner said.

“What we’re proposing is to drill up to 253 wells from 15 pads between now and 2018,” he told the council last week.

WPX plans to drill up to 23 wells on the existing pad outside of the watershed and up to 112 wells on four new pads outside the watershed, but accessed through the watershed, Gardner noted. Up to 80 wells could be drilled on seven existing pads within the watershed and up to 65 wells on four new pads within the watershed.

“A lot of this depends on the market price for gas, obviously,” Gardner added. “So this is a maximum-case scenario.”

WPX would build access roads, install gathering and water lines and other associated facilities in the area, Gardner said.

WPX spokesman Jeff Kirtland said in an interview Tuesday that the permit amendment was sought to keep the permit active, as it was due to expire soon.

“It’s more to make sure we’re keeping up with what we need to do with the permit,” he stated. “So we would have this permit in hand if prices improved.”[...]

Michael Erion, a water resources engineer with Resource Engineering of Glenwood Springs and a city consultant, said the amendment was acceptable and noted the target area is actually a tributary to Beaver Creek, which itself is often dry in the summer, so most direct activity in the district will be road crossings. The permit was amended last year to allow a water pipeline across the watershed and a temporary 1.5 million gallon water storage tank, Erion noted.

Among the nine conditions already part of the permit and included with the latest amendment is a requirement for WPX to submit detailed drawings to the city at least 30 days before construction. New wells can be drilled on approved pads, provided WPX sends written notice to the city 15 days before that activity. WPX is also required to submit an annual activity plan for the entire district by March 1 of each year, and the project shall be subject to biannual inspections, or more frequently if needed, by the city and/or its consultants.

WPX will also continue to participate in the city’s water quality monitoring program on Beaver Creek. This includes a periodic stream monitoring program with sampling at various locations along the creek and the operation and maintenance costs associated with a 24/7 monitoring system at the city intake structure on the Colorado River.

“We understand how critical this area is to Rifle,” Gardner said. “We have all kinds of plans and procedures for spills, to protect groundwater and storm water control. Many different eyes are on each pad each day.”

He also noted that no reportable spills, as defined by state regulations, had occurred in the district since 2008.

More oil and gas coverage here.


COGCC halts activity at injection well; seeks additional review

June 26, 2014

Deep injection well

Deep injection well


Here’s the release from the Colorado Oil and Gas Conservation Commission (Todd Hartman/Matt Lepore):

The Colorado Oil and Gas Conservation Commission this week directed High Sierra Water Services to stop disposing wastewater into one of its Weld County injection wells.

The company agreed to a 20-day halt to wastewater injection as a cautionary step the COGCC believes necessary to gather and further analyze more information to determine whether injection at the site is tied to recent seismic activity recorded within the general vicinity of the well.

Ongoing monitoring by a team of University of Colorado seismologists has picked up additional evidence of low-level seismic activity near the injection site, including a 2.6-magnitude event Monday afternoon. The additional data comes after a 3.4 magnitude earthquake shook the Greeley area May 31.

“In light of the findings of CU’s team, we think it’s important we review additional data, bring in additional expertise and closely review the history of injection at this site in order to more fully understand any potential link to seismicity and use of this disposal well,” said COGCC director Matt Lepore.

The COGCC will undertake several actions over the shutdown period to include: evaluation of baseline, historical seismic activity; continued coordination with the CU team; coordination with the U.S. Geological Survey and Colorado Geological Survey; evaluation of other disposal wells in the area; and a detailed review of data associated with the well in question, including further examination of injection rates, pressures and volumes.

The company immediately agreed to COGCC’s request, and shut the well down on Monday.

From The Greeley Tribune:

Noble Energy continued on Monday to clean up the oil spill it located Friday along the Poudre River near Windsor, according to a news release from the Colorado Department of Natural Resources.

Noble began to dismantle a damaged tank battery Monday in preparation for soil removal, according to the release, after about 173 barrels — or about 7,500 gallons — of crude oil were found to have spilled from the tank while the Poudre River was flooding.

On Saturday, Noble established site security, repaired the access road and had a crew of approximately 30 people using absorbent pads to clean up visible residual oil, according to the release. Soil samples were collected along the path of the release and submitted for laboratory analysis, according to the release, and the results of that analysis are still pending.

Visual observations by Noble along the flow path indicated the oil did not seep deep into the soil, so removal of the soil was ruled out as the main way to clean up the spill, according to the release.

Instead, a product known as Petro Green was applied to help enhance the degradation of any remaining hydrocarbons, according to the release.

Noble also had a consultant perform a biological study on the area, according to the release, and it was determined no wildlife were impacted by the spill.


Poudre oil spill cleanup update

June 24, 2014
Cache la Poudre River

Cache la Poudre River

From the Associated Press via 9News.com:

Environmental officials and work crews are dismantling a flood-damaged storage tank so they can remove oil-stained soil from an area where about 7,200 gallons of crude leaked into a northern Colorado river.

Todd Hartman, a spokesman for the Colorado Department of Natural Resources, says Noble Energy, which operates the tank, has been cleaning up the site on the Poudre River near Windsor since the leak was discovered Friday. The bank next to the storage tank was undercut by the high spring river flows, causing it to drop and break a valve.

From the Fort Collins Coloradoan (Ryan Maye Handy):

“We consider this a significant spill,” wrote Colorado Oil and Gas Conservation Commission spokesman Todd Hartman in an email Monday. “The vast majority of spills are far smaller. We’ve had larger spills, but those are true anomalies.”

Colorado hasn’t seen a spill this big since September 2013, when a deluge of floodwaters in multiple rivers spilled 48,250 gallons of oil.

The September flooding, along with spills like the one discovered Friday near Windsor, have prompted state regulators and environmental groups to consider increasing the distance between wells and Colorado’s waterways. Today, state law governing the distance between oil wells and water along Colorado’s Front Range does not take into account seasonal flooding, Hartman said.

COGCC has one law that adjusts setbacks for high water marks that applies only to gold medal fisheries or cutthroat trout habitats. The fisheries predominately operate on the Western Slope.

Following the floods, environmental advocates are pushing more than a dozen new oil and gas regulations toward ballots in the November election. One proposal suggests moving setbacks to 2,000 feet from bodies of water. Some experts say that would cripple oil and gas development in places like Weld County, where more than 21,000 wells operate today.

There are about 5,900 oil and gas wells within 500 feet of a Colorado “waterway that is significant enough to be named” and more than 20,000 wells within 500 feet of water of some kind.

The practice of drilling near water originates from “longstanding practical pressures” by mineral rights owners to confine wells to their least productive sections of land, according to a special report on oil and gas development commissioned after the September 2013 floods. It’s also easier to drill for oil in more accessible areas, particularly along waterways.

In the post-flood report, the COGCC recommended that tank batteries “be located as far from waterways as possible,” and that all wells near an ordinary high water mark should have remote shut-in equipment, allowing them to be shut down automatically when waters are high. The report also suggested that regulations should “apply within a designated distance from the ordinary high water mark of all waterways in Colorado.”

Since Friday, Noble Energy crews have been cleaning up after the Windsor-area spill. As of Monday, they have yet to identify any wildlife impacted by the spill, and drinking water has not been polluted, said Hartman. On Friday, Noble Energy, owners of the well, began a biological study of the spill’s impacts. Soil samples were also taken, but the results of those are pending.

The river flooded two tanks off Weld County Road 23, an area surrounded by a cattle ranch and farm land. As crews continued work Monday, bikers sped by along the Poudre River Trail, which winds just on the opposite side of the river from the spill.

The well feeding the tanks was shut May 24 due to spring runoff flooding. Although Noble discovered the spill June 20, the company can’t be sure exactly when the damage was done to the tank.

Each tank can hold 300 barrels of crude oil, with about 42 gallons per barrel. Flood waters had undercut the bank below one battery, releasing the contents of 178 barrels.

Noble has since drained the second tank, which was undamaged, said Hartman. Most of the spill was washed away in the floodwaters, which left a few stagnant polluted pools behind. Clean-up crews used absorbent pads to remove oil from vegetation and water pools. On Monday, crews began to excavate a shallow layer of soil.

More oil and gas coverage here.


Oil spill near Windsor ~7,500 gallons

June 21, 2014

South Platte River Basin via Wikipedia

South Platte River Basin via Wikipedia


From The Greeley Tribune:

About 178 barrels of crude oil, or roughly 7,500 gallons, has spilled east-southeast of Windsor and is affecting the Poudre River, state officials said Friday.

The operator, Noble Energy, discovered the spill Friday and reported it to the Colorado Department of Natural Resources, said Todd Hartman, the department’s communications director.

Noble reported a storage tank affected by spring flood waters released its contents. The release appears to be due to floodwaters undercutting a bank, causing the tank to drop downward and damaging a valve, allowing oil to escape from a broken valve. The well associated with the tank is shut in, and a second tank nearby appears unaffected.

Standing water with some hydrocarbons remains in one low-lying area near the tank, Hartman said.

Vegetation is stained for about one-quarter mile downstream of the site.

Noble had environmental response personnel on site Friday afternoon.

A vacuum truck was removing standing water and response personnel were sampling soils.

The oil storage tank sits next to a field east of Weld County Road 23, on the north side of the Poudre River. The tank sits about 200 feet from the river, up a hill. A lot of flood damage was visible in the area, with washed out and eroded river banks and debris still in the water.

Hartman said water quality staff from the Colorado Department of Public Health and Environment also were at the spill site Friday but have not discovered any impact on drinking water.

More water pollution coverage here.


Weld County earthquake: “Just drill new wells and increase recycling” — Ken Carlson

June 8, 2014
Deep injection well

Deep injection well

From The Greeley Tribune (Sharon Dunn):

The answer to Greeley’s first earthquake in at least 40 years may be sitting 10,000 feet below the surface in a deep-water trash can that might be overfilling.

The oil and gas boom has put added stress on the industry’s resources, more specifically in deep wastewater injection wells that cut two miles below the surface. But some say the answer may be as simple as water management.

Wastewater injection wells — which take in produced water from fracking jobs — may now go under increasing scrutiny in Colorado, as scientists have found strong connections between them and a spate of small earthquakes across the country in recent years.

Still, most injection wells are not linked to any earthquakes; it’s only a tiny fraction of injection wells that have specifically been cited as the cause of a minor quake. It’s a puzzle that continues to grow for seismologists looking for answers.

Researchers from the University of Colorado at Boulder put out seismographic equipment throughout Weld County last week, hoping to cull the earth’s secrets into a database of answers. If injection wells are found to be the common denominator in further quake activity, they’ll capture it.

But in the absence of answers, some would say solutions are not that difficult.

“There are ways to fix this,” said Ken Carlson, an associate professor of civil and environmental engineering at Colorado State University. “This is sort of a byproduct of too much water being disposed of, but it’s not like we should shut it down. That’s what the activists will say. It just means we need to improve our water management. So if you say this is probably related to disposal wells, it isn’t that hard to change our practices and really fix this. Just drill new wells and increase recycling.”

WHAT ARE INJECTION WELLS

Injection wells have long been handy tools for oil and gas companies to dispose of wastewater in an environmentally friendly way. The water is pumped two miles beneath the surface into porous rock, through which the water disperses — allowing more water to be pumped in. The process is highly regulated by the Environmental Protection Agency and state oil and gas regulators. Operators must adhere to disposing of water at tested rates and volumes, so as not to overwhelm the well, and they are subjected to annual inspection and well integrity testing every five years, state officials say.

“In a natural system like that, you can do projections. But until you push it to the limit, you can’t really prove it,” Carlson said, noting that he was clearly guessing. “Maybe it’s never been pushed that high.”

For Anadarko Petroleum Corp., which is working to manage its water resources by using municipal effluents, recycling and piping water into sites rather than trucking, officials say they may be coming close to a “limit” on its injections wells, and have been working toward better management to dispose of less.

“The wells are definitely a cause of concern with induced seismicity,” said Korby Bracken, environmental health and safety manager for Anadarko. “We think they’ll continue to be used but it’s something we’re studying quite a bit. There have been multiple studies in Ohio and Oklahoma and other areas where the injection of produced water from oil and gas had the potential to cause induced seismicity. It’s definitely something we’re taking a look at.”

The puzzling part to seismologists is that some areas rife with injection wells for years have no earthquake activity; still others start quaking the minute the well is drilled. There were two injection wells in proximity to the perceived epicenter of the Greeley quake — one was two years old, and the other was 20.

“There are a lot of variables,” said Justin Rubinstein, a seismologist out of Menlo Park, Calif., who is chief of the Induced Seismicity Project, which studies man-made earthquakes. “Maybe this earthquake relieved everything that was available to be relieved or maybe it didn’t and there will be more. Maybe the operator said I might be causing earthquakes, I need to stop injection or slow injections. Generally, when you slow or stop injections, earthquakes slow down.”

The idea of drilling more injection wells to relieve the pressure on existing wells is favored in the exploration community.

Carlson said the water could get dispersed a bit more evenly, reducing pressure with the oil and gas boom going on in Weld.

“It’s not a bucket,” Carlson explained of the rock in which the water is pumped. “It’s more like a sponge. You put the water in and it gets absorbed, then it diffuses through the formation. But you can’t just put in an unlimited rate and keep raising the pressure. Then something would give, and that something might be a fault. With the growth in fracking and unconventional oil and gas in the DJ, there’s certainly greater demand on some of these water disposal sites.”

Rubinstein said he wasn’t so sure drilling more injection wells is the answer.

“In a different perspective, now you’re covering more areas with injections wells, so maybe you’re increasing the probability of finding an area that has a fault,” Rubinstein said. “There are so many variables out there.”

Rubinstein suggested creating mid-volume wells, alleviating pressure that way. “But I don’t know if it gets you out of the problem,” he said.

Anadarko has a permit pending for an injection well. The company has three in Colorado now, all that are running at capacity.

“That being said, we’re looking at other and alternative ways to recycle the fluids that come from the well bore,” Bracken said. “So we don’t have to rely as much on those saltwater injection wells.”

Water, water everywhere

A typical frack job will use 3 million to 4 million gallons of water, but not all of it comes back once the rock is stimulated 7,000 feet below ground. Typically, about 20 percent of the water comes back to the surface during a frack job.

Companies will take that flowback, treat the water on site to take out harmful bacteria from beneath the ground, and truck or pipe it out for recycling or injection. The rest of the water comes out with the oil and gas over time.

Recent years have shown the technology is available to clean up used fracking water, enough to be reused, much like a municipal wastewater treatment system.

“Some operations are pushing ahead with more recycling,” Carlson said. “The more you recycle, the less you’re disposing of and that’s a good thing.”

Anadarko and Noble are big customers of High Sierra Water Services, which operates two recycling facilities in Weld County. Two of their facilities together can recycle about 20,000 barrels a day (840,000 gallons). Both companies have worked on both ends to recycle water.

Anadarko, for example, takes effluent from the city of Aurora’s wastewater treatment plant for most of its fracking operations, then reuses the water over and over.

“If you put down 10 units of something and only get two back, you have to make up eight units for the next well,” Bracken explained. “We’ll recycle what comes back, add make-up water, put it downhole, recycle what comes back and, eventually, you’re recycling the same molecule of water over and over again.”

Both companies are piping recycled water to and from recycling facilities.

But not all water can be recycled. Sometimes it’s too salty. That’s where injection is most necessary.

“Some of the water is very saline,” Rubinstein said. “Some of the water they’re producing in Oklahoma is … 15 percent salt. Salt is highly corrosive. They really can’t reuse it.”

Though reusing the water is the ideal, there’s simply not enough storage out there to hold the water.

“I guess I’d say there is the ability to now recycle probably 15 to 20 percent of the 100,000 barrels a day coming out of the DJ,” said Josh Patterson, operations director for High Sierra. A third recycling center is in the planning stages.

“Logistically speaking, there wouldn’t be a reservoir large enough to store every barrel (of wastewater) for it to be re-used,” Patterson said.

Costs of recycling are high, but so are trucking costs. If companies can eliminate trucking in new water, and recycle existing water, that takes trucks off the road and reduces those expenses.

Patterson said the demand for water recycling continues to grow, however, with both of High Sierra’s facilities contracted out for the next five years.

From the Associated Press via the Fort Collins Coloradoan:

The Greeley Tribune reported Friday that [geophysicist] Anne Sheehan and a team of graduate students have been deploying seismographs to study the magnitude 3.4 quake. The U.S. Geological Survey determined the epicenter of the quake was believed to be 5 miles beneath the surface about 4 miles northeast of Greeley.

The suspected epicenter is near two injection wells. The May 31 earthquake caused no damage.

“If we find out something useful about whether injection causes earthquakes, it might be something that the industry can use to do a better job of injecting, if that turns out to be a problem,” Sheehan said.

Weld County has 28 injection wells for oil and gas waste, or “Class II” disposal wells.

State drilling regulators said earlier this week they were skeptical that the wells caused the earthquake.

The epicenter is difficult to determine, said Justin Rubinstein, a seismologist in Menlo Park, California, who has studied the increasing phenomenon of man-induced earthquakes for the past three years.

More oil and gas coverage here.


CU research team studying earthquake activity near Greeley — The Greeley Tribune

June 6, 2014
Deep injection well

Deep injection well

From The Greeley Tribune (Sharon Dunn):

A small team of Boulder graduate students and their professor hope to soon put an end to the mystery of what created a small magnitude earthquake on Saturday northeast of Greeley.

While the quake measured 3.4 in magnitude — barely enough to be felt and not enough to cause damage to structures — the coincidence of its proximity to wastewater injection wells has researchers pondering the potential of an oil and gas role.

Yes, it could be natural, scientists say. It’s not altogether impossible the Greeley area could have a natural earthquake — though there hasn’t been any such activity in a good 30 years.

A temblor of that size could happen anywhere in the country, seismologists say.

But recent years have proven throughout drilling fields in Ohio, Oklahoma and Texas that the connection between quakes and oil and gas wastewater disposal wells is rather strong.

That’s where University of Colorado at Boulder geophysics professor Anne Sheehan and her small team of graduate students come in. They spent the last several days deploying seismographs in and around what the U.S. Geological Survey determined was the epicenter of the quake believed to have originated five miles beneath the surface about four miles northeast of Greeley.

They “believe” only because the closest station to record tectonic activity is in Idaho Springs, 70 miles away.

The epicenter of the quake was a bit of an educated guess, as well as the depth. But based on what are called “felt reports,” in which area residents reported what they felt at the time of the earthquake, Sheehan has been able to zero in a little better on the area to get the best readings.

Having seismographs closer in the suspected area — which is near two injection wells — will help scientists get a better fix on the cause.

“I guess we wouldn’t have done this if we didn’t think there would be some small follow-up earthquakes,” Sheehan said. “It’s possible we won’t record anything of interest. One would hope there would not be any more earthquakes. But if there are, we will study them.”

In fact, just two hours after Saturday’s quake, there were three smaller tremors that followed, Sheehan said. One was 2.0 and the other two were 1.4 in magnitude. Those aren’t recorded at the USGS in Golden, which only tracks quakes of 2.5 magnitude and above.

Wastewater disposal wells take in produced water from fracking and drilling operations, a practice that has been going on for several years and which is practiced by a variety of industries.

There are about 150,000 injection wells across the country — 40,000 of which are for oil and gas waste, or “Class II” disposal wells. Weld County has 28 of them.

There were two injection wells in proximity to the epicenter of Saturday’s quake, one dug more than 8,700 feet deep and the other 10,700 feet. One is 20 years old, the other just two years old.

Colorado Oil and Gas Conservation Commission officials earlier this week said they were skeptical that the wells caused the quake because they believe the three historic well-related quake instances recorded in Colorado all shared one common characteristic: the point of injection was the epicenter of the quake.

They said that wasn’t the case in Greeley.

But even that is difficult to measure, given the inexact measuring from 70 miles way, said Justin Rubinstein, a seismologist in Menlo Park, Calif., who has studied the increasing phenomenon of man-induced earthquakes for the last three years.

“As long as there is a pathway for the fluids to transfer, it doesn’t matter where you’re injecting,” Rubinstein said of the misconception on locations. “Faults are an incredible transmitter of fluids and fluid pressures. Just because earthquakes are occurring deeper than where injections are, there’s no reason to say they can’t be related.”

But, he said, there’s little proof of any cause at present, and he wouldn’t rule out a natural quake.

An injection well is dug 10,000 feet below the surface into very porous rock. The rate and volume of the water that is pumped in is governed by state and federal regulations.

Once pumped into the porous rock, the water disperses through that formation, allowing more water to be pumped in.

Sometimes the pressure of the water is such that it causes earthquakes in the existing faults.

The injection wells in question were those of High Sierra Water Services, which manages injections wells throughout Weld County and also recycles produced water for companies.

High Sierra also recycles produced water in an ever-growing amount, shipping it back out to the field for further use in drilling.

“We looked at our charts and we’re operating within the parameters of the well and it’s been operational for quite some time,” said Josh Patterson, operations manager for the company.

Sheehan said by studying whether any subsequent quakes are a result of injection wells potentially being drilled into faults, or the wrong rocks, or were simply overvalued in terms of volume and rate capacities, will help bring about better practices in the field.

“If we find out something useful about whether injection causes earthquakes, it might be something that the industry can use to do a better job of injecting, if that turns out to be a problem,” Sheehan said. “So maybe if they inject at lower volumes or spread it out more, it could be that there are things that we’ll learn that can help inform some sort of best practices.”

More oil and gas coverage here.


Did fracking fluid cause Greeley quake? — 9 News

June 3, 2014
Deep injection well

Deep injection well

From 9News.com (Laurie Cipriano and Brandon Rittiman):

Scientists are investigating whether a rare 3.4 magnitude earthquake near Greeley, Colorado this weekend may have been caused by the disposal of fracking fluid.

The quake was centered in an area of Weld County located near four underground injection sites, in which used fracking fluid is forced deep underground as a method of disposal…

“I think we have a good reason to suspect there may be a link,” said Shemin Ge, a hydrologist with the University of Colorado. “We’re still looking into it.”

Ge says there are several injection wells very close to the epicenter of the earthquake.

“One of them is relatively high volume,” Ge said.

Ge is part of a team of scientists that are responding to the Greeley quake by placing a series of seismometers in the area to get more detailed data.

A team from the University of Colorado at Boulder was sent out to scout locations for the measurement devices on Monday.


Epicenter of Saturday earthquake in Greeley was near oil, gas wastewater injection wells — The Greeley Tribune

June 2, 2014
Deep injection well

Deep injection well

From The Greeley Tribune (Trenton Sperry):

As the annual number of earthquakes in the United States has increased, some have pointed to the oil and gas industry as a cause. But while scientists say there is evidence to suggest wastewater injection wells used by the industry could be linked to the increase, there is little or no evidence to suggest a similar link for fracking operations.

“Hydraulic fracturing almost never causes true earthquakes,” University of Texas seismologist Cliff Frohlich told the Associated Press in September during a gathering at West Virginia University for a National Research Council workshop. “It is the disposal of fluids that is a concern.”

Frohlich was referring to the disposal of wastewater, a byproduct of oil and natural gas production from tight shale formations and coal beds, according to the U.S. Department of the Interior’s website. Wastewater produced from many oil and gas production wells within a field may be injected through a single or just a few disposal wells, according to the website.

The question of whether oil and gas operations cause earthquakes was on the minds of Weld County residents Sunday after a 3.4-magnitude earthquake struck 4.8 miles northeast of Greeley about 9:35 p.m. Saturday night, according to the U.S. Geological Survey. The epicenter was near Weld County roads 66 and 43, which is about 3 miles northeast of Greeley.

The epicenter of the quake was about 1.5 miles from two oil and gas wastewater injection wells, both operated by High Sierra Water Services LLC of Denver, according to data from the Colorado Oil and Gas Conservation Commission. They are the only injection wells in at least a 5-mile radius of the quake’s epicenter.

Injection wells provide one of the most economical ways to dispose of wastewater, according to the USGS website, forcing the wastewater deep below aquifers that provide drinking water.

The USGS website also notes, however, wastewater injection increases the underground pore pressure, which may, in effect, lubricate nearby faults, thereby weakening them. If the pore pressure increases enough, the weakened fault will slip, releasing stored tectonic stress in the form of an earthquake. Even faults that have not moved in millions of years can be made to slip and cause an earthquake if conditions underground are appropriate, according to the USGS website.

USGS scientists have found the increase in seismicity in some locations coincides with a significant increase in the injection of wastewater into disposal wells, mostly in Colorado, Texas, Arkansas, Oklahoma and Ohio, according to the Department of the Interior’s website.

Saturday night’s quake near Greeley provided minor shaking that was felt as far south as Longmont and as far north as Fort Collins, according to the USGS website.

The 10,800-foot injection wells near the epicenter were last inspected by the Weld County Department of Public Health and Environment in October 2013, according to COGCC records. State inspectors last checked the wells in August 2012, about four months before one of the wells was completed as a wastewater injection well, according to COGCC records.

Representatives of High Sierra Water Services and the COGCC did not immediately respond to requests for comment Sunday.

The vast majority of wastewater injection wells do not cause earthquakes. According to the Department of the Interior’s website, of approximately 150,000 Class II injection wells in the United States — including roughly 40,000 wastewater disposal wells for oil and gas operations — only a tiny fraction have induced earthquakes large enough to be of concern to the public.

However, injection wells in Colorado causing earthquakes would not be without precedent. In 1961, a 12,000-foot well was drilled at the Rocky Mountain Arsenal, northeast of Denver, for disposing of waste fluids from Arsenal operations, according to the USGS. Injection began in March 1962, and an unusual series of earthquakes erupted in the area shortly after. The U.S. Army ceased use of the injection well in 1966, and in 1990 a solid link was established between the injection of fluids and the subsequent rash of earthquakes.

But Paul Earle, a seismologist with the USGS, said there’s still plenty to consider to determine if the Greeley earthquake was natural or man-made.

“Just because there are injection wells near there doesn’t necessarily mean they caused the earthquake,” Earle said. “There are a number of things you have to address to make that determination. But it’s certainly something we need to look at and will look at.”

More oil and gas coverage here.


Estimated 6,500 gal of Niobrara oil spilled from train into S Platte — Josh Zaffos

May 11, 2014

CU-Boulder researchers confirm leaks from Front Range oil and gas operations

May 8, 2014
DJ Basin Exploration via the Oil and Gas Journal

DJ Basin Exploration via the Oil and Gas Journal

Here’s the release from the University of Colorado (Gabrielle Petron/Katy Human):

During two days of intensive airborne measurements, oil and gas operations in Colorado’s Front Range leaked nearly three times as much methane, a greenhouse gas, as predicted based on inventory estimates, and seven times as much benzene, a regulated air toxic. Emissions of other chemicals that contribute to summertime ozone pollution were about twice as high as estimates, according to the new paper, accepted for publication in the American Geophysical Union’s Journal of Geophysical Research: Atmospheres.

“These discrepancies are substantial,” said lead author Gabrielle Petron, an atmospheric scientist with the Cooperative Institute for Research in Environmental Sciences, a joint institute of the University of Colorado Boulder and the National Oceanic and Atmospheric Administration. “Emission estimates or ‘inventories’ are the primary tool that policy makers and regulators use to evaluate air quality and climate impacts of various sources, including oil and gas sources. If they’re off, it’s important to know.”

The new paper provides independent confirmation of findings from research performed from 2008-2010, also by Petron and her colleagues, on the magnitude of air pollutant emissions from oil and gas activities in northeastern Colorado. In the earlier study, the team used a mobile laboratory—sophisticated chemical detection instruments packed into a car—and an instrumented NOAA tall tower near Erie, Colorado, to measure atmospheric concentrations of several chemicals downwind of various sources, including oil and gas equipment, landfills and animal feedlots.

Back then, the scientists determined that methane emissions from oil and gas activities in the region were likely about twice as high as estimates from state and federal agencies, and benzene emissions were several times higher. In 2008, northeastern Colorado’s Weld County had about 14,000 operating oil and gas wells, all located in a geological formation called the Denver-Julesburg Basin.

In May 2012, when measurements for the new analysis were collected, there were about 24,000 active oil and gas wells in Weld County. The new work relied on a different technique, too, called mass-balance. In 2012, Petron and her colleagues contracted with a small aircraft to measure the concentrations of methane and other chemicals in the air downwind and upwind of the Denver-Julesburg Basin. On the ground, NOAA wind profilers near Platteville and Greeley tracked around-the-clock wind speed and wind direction.

On two days in May 2012, conditions were ideal for mass-balance work. Petron and her team calculated that 26 metric tons of methane were emitted hourly in a region centered on Weld County. To estimate the fraction from oil and gas activities, the authors subtracted inventory estimates of methane emissions from other sources, including animal feedlots, landfills and wastewater treatment plants. Petron and her team found that during those two days, oil and gas operations in the Denver-Julesburg Basin emitted about 19 metric tons of methane per hour, 75 percent of the total methane emissions. That’s about three times as large as an hourly average estimate for oil and gas operations based on Environmental Protection Agency’s (EPA’s) Greenhouse Gas Reporting Program (itself based on industry-reported emissions).

Petron and her colleagues combined information from the mass-balance technique and detailed chemical analysis of air samples in the laboratory to come up with emissions estimates for volatile organic compounds, a class of chemicals that contributes to ozone pollution; and benzene, an air toxic.

Benzene emissions from oil and gas activities reported in the paper are significantly higher than state estimates: about 380 pounds (173 kilograms) per hour, compared with a state estimate of about 50 pounds (25 kilograms) per hour. Car and truck tailpipes are a known source of the toxic chemical; the new results suggest that oil and gas operations may also be a significant source.

Oil-and-gas-related emissions for a subset of volatile organic compounds (VOCs), which can contribute to ground-level ozone pollution, were about 25 metric tons per hour, compared to the state inventory, which amounts to 13.1 tons. Ozone at high levels can harm people’s lungs and damage crops and other plants; the northern Front Range of Colorado has been out of compliance with federal health-based 8-hour ozone standards since 2007, according to the EPA. Another CIRES- and NOAA-led paper published last year showed that oil and natural gas activities were responsible for about half of the contributions of VOCs to ozone formation in northeastern Colorado.

This summer, dozens of atmospheric scientists from NASA, the National Center for Atmospheric Research, NOAA, CIRES and other will gather in the Front Range, to participate in an intensive study of the region’s atmosphere, said NCAR scientist Gabriele Pfister. With research aircraft, balloon-borne measurements, mobile laboratories and other ground-based equipment, the scientists plan to further characterize the emissions of many possible sources, including motor vehicles, power plants, industrial activities, agriculture, wildfires and transported pollution.

“This summer’s field experiment will provide us the information we need to understand all the key processes that contribute to air pollution in the Front Range,” Pfister said.

More oil and gas coverage here.


Black Hills Exploration & Production is bankrolling $7 million cost to develop #ColoradoRiver diversion near De Beque

April 21, 2014

Colorado River near De Beque

Colorado River near De Beque


From The Grand Junction Daily Sentinel (Gary Harmon):

Ranchers and De Beque residents will gain irrigation water and the energy industry will have access to water for drilling under a project that will pump water out of the bottom of the Colorado River. Energy companies will pay most of the cost of the project that will use an existing intake at the bottom of the river to draw water out and pipe it into existing ditches and a small impoundment that energy companies can draw on for their drilling activities.

“It’s definitely an asset to the community,” said De Beque-
area rancher Tom Latham. “The town will benefit, irrigation and agricultural people will benefit and the oil and gas business will benefit.”

Latham and rancher Dale Albertson represent the Bluestone Water Conservancy District along with members of the board of the Colorado River Water Conservation District in pushing the project, for which work could begin this year.

Called the Kobe Project, the water it draws from the Colorado will be devoted mostly — 75 percent — to agricultural use and 25 percent for industrial use.

Black Hills Exploration & Production is bankrolling almost all the estimated $7 million development cost, some of which it will recoup through lower water costs and from other energy companies that use water from the project, officials said.

The Kobe project will draw 25 cubic feet per second from the Colorado, with 5 cfs set aside for industry and the rest for De Beque and agriculture, said Ray Tenney, an engineer with the River District.

The water won’t necessarily expand agriculture in the area, but it will be a welcome layer of security against continued drought, Latham said.

“The last two years, if it had been in place, it would have been a benefit,” Latham said.

Water availability also will make it easier to develop natural gas in areas that otherwise might have been impossible because of the difficulty of trucking it in, said Mesa County Commissioner Steve Acquafresca, who until recently served as the county’s representative on the project.

“This really is a great local project converting local conditional rights to absolute rights for diverse purposes,” Acquafresca said.

The project also illustrates the need for water to remain in the Colorado as opposed to being diverted east to the Front Range.

“If we want to be more than a donor basin, we need to have a robust economy,” Acquafresca said.

“Kobe is a good example of what we need to be doing here with our water resources.”

More Colorado River Basin coverage here.


Pure Cycle Corporation Announces Second Fiscal Quarter 2014 Financial Results

April 14, 2014

waterfromtap

Here’s the release from Pure Cycle Water:

Pure Cycle Corporation (NASDAQ Capital Market: PCYO) today reported financial results for the six months ended February 28, 2014. Basic and diluted loss per share decreased 38% from a loss of $.08 per share in last year to $.05 per share this year.

“During the second quarter we continued to see our business grow and develop driving long- term shareholder value” commented Mark Harding, President of Pure Cycle Corporation. “We are very excited to have record water sales and deliveries and are continuing to add value to our Company through monetizing our valuable water assets.”[...]

Revenues increased approximately 51% during the our six months ended February 28, 2014 compared to our six months ended February 28, 2013 primarily as a result of increased water sales used for fracking.

More infrastructure coverage here.


“…nobody is digging a new tunnel tomorrow” — Jim Pokrandt #ColoradoRiver #COWaterPlan

April 13, 2014
Colorado River Basin including out of basin demands -- Graphic/USBR

Colorado River Basin including out of basin demands — Graphic/USBR

From the Glenwood Springs Post Independent (John Stroud):

…it’s important to note that “nobody is digging a new tunnel tomorrow,” and organizations like the Glenwood Springs-based River District are active at the table in working to protect Western Colorado interests in the face of growing Front Range water needs, [Jim Pokrandt] said.

“There are a lot of top-10 lists when it comes to rivers and water conservation,” Pokrandt said in reaction to the listing last Wednesday by the nonprofit conservation group American Rivers. “It’s a good way to generate publicity for these various causes.”

American Rivers calls on Colorado Gov. John Hickenlooper to prevent new water diversions and instead prioritize protection of Western Slope rivers and water conservation measures in the Colorado Water Plan, which remains in discussions through a roundtable process that involves stakeholders from across the state.

Already, about 450,000 to 600,000 acre-feet of water per year is diverted from the Colorado basin to the Front Range, Pokrandt noted.

The prospect of more diversions “is definitely being advocated in some quarters from those who say a new project is not a question of if, but when and how soon,” he said.

“We’re saying that’s a big ‘if,’ because there are a lot of big issues around that.”

Pokrandt said any new trans-mountain diversions are “questionable, if it’s even possible.” That’s primarily because of the Colorado River Compact with down-river states that guarantees their share of river water.

“It’s important that we don’t overdevelop the river, and any more transmountain diversions should be the last option out of the box [for Front Range needs],” said. “First and foremost, it behooves all of Colorado to be more efficient in our water use.”[...]

Pokrandt notes that many municipalities across the state, not just the Front Range, are scrambling to find water to take care of projected population growth. That means more water demand on both sides of the Continental Divide.

“But there’s a big question about how much water is really left to develop,” he said. “There’s also an economic benefit to leaving water in the river without developing it, so there’s that issue as well.”[...]

Another Colorado river on the American Rivers endangered list this year is the White River, which was No. 7 due to the threat of oil and gas development and the risk to fish and wildlife habitat, clean water and recreation opportunities.

The White River flows from the northern reaches of the Flat Tops through Rio Blanco County and into the Green River in northeastern Utah.

“Major decisions this year will determine whether we can safeguard the White River’s unique wild values for future generations,” said Matt Rice of American Rivers in their Wednesday news release.

From the Vail Daily (Melanie Wong):

The conservation group American Rivers releases the annual list, and rivers that are threatened include sections of the Colorado that run through Eagle County, including headwater rivers, which include the Eagle River.

According to the group, the river is threatened as many Front Range cities look for future water sources to meet growing municipal and industrial needs. Some of those communities are eyeing various parts of the Colorado for diversion.

Advocates hope the list garners some national awareness and spurs lawmakers to prevent new water diversions and prioritize river protection and water conservation measures in the state water plan.

“The America’s Most Endangered Rivers report is a call to action to save rivers that are at a critical tipping point,” said Ken Neubecker, of American Rivers. “We cannot afford more outdated, expensive and harmful water development schemes that drain and divert rivers and streams across the Upper Colorado Basin. If we want these rivers to continue to support fish, wildlife, agriculture and a multi-billion dollar tourism industry, we must ensure the rivers have enough water.”[...]

For decades, Front Range growth has been fed by Western Slope rivers. Around a half million acres of water is already being diverted east from the Upper Colorado and growing cities need more. The problem with diversions, said Neubecker, is that the water leaves the Western Slope forever, citing a proposed project to tap into Summit County’s Blue Mountain Reservoir and divert water from the Blue River.

“Grand and Summit counties are justifiably worried about a Green Mountain pumpback, and so should Eagle County, because that project isn’t possible without a Wolcott reservoir,” he said. “With water diverted to the Front Range, we never see it again. It has serious impacts on us as far as drought and growth. It’s a finite resource.”

Historically, there have been agreements that have benefited both the Western and Eastern slopes, and river advocates said they want to see more such projects. The Colorado Cooperative Agreement, announced in 2011, involved the cooperation of many Eagle County entities. The Eagle River Memorandum of Understanding, signed in 1998, was also a major victory for mountain communities, significantly capping the amount of water that could be taken at the Homestake Reservoir and keeping some water in Eagle County.

Another settlement with Denver Water in 2007 was a big win for the local water community, said Diane Johnson, of Eagle River Water and Sanitation. “Denver Water gave up a huge amount of water rights, pretty much everything leading into Gore Creek, and as for a Wolcott Reservoir, it could only be developed with local entities in control,” she said. “Things are done more collaboratively now. It’s not the 1960s and ’70s anymore, where the Front Range developed the rivers without thought of how it affected local communities.”[...]

A new Colorado State University report commissioned by the Eagle River Watershed Council studied the state of the Eagle River.

“It’s clearly showing that the biggest threat to this portion of the Upper Colorado is reduced flows. It’s impacting wildlife for sure, most notably the fish,” said the council’s executive director Holly Loff.

With less water, the average river temperature is rising, and many cold-water fish have either been pushed out or killed as a result. Less water also means less riparian (riverside) habitat, an ecosystem that supports 250 species of animals. Of course, less water also affects river recreation and means there’s less water to drink.

More Colorado River Basin coverage here.


Environmental groups are suing to prevent oil and gas exploration operations north of Del Norte #RioGrande

April 5, 2014
San Luis Valley Groundwater

San Luis Valley Groundwater

From The Pueblo Chieftain (Robert Boczkiewicz):

Environmental groups in the San Luis Valley say they are suing to protect an aquifer they call “the lifeblood” of the valley. The lawsuit alleges that proposed drilling for oil and gas on federal land just south of Del Norte endangers 7,000 water wells in the valley. The lawsuit asks a judge to overturn the federal Bureau of Land Management’s approval of the drilling by a Texas oil company.

The lawsuit against BLM was filed March 5 in U.S. District Court by the San Luis Valley Ecosystem Council and Conejos County Clean Water Inc.

The Conejos Formation aquifer “holds the lifeblood of the San Luis Valley ecosystem, culture and economy, as well as the headwaters of the Rio Grande (River),” the 37-page lawsuit states. “Any underground and surface water contamination due to oil and gas exploration in the project area would likely enter the Conejos Formation aquifer.”

“BLM violated the law by issuing (the oil) lease . . . without considering the unique and controversial effects” of the drilling, the lawsuit alleges. “A growing number of people . . . are concerned that the federal government has once again relied on a rushed, incomplete process,” approving the proposed drilling “without taking a hard look,” as law requires, at its impacts, the lawsuit asserts.

BLM said that it is reviewing the lawsuit.

The environmental groups contend that BLM’s environmental assessment of the drilling project incorrectly concluded there would be no significant impact.

More Rio Grande River Basin coverage here.


CU-Boulder offers well users guide for testing water in areas of oil and gas development

April 3, 2014

chemistryglassware

Here’s the release from the University of Colorado at Boulder:

A free, downloadable guide for individuals who want to collect baseline data on their well water quality and monitor their groundwater quantity over time was released this week by the University of Colorado Boulder’s Colorado Water and Energy Research Center (CWERC).

The “how to” guide, “Monitoring Water Quality in Areas of Oil and Natural Gas Development: A Guide for Water Well Users,” is available in PDF format at http://cwerc.colorado.edu. It seeks to provide well owners with helpful, independent, scientifically sound and politically neutral information about how energy extraction or other activities might affect their groundwater.

The guide spells out the process of establishing a baseline for groundwater conditions, including how best to monitor that baseline and develop a long-term record.

“Baseline data is important because, in its purest form, it documents groundwater quality and quantity before energy extraction begins,” said CWERC Co-founder and Director Mark Williams, who is also a fellow at the Institute of Arctic and Alpine Research and a CU-Boulder professor of geography.

“Once a baseline has been established, groundwater chemistry can be monitored for changes over time,” Williams said. “The most accurate baselines are collected before energy extraction begins, but if drilling has already begun, well owners can still test their water to establish a belated baseline and monitor it for changes. That might not be scientifically ideal, but it’s a lot better than doing no monitoring at all.”

CWERC’s guidance builds on the state’s public health recommendations that well owners annually test water for nitrates and bacteria. The guide encourages well water users to collect more than one pre-drilling baseline sample, if possible.

CWERC recommends collecting both spring and fall samples within a single year because water chemistry can vary during wet and dry seasons. Well owners should measure the depth from the ground surface to the water in their wells in the fall, during the dry season, so that they can keep track of any changes.

“Colorado’s oil and gas regulators have established some of the most comprehensive groundwater monitoring regulations in the country, but those regulations do not require oil and gas operators to sample every water well in an oil or gas field,” Williams said. “So we wanted to develop a meaningful tool for people who want to test their water themselves or those who need information to help negotiate water testing arrangements as part of surface use agreements with drillers in their area.

“Ultimately, it is the responsibility of the well owner to know their own well and understand their water. This guide will help Coloradans do just that.”

The guide specifically outlines what well water users may want to test for and provides a list of properly certified laboratories that offer water-testing services. In addition, the guide assists individuals in interpreting the scientific data, chemical references and compound levels that are outlined in the laboratory results they will receive and any industry tests or reports related to drilling in their area.

CWERC studies the connections between water and energy resources and the trade-offs that may be involved in their use. It seeks to engage the general public and policymakers, serving as a neutral broker of scientifically based information on even the most contentious “energy-water nexus” debates.

CWERC was co-founded in 2011 by Williams and Joseph Ryan, a CU-Boulder professor of civil, environmental and architectural engineering, with funding from the CU-Boulder Office for University Outreach.

To download a free copy of the guide, visit http://cwerc.colorado.edu. For questions about obtaining the guide or to order a printed version, visit the website or call 303-492-4561.


Colorado legislative committee OKs oil and gas health impact study — Denver Post #COleg

April 2, 2014

COGCC issues ‘Lessons Learned’ report for operations affected by September #COflood

March 18, 2014
Production fluids leak into surface water September 2013 -- Photo/The Denver Post

Production fluids leak into surface water September 2013 — Photo/The Denver Post

From the Denver Business Journal (Cathy Proctor):

…while images of tipped storage tanks and flooded well sites were part of the national media coverage of the storm and the aftermath, the amount of petroleum products spilled into the rushing waters was small compared to the raw sewage and chemicals from flooded wastewater treatment plants, homes, stores and other facilities, state officials said in the weeks following the flood.

Now, the COGCC, which oversees the state’s multi-billion dollar oil and gas industry, issued its staff report to focus on “Lessons Learned” from the flood. The report doesn’t suggest putting new laws in place, but does propose the COGCC consider adopting “best management” practices for oil and gas equipment located near Colorado’s streams and rivers.
Along with encouraging remote wells, the COGCC recommends boosting the construction requirements for wells located near streams and rivers and developing an emergency manual to help the the COGCC staff better respond in the early days of a future emergency.

From the Northern Colorado Business Report (Jerd Smith):

In the wake of last September’s floods, a new report from state oil and gas regulators recommends that oil companies maintain precise locations and inventories of wells and production equipment near waterways, that all new wells near waterways contain remote shut-in equipment, and that no open pits be allowed within a designated distance from the high-water mark of any given streams.

In the report, released Monday, staff of the Colorado Oil and Gas Conservation Commission said they would not recommend any new state laws to address flood damage in oil and gas fields, but that they would suggest changes to regulations governing how production and gathering facilities are sited and constructed.

The commission noted that more than 5,900 oil and gas wells are within 500 feet of a Colorado stream.

The Colorado Oil and Gas Association, however, said that the industry responded well to the emergency and that no further regulatory action was needed.

“The floods were a difficult and trying event for everyone, and we are proud at our ability to engage meaningfully in the response and recovery of our Colorado communities,” Tisha Schuller, president and chief executive of the association, said in a statement Monday afternoon. “The flood report reiterated facts supporting that Colorado’s oil and gas industry was extraordinarily well prepared, responded in real time, and is committed to Colorado’s recovery.

From the Associated Press via The Colorado Springs Gazette:

The suggestions from the commission’s staff include requiring that storage tanks be anchored with cables so they’re less likely to tip and spill and requiring all wells within a certain distance of waterways to be equipped with devices that allow operators to shut them down remotely.

The staff recommendations didn’t say what that distance should be.

The commission is expected to discuss the proposed rules at a meeting this spring.

The report described the flood damage to storage tanks and production equipment as “substantial and expensive” but gave no dollar amount. It also said oil and gas production has still not returned to pre-flood levels but again gave no figures.

More oil and gas coverage here and here.


COGCC: A Staff Report to the Commissioners “Lessons Learned” in the Front Range #COFlood of September 2013

March 17, 2014
Flooded well site September 2013 -- Denver Post

Flooded well site September 2013 — Denver Post

Here’s the release from the Colorado Oil and Gas Conservation Commission (Todd Hartman):

The Colorado Oil and Gas Conservation Commission today released a comprehensive public report describing the lessons learned from the September 2013 flood. This 44-page report will support a Commission discussion in coming months as it decides whether to modify its regulations and policies that apply to Colorado’s oil and gas industry.

The flood along the Front Range and eastern plains of Colorado in September 2013 inundated many oil and gas facilities. Production equipment and oil and gas locations were damaged by rushing flood waters and debris. Colorado experienced spills of oil, condensate and produced water.

The report, Lessons Learned in the Front Range Flood of September 2013, describes the Commission’s investigation and conclusions following its flood response so far. The Commission has completed more than 3,400 individual inspections of oil and gas facilities affected by flood waters. It has discussed flood observations and lessons learned with the oil and gas industry, first responders, federal, state and local government agencies, conservation groups, and many other interested parties. On February 6, 2014, the Commission held a workshop in Denver to support a wide-ranging public discussion of these matters.

The report describes recommendations for changes to Colorado’s oil and gas program, and it also collects the flood response information gathered by the Commission. Recommendations include improved construction and protection of oil and gas facilities sited near Colorado’s streams. The report also includes recommendations for how the Commission can work better in a future emergency, emphasizing the importance of the Commission’s collection and dissemination of reliable oil and gas information in the very early days of an emergency.

The COGCC will schedule a hearing in the near future to discuss the report and take additional public comment.

The Colorado Oil and Gas Conservation Commission oversees the responsible development of oil and gas in Colorado and regulates the industry to protect public health, safety, welfare and the environment. The Commission oversees wells, tank batteries, and other oil and gas equipment located, in some cases, near streams throughout the state.

Click here to read the report. Here’s an excerpt:

The Colorado Oil and Gas Conservation Commission (“COGCC” or the “Commission”) estimates that more than 5,900 oil and gas wells lie within 500 feet of a Colorado waterway that is substantial enough to be named. When these streams flood, nearby oil and gas facilities are at risk of damage, spills, environmental injury and lost production.

COGCC continues its work in the state’s recovery from the September 2013 flood along the Front Range of Colorado. COGCC has completed more than 3400 firsthand inspections of the oil and gas facilities affected by the flood. It has discussed flood observations and recommendations in detail with industry, other federal and state agencies, first responders and local governments, conservation groups and many others. The agency participates fully in Governor Hickenlooper’s broad flood response efforts started when the extraordinary rains began to fall.

COGCC has learned from these experiences, and this report is built upon that information. Section III collects and describes flood observations by COGCC staff and others. These observations range from highlighting significantly varying levels of protection offered by different anchoring systems to the importance of releasing to the public accurate and comprehensive COGCC information in the early days of the flood. Section IV assembles suggestions to improve Colorado’s oil and gas program – suggestions gathered from many sources by COGCC since the flood. These suggestions also vary widely, from those who believe COGCC regulations worked well to protect against the flood and should be left as they are today to those who believe that additional construction and other regulations are called for statewide as a result of the flood experience.

From The Denver Post (Mark Jaffe):

The the state and the oil and gas industry need to do a better job of managing the 20,850 Colorado wells within 500 feet of rivers and streams, according to a report released Monday.

The Colorado Oil and Gas Conservation Commission report on lessons learned from the 2013 floods sought to identify the potential risks and suggest steps to be taken.

“The flood that struck the Front Range of Colorado in September 2013 was a major disaster and emergency,” the report said. “Damage to the oil and gas industry was significant.”

The oil and gas commission conducted more than 3,400 flood-related inspections and evaluations, and evaluated each of the 1,614 wells in the flood zone.

The inspections determined that wellheads generally fared well, but that tank batteries and other production equipment were toppled or dislodged by flood waters.

Flowing water, for example, eroded earthen foundations below tanks and equipment.

“Many oil and gas facilities located near flooded streams were damaged in the September 2013 flood,” the report said. “Oil, condensate and produced water spilled into the environment.”

About 48,250 gallons of oil and condensate spilled and more than 43,478 gallons of produced water also spilled, the report said.

Among the recommendations are that tanks and equipment be located as far from waterways as possible.

Secondary containment should be constructed with steel berms, which held up better in the flood, and lined with synthetic liner material bolted to the top of the steel berm.

Tanks should be constructed on compacted fill to reduce sub-grade failure and they should be should be ground-anchored, with engineered anchors and cabling.

The report also suggests regulatory changes including requiring each driller to have an inventory of all wells and production equipment in waterway areas.

Wells within the high-water mark of a waterway should be equipped with remote shut-in devices. These were very effective in closing wells during the flood, the report said.

More oil and gas coverage here and here.


‘Our water right requires us to replace the water in the Box Elder. That’s what they (Select Energy) should do’ — Mark Harding

March 16, 2014
Map of the South Platte River alluvial aquifer subregions -- Colorado Water Conservation Board via the Colorado Water Institute

Map of the South Platte River alluvial aquifer subregions — Colorado Water Conservation Board via the Colorado Water Institute

From The Denver Post (Mark Jaffe):

The meandering Box Elder Creek has become a battlefield as farmers and ranchers are facing off against a plan to drill wells along its banks to provide water for fracking and other oil-field operations. While the creeks wends its way north from Elbert County to the South Platte River in Weld County — Arapahoe County is ground zero for the fight.

Boxelder Properties LLC is proposing sinking four wells to draw 500-acre feet of water annually for the fracking and other oil-drilling operations. That is enough water to supply 200 average Denver homes for a year.

Ranchers and farmers along the Box Elder say the plan will dry out wells and pools used by cattle, as well as kill vegetation along the creek’s banks east of Aurora.

“These boys from Texas think they can just ride in. Well, the people on Box Elder are going to meet ‘em at the hill,” said Jerry Francis, who grazes about 30 head of cattle on the creek.

The dispute underscores the problem of trying to balance oil and gas development in Colorado with other economic activities.

“We want oil and gas development, but we have to do it so we don’t jeopardize our agricultural community,” Arapahoe County Commissioner Rod Bockenfeld said.

The county commissioners have sent a letter opposing the project to the Colorado Division of Water Resources, which must decide on the proposal.

The proposal has become so controversial that Houston-based Conoco-Phillips, the main company drilling in the area, announced that it wouldn’t use water from the wells. Houston-based Select Energy Services, the Conoco contractor that initiated the plan, has also abandoned the idea, according to company spokeswoman Brooke Jones.

Still, the permit application to drill the wells is pending with the water division, also called the Office of the State Engineer.

“The project isn’t dependent on Conoco; there are other oil service companies,” said Walraven Ketellapper, head of Boulder-based Stillwater Resources and Investment.

Stillwater, a water broker and agent, is handling the permit for Boxelder Creek Properties.

The state engineer has received 16 letters — from farmers, public officials, water districts — objecting to the plan and raising concerns about its impact on water supplies.

“We are going to do the engineering analysis, the groundwater modeling to show the wells can withdraw water without adverse impacts,” Ketellapper said. “That is our burden of proof.”

Just 15 miles east of Denver, suburban sprawl gives way to silos, barns and broad fields seemingly running all the way to the snow-capped Rockies. It is through this landscape that Box Elder Creek snakes its way to the South Platte River, 2 feet deep in some places, sometimes as wide as 12 feet, while in other spots it is just a dry, sandy bottom most of the year.

“We are a dry county,” said Bockenfeld, the Arapahoe County commissioner. “Many farms dry farm; there just isn’t a lot of water.”

Only in the early spring with the first snowmelt does the creek run full, but all year long a subterranean stream feeds ponds and pools, residents say.

“This pool is here all summer long,” Francis said as he stood in a field next to the creek. “The water and this buffalo grass gets cattle fat as a fritter.”

A retired John Deere worker who raises cattle to keep busy, the 67-year-old Francis said what he is most concerned about is the future.

“They take away the water, what’s left for my kids and grandkids?” he said.

A neighboring farmer, Bill Coyle, 60, has more immediate concerns. Coyle estimates he spent about $300,000 in an eight-year battle with the state engineer to get a water right for four irrigation wells on his 1,000-acre farm. Standing at one of his center-pivot wells, Coyle can see the spot where one of the proposed wells would be. It is beyond the state-required 600-foot setback — but still within sight.

The application for the four water wells says that they are drawing water from the creek and won’t impact local wells. Coyle doesn’t believe it.

“They are proposing pumping at 1,000 gallons a minute,” Coyle said. “My well is 42 feet deep. It will have an impact on the well, and it will be immediate.”

The decision to issue a temporary permit to drill and pump the four wells to produce 500-acre feet a year or 163 million gallons rests with the state engineer. The award of a long-term water right would be determined in Colorado Water Court — a process that can take as much as five years. The process is governed by Colorado water law — a byzantine set of rules organizing the right to draw water based on a priority system.

The key to being allowed to pump the water is a so-called augmentation plan to replace it so that the older or “senior” water rights are not impaired. This is an expensive process.

Select Energy offered four landowners — none of them local residents — $10,000 to drill a water well on their land and 1 cent for every barrel of water — about 42 gallons — pumped, according to one of the contracts.

They also purchased shares in the Weldon Valley Ditch to replace the pumped water. The application estimates that 10.4 shares — worth about $950,000 — would be needed to replace the 500 acre-feet drawn from the water wells.

Water, however, is vital to the oil and gas industry, with demand growing 35 percent to 18,700 acre-feet from 2010 to 2015, according to state estimates. The water, mixed with sand and chemicals, is pumped into wells under pressure to “hydrofracture” or frack shale rock and release oil and gas. About 4 million gallons is pumped into a single horizontal well.

“Water has always responded to the market in Colorado,” said Ken Carlson, director of the Center for Energy and Water Sustainability at Colorado State University. “First it was urban areas buying the water rights of farms. Now it is oil and gas.”

Select Energy is now getting its water from Denver-based Pure Cycle Corp., which has deep wells on the former Lowry Bombing and Gunnery Range, in Arapahoe County. Pure Cycle is opposing the plan because it also has a water right on the Box Elder that would be hurt, said Mark Harding, Pure Cycle’s president. The problem is that the plan calls for pumping along the Box Elder but returning the water about 50 miles to the north near Wiggins.

“Our water right requires us to replace the water in the Box Elder. That’s what they should do,” Harding said.

The state engineer will rule in the next few months on the temporary permit, which could enable pumping this year and last for as long as five years.

“This application is unusual in that the Box Elder isn’t a continuously flowing stream where the groundwater is continuously replenished,” Deputy State Engineer Kevin Rein said.

“We take the concerns seriously, and we’ve asked the applicant to respond to them,” Rein said. “We’ll have to see what they say.”

More oil and gas coverage here and here.


Hydraulic Fracturing & Water Stress: Water Demand by the Numbers — CERES

March 2, 2014

The hydraulic fracturing water cycle via Western Resource Advocates

The hydraulic fracturing water cycle via Western Resource Advocates


Click here to register to download the report.

Thanks to the Boulder Weekly (Haley Gray) for the link. Here’s an excerpt:

Water is the lifeblood of Colorado’s Weld and Garfield counties, and lately it’s been in short supply. Both of these counties face extremely high stress in terms of water scarcity, and both have seen an intense concentration of the water-intensive hydraulic fracturing (fracking) process.
It’s a bad combination, according to a recent report issued by Ceres, a nonprofit devoted to promoting corporate responsibility and sustainability leadership.

The report, released Wednesday, Feb. 4, is titled, “Hydraulic Fracturing & Water Stress: Demand by the Numbers,” and it projects that the clash between water shortages and fracking is only going to get worse, given that a significant increase in shale development via fracking in these areas is likely. In the Denver- Julesburg (DJ) Basin alone, which covers parts of Boulder and Weld counties, Ceres predicts a redoubling of fracking activity by 2015…

CERES FOUND THAT 100 PERCENT OF THE NATURAL GAS AND OIL WELLS IN COLORADO ARE LOCATED IN AREAS FACING EXTREME WATER STRESS, 89 PERCENT OF WHICH ARE LOCATED IN WELD AND GARFIELD COUNTIES…

Ceres’ report constitutes the first systematic effort to investigate water usage by natural gas companies. One of the purposes of the report is to identify water sourcing risks to oil and gas companies, thereby generating information previously unavailable to the public. Famiglietti lauds the “deep dives,” or meticulously detailed case studies, conducted by Ceres for the report.

It is, however, by no means a comprehensive study of the risks associated with fracking. Concentrated usage of water in extremely dry regions was just one of three primary concerns Famiglietti points out regarding the report. Famiglietti listed earthquakes and the removal of water from the natural water cycle as additional issues demanding further investigation. Both of these concerns arise from the practice of using injection wells to dispose of wastewater from the fracking process by injecting it into deep formations.

The report also issues recommendations and identifies some of the most progressive current practices in the industry. It specifically mentions, among other companies, Anadarko, the single largest natural gas producer in the DJ Basin in terms of water use, as a “pocket of success.” Anadarko earned the mention for its practice of leasing wastewater from local municipalities. Even so, Anadarko is one of the most at-risk companies in terms of drilling in water-scarce areas, according to Freyman.

“In a general year, cities have more water than they can use,” says Brian Werner, public information officer of the Northern Colorado Water Conservancy District (NCWCD).

Leasing excess water to oil and gas companies to use for fracking allows municipalities to pad meager budgets. The years 2009, 2010 and 2011, for example, were wet years, according to Werner. In 2012 the Front Range was hit with a drought. Werner expects 2014 to be a particularly wet year.

According to Werner, it is not unheard of to see a town both lease excess water and impose water rationing simultaneously, since water rationing is used to keep water conservation on the public’s minds. “In most years [how much, if any, excess water leased] depends on comfort levels and a number of other factors,” Werner says.

No towns in Colorado currently lease water directly to companies for fracking purposes, according to Werner. Generally, a water leasing company such as A&W Water Service Inc. secures water from municipalities or local farmers, who might own the rights to more water than they need, and then resells the water to a third party for fracking purposes.

The increased demand for water by “deep-pocketed” oil and gas companies is not beneficial to all farmers, though. According to the Ceres report, it has driven up the price of water in Colorado, making it difficult for struggling farmers to stay afloat.

More oil and gas coverage here and here.


Governor joins environmental community, energy industry to highlight new rules for oil and gas activities

February 26, 2014
Wattenberg Oil and Gas Field via Free Range Longmont

Wattenberg Oil and Gas Field via Free Range Longmont

Here’s the release from Governor Hickenlooper’s office:

Gov. John Hickenlooper was joined today by representatives from the environmental community, the energy industry and state agencies to discuss the Colorado Air Quality Control Commission’s recent approval of comprehensive changes to rules governing oil and gas activities in the state.

The new rules include the nation’s first-ever regulations designed to detect and reduce methane emissions.

“All Coloradans deserve a healthy economy and a healthy environment, and we’ve taken yet another critical move to help make sure that Colorado will continue to have both. The new rules approved by Colorado’s Air Quality Control Commission, after taking input from varied and often conflicting interests, will ensure Colorado has the cleanest and safest oil and gas industry in the country and help preserve jobs,” Hickenlooper said. “We want to thank the environmental community, the energy industry and our state agencies for working together so hard to take this significant step forward.

“We’re fortunate to live in this beautiful, vibrant state. We enjoy it every day, and we don’t for one second take it for granted. It’s collaborative efforts like this, the result of everyone working together, that will help ensure Colorado’s tomorrow is even brighter than today.”

Representatives from the environmental community, the energy industry and state agencies at the press conference today included: Fred Krupp from the Environmental Defense Fund; Pete Maysmith from Conservation Colorado; Ted Brown from Noble Energy; Craig Walters from Anadarko; Angie Binder from Encana; Dr. Larry Wolk from the Colorado Department of Public Health and Environment (CDPHE); and Gerald Nelson, an economist from Grand Junction.

The new Oil and Gas Emission Rules were adopted by the Colorado Air Quality Control Commission on Sunday, Feb. 23, 2014. The regulations resulted from the governor’s calls for further action to minimize potential negative air quality impacts associated with oil and gas development.

The rules continue Colorado’s leadership in ensuring responsible development under the most stringent and protective standards in the country. A coalition of environmental and industry interests worked with the administration on the rules. Highlights of the rules include:

  • The most comprehensive leak detection and repair program for oil and gas facilities in the country.
  • Regulation of a range of hydrocarbon emissions that can contribute to harmful ozone formation as well as climate change. The rules include first-in-the-nation provisions to reduce methane emissions.
  • Implementation of the rules will reduce more than 92,000 tons per year of volatile organic compound emissions. VOC emissions contribute to ground level ozone that has adverse impacts upon public health and environment, including increased asthma and other respiratory ailments.
  • Implementation of the rules also will reduce of more than 60,000 tons per year of methane emissions. As a natural gas, methane provides a clean and affordable domestic energy source. But when it leaks or vents to the atmosphere, it is a potent greenhouse gas.
  • Expanded control and inspection requirements for storage, including a first-in-the-nation standard to ensure emissions from tanks are captured and routed to the required control devices.
  • Expands ozone non-attainment area requirements for auto-igniters and low bleed pneumatics to the rest of the state
  • Require no-bleed (zero emission) pneumatics where electricity is available (in lieu of using gas to actuate pneumatic)
  • Require gas stream at well production facilities either be connected to a pipeline or routed to a control device from the date of first production.
  • Require more stringent control requirements for glycol dehydrators.
  • Require use of best management practices to minimize the need for – and emissions from – well maintenance.
  • Many operators will use infrared (IR) cameras, which allow people to see emissions that otherwise would be invisible to the naked eye. Colorado obtained IR cameras for CDPHE and the Department of Natural Resources inspectors last year. They are an effective tool in identifying leaking equipment and reducing pollution.
  • Comprehensive recordkeeping and reporting requirements to help ensure transparent and accurate information.
  • Adoption of federal oil and gas standards that complement the state-specific rules.
  • The unofficial draft of the rules now will be sent to the Colorado Secretary of State’s Office for publication, prior to the rules becoming effective in the spring. Click on the highlighted “Regulations 3, 6 & 7” to view the complete regulations.

    From the Denver Business Journal (Cathy Proctor):

    Gov. John Hickenlooper knows that Colorado’s new air quality rules for oil and gas operations, lauded as the strictest in the nation, won’t please everyone…

    At a press conference Tuesday at the state Capitol, Hickenlooper said Colorado’s new air quality rules were the result of the collaborative efforts of some of the state’s biggest oil and gas companies, a national environmental group and state regulators. But he said he knows that others want more.

    “There’s a group that wants to ban hydrocarbons, to ban hydraulic fracturing, and today’s not going to satisfy people who are against all hydrocarbons and want to have all renewable fuels,” Hickenlooper said. “Natural gas will be a transition fuel, and our efforts today are focused on how we do that as cleanly as possible.”[...]

    State officials have pegged compliance costs at about $42.5 million a year, or less than $500 per ton of pollution eliminated.

    Executives at some of Colorado’s biggest oil and gas companies have said the state’s estimate is in line with their estimates and a cost they consider acceptable.

    Here’s a release from Earth Justice (Michael Freeman):

    Today, Governor Hickenlooper held a press conference to celebrate the Colorado’s Air Quality Control Commission’s adoption of groundbreaking revisions to rules that govern the oil and gas industry. The new rules include measures to help protect Coloradans from air pollution caused by the industry’s fracking-fueled boom and make Colorado the first state in the nation to regulate emissions of methane—a powerful greenhouse gas—from the oil and gas industry.
    The Commission’s resounding 8–1 vote came Sunday after a contentious five-day hearing in which powerful industry trade associations opposed the Governor’s proposed revisions. In the end, the Commission stood with Coloradans from across the state who spoke out in favor of accepting and strengthening the Governor’s proposal.

    Earthjustice Rocky Mountain Office staff attorneys Michael Freeman and Robin Cooley represented a coalition of conservation groups—the Sierra Club, Natural Resources Defense Council, WildEarth Guardians and Earthworks Oil and Gas Accountability Project—in the just completed rulemaking process.

    Following the Governor’s press conference, Michael Freeman stated: “Today, we join many other Coloradans in celebrating the new rules. While these rules won’t be enough to bring Colorado into compliance with federal air quality standards, they’re a good first step. We look forward to finishing the job and ensuring that all Coloradans can breathe clean air.”

    Robin Cooley added: “Getting a handle on methane emissions from the fracking industry will be necessary for the United States to address climate change. These rules make Colorado a leader in that effort.”

    From the Denver Business Journal (Cathy Proctor):

    Colorado’s new air quality regulations for oil and gas operations are the strictest in the nation, says Fred Krupp, the president of the Environmental Defense Fund, which participated in meetings that led to the proposed rules…

    “There is more work to be done of course — whether it is addressing carbon pollution from power plants or making sure we are using energy as efficiently as possible. But let’s take a moment today to say, “job well done.” If we can replicate the cooperation and collaboration represented here today – we can provide a cleaner, safer environment for our children and grandchildren. — Pete Maysmith, executive director Conservation Colorado.

    More oil and gas coverage here and here.


    Snowpack news: Reclamation’s current forecast for Fry-Ark deliveries = 63,000 acre-feet #ColoradoRiver

    February 23, 2014

    From The Pueblo Chieftain (Chris Woodka):

    The Bureau of Reclamation has estimated a banner year for Fryingpan-Arkansas flows — with a disclaimer.

    “The forecast is based on average conditions for the rest of the spring,” said Roy Vaughan, Reclamation’s manager for the Fry-Ark Project. “We’ve seen it continue to snow and rain, and we’ve seen everything stop in March.”

    Vaughan spoke at Wednesday’s meeting of the Lower Arkansas Valley Water Conservancy District.

    Based on snowpack of 140 percent of median in the Fry-Ark collection area on the other side of the Continental Divide on Feb. 1, Reclamation predicts 63,800 acre-feet of water could be imported this year. If it holds, that would be about 20 percent higher than normal. But that number could be influenced by when and how quickly the snow melts in May and June. It also depends on whether snows continue during March and April, when the mountains typically get the largest accumulation of snow.

    While the Arkansas River basin is reporting storage levels of 64 percent of average, Fry-Ark reservoirs are 85-105 percent of average for this time of year, Vaughan said. Turquoise Reservoir, near Leadville, is at 105 percent, while Twin Lakes and Pueblo are about 85 percent of average.

    Reclamation wants to move about 30,000 acre-feet of water out of Turquoise Lake, but can’t because it is making repairs on the turbines at the Mount Elbert hydroelectric plant. Most of the water moved between Turquoise and Twin Lakes goes through a large tunnel that feeds the Mount Elbert forebay. Repairs should be completed in early March, Vaughan said.

    The Southeastern Colorado Water Conservancy District will allocate water from the Fry-Ark Project in May. About 53 percent goes to cities and 47 percent to farms under the district’s allocation principles.

    From the USDA:

    Limited water supplies are predicted in many areas west of the Continental Divide, according to this year’s second forecast by the National Water and Climate Center of USDA’s Natural Resources Conservation Service (NRCS).

    Right now, snow measuring stations in California, Nevada and Oregon that currently don’t have any snow, and a full recovery isn’t likely, the center’s staff said.

    USDA is partnering with states, including those in the West, to help mitigate the severe effects of drought on agriculture.

    USDA announced last week that $15 million was available for conservation assistance to farmers and ranchers in affected areas in California, Texas, Oklahoma, Nebraska, Colorado and New Mexico. As part of the announcement, $5 million was also made available to California communities through the Emergency Watershed Protection Program. Earlier this month, USDA made another $20 million available to farmers and ranchers in California. Agriculture Secretary Vilsack joined President Obama in California on February 14th to announce those and other drought relief measures.

    Parts of eastern California are now in a state of emergency because of drought. This area is suffering one of the lowest snow years on record. Meanwhile, in Oregon, mountain snowpack is far below normal.

    “The chances of making up this deficit are so small that at this point we’re just hoping for a mediocre snowpack,” said NRCS Hydrologist Melissa Webb for Oregon. “We’d need months of record-breaking storms to return to normal. There’s a strong chance we’ll have water supply shortages across most of Oregon this summer.”

    Most Oregonians don’t have access to water from other states and depend on local sources for water supply.

    Across the Continental Divide, Montana, Wyoming and Colorado are mostly near normal. The one exception is New Mexico, which is extremely dry.

    Although NRCS’ streamflow forecasts do not predict drought, they provide information about future water supply in states where snowmelt accounts for the majority of seasonal runoff.

    NRCS has conducted snow surveys and issued regular water supply forecasts since 1935 and operates SNOTEL, a high-elevation automated system that collects snowpack and related climatic data in the western United States and Alaska. These data help farmers, ranchers, water managers, hydroelectric companies, communities and recreational users make informed, science-based decisions about future water availability.

    View February’s Snow Survey Water Supply Forecasts map or view information by state.


    Hydraulic fracturing: ‘It really is just water and sands that goes down a hole’ — William Fronczak

    February 22, 2014

    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates


    From The Fort Morgan Times (Rachel Alexander):

    He said the fluid used in the hydraulic fracking, as it is called, process is 99 percent water and sand, with only a small percentage being added chemicals.

    “It really is just water and sands that goes down a hole,” Fronczak said.

    He said vertical fracking uses between 375,000 and 410,000 gallons of water while the more frequently used horizontal fracking uses between 2 and 4 million gallons.

    “There’s a lot of logistics handling water,” he said. “We don’t want to shut down a frack due to water.”

    Fronczak used a variety of charts to show the association members how the actual fracking is only a small portion of what is done with the industry’s water. Initially, water has to be sourced, then transported or transferred to the fracking site. After it is brought out of the fracking hole, the water has to be contained and treated.

    “The challenge is meeting that high rate of demand in a short period of time,” Fronczak said.

    He discussed the limitations of trucking water to fracking sites and the use of piping to transfer the water over distances. This also allows the industry to decrease its carbon footprint.

    “Where there’s a lot of activity, there’s not a lot water,” he said, adding that industry members have work to find solutions to the water issue. “Closest water isn’t always the best. From a quality standpoint as well as from a logistical standpoint.”

    More oil and gas coverage here and here.


    COGCC flood response lessons learned forum recap

    February 7, 2014
    Flooded well site September 2013 -- Denver Post

    Flooded well site September 2013 — Denver Post

    From the Fort Collins Coloradoan (Ryan Maye Handy):

    Colorado oil and gas regulators set a precedent on Thursday by hosting a public forum on lessons learned from oil spills caused by the September 2013 floods, said Colorado Oil and Gas Conservation Commission Director Matt Lepore.

    But in recapping its response to the spills — which poured about 43,000 gallons of oil into the South Platte River basin — few new updates came out of the meeting, held in the Wells Fargo building in downtown Denver. Representatives from COGCC, a state agency that regulates oil and gas, and industry advocacy group the Colorado Oil and Gas Association, spoke about response to the spills that alarmed Front Range residents for weeks last fall. The groups intend to present a series of recommendations to the state government as a result of their review, Lepore said.

    But the main purpose of the meeting — time for public discussion — was largely a bust. Lepore had set aside an hour for discussion with an audience of more than 70 people, but after four or five comments and questions, the audience was silent.

    “I am pleased with the turnout,” Lepore said after the meeting adjourned almost an hour early. “Honestly, I hoped for much more dialogue.”[...]

    When it comes to flood aftermath, Laura Belanger, an environmental engineer with Western Resource Advocates, is still hopeful that COGCC’s list of best management practices — now only suggestions — become hard-and-fast rules. While larger oil and gas operators might go above and beyond what the list recommends, smaller operations may not, she said.

    More oil and gas coverage here and here.


    The COGCC explores expanded policy for horizontal drilling ‘communication’ with existing wells

    February 6, 2014
    Potential vertical and horizontal drilling conflict via The Grand Junction Daily Sentinel (Robert Garcia)

    Potential vertical and horizontal drilling conflict via The Grand Junction Daily Sentinel (Robert Garcia)

    From The Grand Junction Daily Sentinel (Dennis Webb):

    The Colorado Oil and Gas Conservation Commission plans to expand statewide a policy aimed at preventing horizontal wells from causing leaks involving existing wells, due to a leak southwest of De Beque where such a possible link is being investigated.

    The Bureau of Land Management also is looking at what it can do to try to help head off such problems.

    The agencies’ actions follow the Dec. 14 discovery of natural gas and fluids bubbling up around a Maralex Resources well on Jaw Ridge, which is BLM-managed land about seven miles from De Beque. The leak’s cause continues to be investigated, and one possibility the COGCC is considering is that it resulted from hydraulic fracturing of a Black Hills Exploration & Production well that was drilled from a surface site about a mile away, but made a 90-degree turn underground and passed within about 400 feet of the Maralex well.

    The Maralex well was drilled in 1981 but was shut in shortly after its drilling. It stopped leaking Jan. 17, as work continued on permanently plugging it, an effort completed a week later. Fluids initially escaped from the well pad after the leak’s start. Maralex then opened the well and directed the flow into a pit for removal by truck. That flow fluctuated widely but averaged about 6,300 gallons a day during the month before it ceased. Authorities have found no indication of contamination of surface water or groundwater. Testing continues to try to determine exactly how far the fluids spread beyond the pad within what the BLM considers to be a known maximum spill parameter.

    ‘COMMUNICATION’ CONCERN

    The COGCC currently has a policy aimed at preventing what it calls the potential for “communication” between horizontal wells and existing wells in 11 counties in eastern Colorado’s Denver-Julesburg Basin. That area is seeing a boom in horizontal drilling aimed at producing oil and other liquids, in an area with numerous existing vertical wells that in some cases may not have been constructed to withstand modern-day, high-pressure fracture operations nearby.

    “It is apparent that that policy needs to be pushed out statewide. It needs to be pushed out statewide very quickly,” COGCC director Matt Lepore told the commission at its last meeting.

    The policy requires the COGCC engineer to evaluate all wells within 1,500 feet of a proposed horizontal wellbore to determine whether the existing wells have adequate cement sealing around them to isolate the geological formation to be fractured, as well as all groundwater zones. Also to be evaluated is whether an existing well’s wellhead and master valve are rated to 5,000 pounds per square inch of pressure, or alternatively that there is adequate mechanical isolation down the well.

    If concerns exist regarding an existing well, the company proposing the horizontal well must take measures that can range from doing remedial cement work in the existing well to isolate all formations, to properly plugging it, to replugging it if needed or proposing alternative mitigation. An existing well’s owner cannot refuse to let mitigation work occur.

    The COGCC initially implemented the policy for horizontal wells coming within 300 feet of existing wells. It eventually expanded the distance after pressure readings and other data collected at existing wells during fracking of new ones indicated a need to do so.

    Lepore told the commission one concern companies have is the lack of data that would justify the 1,500-foot-distance standard in the case of wells outside the DJ Basin. He also noted that there are currently few plans to drill horizontal wells elsewhere in the state. Companies have been drilling a small number of such wells for exploratory purposes in the Piceance Basin.

    LEAK THEORY INVESTIGATED

    The Maralex well was drilled into the Dakota sandstone formation, while the Black Hills well targeted the Niobrara shale, part of the shallower Mancos formation. The COGCC says the Maralex well wasn’t cemented to isolate the Niobrara zone because that zone wasn’t considered a producing formation when the well was drilled. It’s looking at whether gas liberated from fracking the Black Hills well reached the Maralex well, pushing gas and water to the surface.

    Bruce Baizel, energy program director with the Earthworks conservation group, has said another concern in horizontal drilling is that it may occur around older existing wells that may have corroded pipes or cement sealing that has weakened over time and can’t stand up to fracking pressures.

    Maralex plugged its well in stages after the discovery of the leak. When it finished plugging the Dakota sandstone formation, the leak slowed but continued. The leak stopped once plugging was completed at the top of the Mancos formation. But that in itself hasn’t been enough to convince officials that the Black Hills well fracking caused or contributed to the problem.

    Test results of fluid that flowed back from the Black Hills well are still being awaited. Samples of flowback fluid from another Black Hills horizontal well farther from the Maralex well proved to differ significantly from the fluid that came up the Maralex well.

    THE BLM’S ROLE

    Agency spokesman Steven Hall called the Maralex situation a rare one for the BLM, which he believes has seen few instances where fracking has occurred close to shut-in wells on lands it administers in Colorado. While noting that the leak’s cause hasn’t been determined, he said the BLM wants to do what it can to prevent problems between horizontal and existing wells. He said the BLM is reviewing how it manages horizontal drilling and fracking on federal land in the state. The agency has no rules or policies addressing potential communication between horizontal and existing wells. But Hall said it has a lot of leeway during the process of reviewing drilling permit applications to impose conditions to try to avoid such situations. In addition, it is working to deal with the situation of wells that are shut in for a long time, to make sure they are permanently plugged, put into production, or tested to ensure their integrity.

    “We’re going to try to be very aggressive in addressing those,” Hall said.

    The agency previously has said that of 110 wells Maralex owns that involve federal lands or minerals in western Colorado, 86 are shut-in — in nearly half those cases for more than 20 years. It has met with Maralex about coming up with a strategy for addressing its shut-in wells.

    More oil and gas coverage here and here.


    New Hydraulic Fracturing Report Finds Texas and Colorado Face Biggest Water Sourcing Risks

    February 6, 2014
    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates

    Here’s the release from CERES via CSRWire:

    As hydraulic fracturing is increasingly used for oil and gas extraction across much of the United States and Western Canada, a new Ceres report issued today shows that much of this activity is happening in arid, water stressed regions, creating significant long-term water sourcing risks for companies operating in these regions as well as their investors.

    The report provides first-ever data on oil & gas companies’ water use and exposure to the most water stressed regions, including those in Texas, Colorado and California. It includes recommendations for companies to improve their water management and reduce their overall exposure to water sourcing risks.

    “Hydraulic fracturing is increasing competitive pressures for water in some of the country’s most water-stressed and drought-ridden regions,” said Ceres President Mindy Lubber, in announcing Hydraulic Fracturing and Water Stress: Water Demand by the Numbers. “Barring stiffer water-use regulations and improved on-the-ground practices, the industry’s water needs in many regions are on a collision course with other water users, especially agriculture and municipal water use. Investors and banks providing capital for hydraulic fracturing should be recognizing these water sourcing risks and pressing oil and gas companies on their strategies for dealing with them.”

    The report is based on water use data from 39,294 oil and gas wells reported to FracFocus.org from January 2011 through May 2013 and water stress indicator maps developed by the World Resources Institute (WRI). It shows that nearly half of the wells were in regions with high or extremely high water stress. (Extreme high water stress regions, as defined by WRI, are areas where 80 percent of available surface and groundwater are already allocated to municipal, industrial and agricultural users.) Read the rest of this entry »


    Noble Energy looks to the Denver Basin Aquifer System for non-tributary groundwater for operations

    January 29, 2014
    Denver Basin Aquifers confining unit sands and springs via the USGS

    Denver Basin Aquifers confining unit sands and springs via the USGS

    From The Greeley Tribune (Eric Brown):

    Many water needs in the region have been met by buying supplies from farmers and ranchers, but a Noble Energy manager said Tuesday the oil and gas industry could and should stop being a part of that problem, and explained what his company is doing to get water. The large energy developer is looking to use deep groundwater wells — drawing “non-tributary water” — to meets its needs down the road, said Ken Knox, senior adviser and water resources manager for Noble, during his presentation at the Colorado Farm Show in Greeley.

    Farmers and others who pump groundwater typically draw water that’s less than 100 feet below the Earth’s surface — water that’s considered to be “tributary,” because it’s connected to the watershed on the surface and over time flows underground into nearby rivers and streams, where it’s used by farmers, cities and others. Wanting to avoid water that’s needed by other users, Knox said Noble is looking to have in place about a handful of deep, non-tributary groundwater wells that draw from about 800 to 1,600 feet below the Earth’s surface. Digging wells that deep is considered too expensive for farmers, Knox and others said Tuesday, and the quality of water at that depth is typically unusable for municipal or agricultural uses.

    One of Noble’s deep groundwater wells is already in place, and the company is currently going through water court to get another four operating in the region down the road, Knox said. Along with digging deeper for water, Knox explained that Noble across the board is “strategically looking” to develop water supplies that don’t put them in competition with agriculture or cities.

    Oil and gas development, according to the Colorado Division of Natural Resources, only used about 0.11 percent of the state’s water in 2012 — very little compared to agriculture, which uses about 85 percent of the state’s supplies. But in places like Weld County — where about 80 percent of the state’s oil and gas production is taking place, and where about 25 percent of the state’s agriculture production is going on, and where the population has doubled since 1990 and is expected to continue growing — finding ways for an economy-boosting energy industry to not interfere with the water demands of farmers, ranchers and cities is critical.

    The growing water demands of the region is coupled with the fact that the cheapest way to build water supplies is to purchase them from farmers and ranchers who are leaving the land and willing to sell. Those factors leave the South Platte Basin, which covers most of northeast Colorado, potentially having as many as 267,000 acres of irrigated farmland dry up by 2050, according to the Statewide Water Supply Initiative Study, released by the state in 2010.

    With that in mind, the Colorado Farm Show offered its “Water Resources Panel: Agriculture, Urban and Oil and Development Interactions.”

    Joining Knox on the panel were John Stulp, who is special policy adviser on water to Gov. John Hickenlooper; Dave Nettles, division engineer with the Water Resources Division office in Greeley; and Jim Hall, resources manager for the city of Greeley. The panel was moderated by Reagan Waskom, director of the Colorado Water Institute at Colorado State University.

    Knox also spoke Tuesday of Noble’s and other energy companies’ efforts to recycle the water they use in drilling for oil and gas — a hydraulic fracturing process, or “fracking,” that involves blasting water, sand and chemicals into rock formations, about 7,000 feet into the ground, to free oil and natural gas. The average horizontal well uses about 2.8 million gallons of water. Some water initially flows out of the well, but another percentage flows back over time. Knox stressed it is cheaper for companies to dispose of that returned water and buy fresh water for drilling purposes than it is to build facilities that treat used water. But, seeing the need to make the most of water supplies in the region, Noble is willing to invest in water-recycling facilities and other water-efficiency endeavors.

    Hall noted that the city of Greeley, which leases water to both ag users and oil and gas users, has seen a decrease in the amount of water it leases for energy development. With improved technology and improved drilling techniques, also decreasing is the amount of land oil and gas development is using, and the number of water trucks on rural roads.

    Knox said oil and gas companies — once requiring about 8 acres for one well site — can now put four to eight wells on just 3 acres, meaning the impact on farm and ranch land is less than it once was. By becoming more water efficient, he said Noble has decreased its water truck loads by 1.65 million annually, and reduced its carbon dioxide emissions by 264,000 tons.

    More oil and gas coverage here and here.


    High Sierra Water Services opens new oil and gas production fluids recycling facility

    January 7, 2014
    Wattenburg Field

    Wattenburg Field

    From The Greeley Tribune (Sharon Dunn):

    The sun shines, the temperature is still unaware of a looming arctic freeze and Josh Patterson chats happily in his new truck as it lumbers down a maze of Weld County roads headed northeast from High Sierra Water Services offices in west Greeley. Heading toward his company’s latest accomplishment, his truck turns, moves ahead and turns a few more times before we’re in open country of blue skies and golden plains. He tears open his breakfast burrito, and manages to swallow a few bites as he answers questions about C7, High Sierra Water Services’ latest commercial water recycling facility about 10 miles southwest of Briggsdale.

    This one is unique in that it is the first water recycling facility in Colorado that will transport water via pipeline. As of early December, the planned four miles of pipeline remain to be set to connect it to Noble Energy’s central processing facility — a centralized area that will become one of the global oil and gas company’s hubs. The facility will take in oil, natural gas, and water piped in from the wellhead, separate it all on one 40-acre space, recycle the water, and pipe out the oil and natural gas to the markets. As a unit, it will eliminate hundreds of truck miles spent transporting from one place to another. Noble plans to build a few more in the field to centralize its operations.

    “This is the big brother to C6,” says Patterson, director of operations for High Sierra Water, of the nine-acre water recycling and injection facility called C7.

    High Sierra is one of a few companies in the Wattenberg Field that recycles used production water from wells, a process that Patterson designed, and which he continues to upgrade. High Sierra’s C6 facility, unveiled publicly last year west of Platteville, is High Sierra’s other recycling facility in the Wattenberg where produced water can be recycled or injected into underground wells. The company also has a recycling facility in Wyoming.

    Recycling water has been on the rise in recent months as companies strive to become more environmentally friendly — Noble Energy, especially, with it is Wells Ranch central processing facility, and Anadarko Petroleum, are both big customers of High Sierra.

    We stop outside the sprawling Wells Ranch Central Processing facility to view the route of the four miles of pipeline to bring water in and out of the facility for Noble, which will be the chief customer at C7.

    “C7 was built in concert with C6, but it sat idle for a year,” Patterson explains. “The demand essentially wasn’t there. It took time to prove up the water quality to frac-fluid compatibility. A lot of water isn’t compatible with gel-frac chemistry. It requires a certain water quality. So we’re taking treated water and making sure it doesn’t ruin a $7 million frac job.”

    The trench for the last bit of pipeline is already dug in some spots, and workers work to fuse the pipes together along the pipeline’s route as we travel those four miles north. The pipeline typically sits about 4 feet underground, depending on the frost line.

    “There are lot of rolling hills and we want to lay the pipe out as flat as possible,” Patterson said. “We don’t do it by gravity. We have a medium pressure pipeline set at 120 psi.”

    At Weld County roads 74 and 69, we stop finally at High Sierra, where a backhoe is digging the trench that will feed into the recycling plant. To the eastern side of the site, workers are on a rig, drilling a directional well to dispose of production water that doesn’t get recycled. It is the facility’s second injection well.

    On the outside, it looks as if it’s one massive storage facility, with several tank batteries, and an open concrete pad where the company plans to place more for storage of both produced and recycled water.

    The company started operations with a 2,000-barrel sale on Thanksgiving Day. It has the capacity to process 15,000 barrels a day.

    “Now, we can store 6,000 barrels for incoming water, and 3,000 barrels for finished water,” Patterson said. Noble will have the capacity to store 80,000 barrels (enough for about one frack job) at the central processing facility, all piped in from High Sierra.

    “It’ll get to capacity and based on my projections, it will require an expansion,” Patterson said of C7’s capabilities. “With the drilling plans and projected water use (in the field), by 2018, we’ll need another facility or an expansion to that facility.”

    To date, C8, a new injection facility with planned recycling capabilities, has been built in Grover, and officials are mulling plans for future expansion.

    We walk inside to don hard hats and step into the belly of the beast. Actually, the big blue beast, an injection pump, sits in the middle pumping production water downhole into the plant’s first injection well, arguably the loudest piece of equipment in the metal building with concrete flooring. Across the room, a door leads to the recycling facility, where tanks and equipment are placed strategically and carefully in tight quarters, leaving just enough room for a body to roam through and maybe clean and check tanks. Each massive tank inside has a function in the four-step process that takes four hours from production wastewater to recycled product. The process starts by removing the suspended solids from the water, such as cuttings from the wells. Step two is dissolving other solids; step three is polishing, and step four is filtration. It’s a process that Patterson has honed in his time at High Sierra, and in which he takes enormous pride. With each step, or system design, he tries to improve on the process.

    The facility has eight employees who work on the disposal side and nine for the recycling side; the process is 24/7, and the facility is open 15 hours a day.

    After about 30 minutes, and Patterson disappearing to discuss a site production issue with staff, we’re back in the truck en route to Greeley.

    His burrito barely touched, Patterson swigs from a bottle of water nabbed for the trip, and he talks about the future needs of recycled water.

    While not every company in the field is going with recycled water, Patterson said more inquires are coming in all the time. It’s a rather expensive process, and volume dictates the cost. With a long-term contract with Noble, dealing in millions of gallons of water, the costs make it on par with trucking costs. Some companies have experimented with recycling water at the wellhead — Patterson himself has even tried it. But the amount of power needed to recycle water, makes the paltry amount coming out of wells cost-prohibitive, Patterson said.

    “It’s just not economic. Just the power required to run a treatment system brings the costs way up,” Patterson said. “A lot of companies have put together treatment technology. But there’s just not enough water. If you’re on a seven-well pad, with a seven-well pad next door, it could be economic. But it goes back to the fixed costs (which don’t fluctuate).”

    Recycling water is not the only answer in this growing field, which produces roughly 85,000 barrels of water a day, but it is growing. Between C6 and C7, High Sierra has the capacity to recycle 25,000 barrels a day. The rest must be put into injection wells. Barring additional storage capacity for a growing need for recycled water, it must go somewhere.

    “We’re still a drop in the bucket compared to the water that could be utilized,” Patterson said.

    More oil and gas coverage here.


    Officials still don’t have conclusive evidence between hydraulic fracturing and the leaking well near De Beque

    December 31, 2013
    Debeque phacelia via the Center for Native Ecosystems

    Debeque phacelia via the Center for Native Ecosystems

    From The Grand Junction Daily Sentinel (Dennis Webb):

    Authorities are still awaiting test results that could help determine the cause of a leak at a 32-year-old, nonproducing oil and gas well seven miles southwest of De Beque.

    The Maralex Resources well is now producing about 100 barrels, or 4,200 gallons, of fluids a day into a containment pit, about a week and a half after the discovery of gas and fluids leaking from and around the well. Part of the leak investigation is focused on whether recent hydraulic fracturing of a nearby Black Hills Exploration & Production well could have caused the leak.

    As of Tuesday, results weren’t back from water and soil tests that could confirm or rule out the presence at the leak site of frack fluids from the recent operation.

    Todd Hartman, spokesman for the state Department of Natural Resources, said test results are expected the first week of January.

    Black Hills drilled a well about a mile away that by design turned horizontally underground. The company believes it came within about 400 feet of the Maralex well, which is on Bureau of Land Management land. The Black Hills well is targeting the Niobrara shale formation, whereas the Maralex well was drilled deeper to reach the Dakota sandstone formation.

    BLM spokesman Chris Joyner said it’s theoretically possible the two wells are as close as 260 feet. He said that in the spring, Black Hills ran measuring tools down the Maralex well, and it headed in a direction that would place the new well about 400 feet from it. But for some reason Black Hills didn’t measure the entire length of the Maralex well, so if it happened to make a 90-degree turn beneath the measured length, the wells could be as close as 260 feet, Joyner said. That’s unlikely for what is considered to be a vertical rather than horizontal well, and the 400-foot distance is probably correct, but the BLM has to consider worst-case scenarios, he said.

    An unknown amount leaked from the well before it was discovered and Maralex began diverting it into the pit, from which fluids are being removed by trucks. The BLM says no surface water impacts have occurred. The nearest surface water is the Colorado River, which is anywhere from four to six miles away as measured by the winding canyons below the spill site.

    Crews have built a berm and shored up the downhill side of the pad, and installed a trench to protect a nearby draw, particularly from any possible leaked fluids that may now be frozen but could flow when thawed. Soil samples also have been taken in the draw, and Joyner said it’s likely Maralex also will be ordered to install groundwater monitoring wells in the area.

    Following the leak’s discovery, Maralex opened the well and installed a diversion pipe from it, and leaking around the well ceased. Flows from the well itself also have been intermittent. Joyner said some of the flows may simply consist of substances coming up from the well’s target production zone because it’s no longer shut in. That shut-in occurred in 1981, the same year the well was drilled, but it remained capable of production, the BLM says. The well showed no structural problems during a BLM inspection this summer.

    The BLM has ordered Maralex to permanently plug and abandon the well and reclaim the site. Joyner said plugging could occur as soon as the end of this week, but first the problem with the well must be identified and fixed.

    “Right now we’re very actively engaged in trying to figure out what the problem is with the well,” he said.

    “… It’s a very controlled situation now. We just don’t have the well killed, so to speak, and fixed.”

    He said the BLM has been happy with the efforts by Maralex and the industry in general, including contractors and companies that have lent equipment. Quick early actions helped contain the leaking fluids, he said.

    Black Hills also has been involved on the scene.

    “It’s certainly not looked at as just a Maralex problem. It’s looked at as a problem that we need to fix as a group,” he said, referring to the industry, BLM and Colorado Oil and Gas Conservation Commission.

    Hartman said the COGCC has had personnel on the scene daily. He said the agency has had discussions with Maralex about a remediation plan that will be carried out after the well is plugged.

    Joyner said site access has been a challenge due to alternately frozen and muddy roads.

    An employee for Ignacio-based Maralex who declined to give his name said Tuesday that the company was waiting on test results before it would speak to issues surrounding the leak.

    More oil and gas coverage here and here.


    The COGA is disputing the recent University of Missouri study of endocrine disruptors in Garfield County waters

    December 21, 2013
    Directional drilling and hydraulic fracturing graphic via Al Granberg

    Directional drilling and hydraulic fracturing graphic via Al Granberg

    From the Northern Colorado Business Report (Steve Lynn):

    Doug Flanders, COGA’s director of policy and external affairs, issued a statement this week calling the study’s link between drilling and chemicals known as endocrine disruptors “short sighted.”

    “The Colorado River is a drainage basin for almost half of western Colorado,” reads the statement. “To correlate the (endocrine disrupting chemical) levels in the river to oil and gas drilling is extreme cherry-picking from a number of sources that are known to contain (endocrine disrupting chemicals).”

    The study from researchers with the University of Missouri at Columbia and the U.S. Geological Survey who collected water samples from the Colorado River and water wells near oil and gas development in Garfield County found chemical activity linked to cell destruction. The study is published in the journal Endocrinology…

    She noted that though the study found higher levels of the endocrine disruptors in waters near fracking sites, more research is required to determine whether fracking is causing more of the chemicals to appear in the water supply. Nagel is conducting additional testing on the Western Slope as part of a new, more comprehensive study, she said.

    The researchers collected control water samples in Boone County, Missouri, an area with no natural-gas drilling, and found lower levels of endocrine disrupting chemical activity.

    The Colorado Oil & Gas Association argues that the region in Missouri has a different geology, topography and environment.

    “Additionally, authors of the study are unsure of the exact source of the (endocrine disrupting chemicals) and even acknowledge that the chemicals could come from a host of other sources besides fracking,” the industry group’s statement reads.

    Naturally occurring and synthetic chemicals could contribute to the activity observed in water samples collected by scientists, according to the study. Researchers noted, however, that they collected samples in areas without recent agricultural activity and wastewater contamination that could have led to additional endocrine disrupting chemical activity.

    The researchers also contend that water samples taken in the more urban Boone County lend further support for a link between fracking and chemical activity in water.

    “The more urban samples were found to exhibit the lowest levels of hormonal activity in the current study,” the study states.

    Meanwhile, the State of Colorado has toughened regulations for oil and gas spills. Here’s the release from the COGCC (Todd Hartman):

    The nine-member Colorado Oil and Gas Conservation Commission today unanimously approved new spill reporting regulations that significantly tighten the volume thresholds and timeframe for operators to report spills of oil as well as exploration and production waste.

    Under the new rules, any spill of five barrels or more must be reported within 24 hours. In addition, any spill of one barrel or more that occurs outside secondary containment, such as metal or earthen berms, must also be reported within 24 hours. The previous threshold for such reporting in both instances was 20 barrels, and spills between five and 20 barrels could be reported within 10 days.

    The rules continue to require reporting within 24 hours of any spill that impacts or threatens to impact waters of the state, any occupied structure, livestock, a public byway or surface water supply area.

    The rules approved Tuesday build upon House Bill 13-1278, which was approved by lawmakers earlier this year and took effect August 7.

    “These are important improvements to our spill reporting requirements and improve our ability to track and respond to spills and releases across Colorado,” said COGCC director Matt Lepore.

    “These regulations will improve the public’s confidence in our ability to protect public health, safety and our environment.”

    More oil and gas coverage here and here.


    The BLM and COGCC continue to monitor leaking gas well near De Beque

    December 19, 2013
    Colorado River near De Beque

    Colorado River near De Beque

    From The Grand Junction Daily Sentinel (Dennis Webb):

    A recently hydraulically fractured horizontal oil and gas well was drilled within about 400 feet underground, and possibly within 260 feet, of a nonproducing well discovered to be leaking Saturday. The inactive, 32-year-old vertical well showed no leaking or structural problems during a routine Bureau of Land Management inspection July 9.

    Authorities are continuing to investigate the cause of the newly discovered leak at the Maralex Resources well on BLM-managed land on Jaw Ridge in Mesa County about seven miles southwest of De Beque. One possibility is that hydraulic fracturing of a horizontal well owned by another company, Black Hills Exploration & Production, may be responsible.

    The BLM and Colorado Oil and Gas Conservation Commission are investigating the incident with the assistance of both companies. BLM spokesman Chris Joyner said the COGCC took soil and water samples Tuesday.

    “We’re being told within a week we’ll know what the analysis shows,” he said.

    “If it’s fracking fluids, then obviously that will give us an indication that it was related to the other site that was recently fracked,” Joyner said.

    Joyner said the BLM is being told a citizen, possibly a hunter, discovered the leak Saturday. The leak was bubbling up from around the well, but Maralex opened the well to divert the leak to a holding pit, which caused the water and gas to come up only through the well and suggested the action relieved the pressure, he said.

    Todd Hartman, spokesman for the Colorado Department of Natural Resources, said late Tuesday afternoon that it appeared the flow of fluids and gas had stopped altogether. An unknown amount of fluids initially migrated off the pad but didn’t reach surface water, Joyner said.

    Maralex “acted quickly Saturday and got it going into a containment pit. That helped a lot,” he said.

    A containment berm around the pad was built Tuesday.

    Fracked recently

    Joyner said Maralex removed 160 barrels of fluids from the pit, which had been dry during this summer’s inspection. He said precipitation likely accounts for part of that amount.

    The leaking well is 7,300 feet deep and about a mile southeast of a 6,000-foot-deep Black Hills well that Joyner was told was fracked within the last 10 days. He said the leak appears fairly fresh, or the volume would likely be much larger.

    Maralex couldn’t be reached for comment. Black Hills spokesman Wes Ashton said his company’s horizontal well went underground within about 400 feet of the Maralex well. Joyner said that’s possible, but it could have come within 260 feet. Joyner didn’t know how close to the well it was allowed to be, and Ashton didn’t know how far the fractures from the Black Hills well were expected to extend.

    Ashton said Black Hills has drilled four wells, all horizontal, in the De Beque area in the last three years.

    “We’ve got a pretty good track record and history in the local area. … We’re just doing anything we can at this point to assist what’s going on and as far as the review.”

    Horizontal drilling, which involves drilling down and then out 90 degrees sometimes for long distances, is becoming increasingly popular, in Colorado’s case mostly in northeastern Colorado where companies are pursuing oil development.

    Path to surface

    Bruce Baizel, energy program director with the Earthworks conservation group, said such drilling poses a challenge as the wells “wiggle and waggle” between pre-existing vertical wells, at closer and closer distances with less margin for error. Especially if the wells are older, perhaps with corroded pipe or with cement sealing around them that has weakened over time, there’s the potential for leaks when high-pressure fracking occurs, he said.

    “You put pressure on it and boom, there goes your crumbling cement and you’ve got a path right to the surface,” he said.

    Ashton said Black Hills does collision-avoidance studies, including resurveying of existing wells and planning of a well path to avoid existing well bores.

    “This is an issue of concern to the industry and operators in the industry are presently working with regulatory agencies to address the issue and we’re actively participating in that process,” he said.

    More oil and gas coverage here and here.


    De Beque: COGCC is probing flow of water and gas from non-producing well near DeBeque, new activity in area the cause?

    December 17, 2013
    Colorado River near De Beque

    Colorado River near De Beque

    From The Grand Junction Daily Sentinel (Dennis Webb):

    State oil and gas personnel are trying to determine whether hydraulic fracturing of a horizontal well outside De Beque is responsible for water and gas flowing from a non-producing vertical well a half-mile away. Todd Hartman, spokesman for the state Department of Natural Resources, said fluid at the surface has been captured in a trench and contained in a pit on site.

    “No surface waters have been impacted and the nearest known water well is roughly six miles away. (Colorado Oil and Gas Conservation Commission) personnel will be working to determine any potential impact on groundwater,” he said.

    “COGCC is investigating the possibility the hydraulic stimulation of the horizontal wellbore communicated with the vertical wellbore.”

    He said Black Hills Exploration & Production was doing the horizontal drilling and fracturing operation on Bureau of Land Management property. Its well reached about 6,000 feet deep and the fracking was done within the last few weeks. The vertical well, owned by Maralex Resources Inc., is 7,300 feet and was drilled in 1981. It hasn’t produced for many years, Hartman said.

    He said COGCC field inspection personnel were on the site Monday and more, including environmental specialists and engineers, would be arriving Tuesday to determine what happened and assess and remediate any impacts. The agency is collecting water samples as part of its investigation. Representatives with both companies also are involved in the investigation.

    Horizontal drilling involves drilling down and then out horizontally to follow geological formations. The practice has taken off as companies have combined it with hydraulic fracturing to successfully produce significant quantities of oil and gas.

    The practice also has led to some concerns about the possibility of impacting pre-existing vertical wells that may not be designed to withstand the kind of pressure associated with the fracking, which involves pumping fluids into a formation to create cracks and foster oil and gas flow. In October, Encana said its fracking of a horizontal well in New Mexico may have been responsible for releases of fluid from a nearby vertical well, according to a report by KRQE in Albuquerque.

    Meanwhile, a group of 9-15-year-olds have delivered a petition asking the state to stop issuing permits for oil and gas exploration and production. Here’s a report from Cathy Proctor writing for the Denver Business Journal. Here’s an excerpt:

    A group of eight 9-15-year-olds from Boulder, Lafayette and Englewood have asked state regulators to stop issuing permits for drilling oil and gas wells, or for fracking them, “until it can be done without adversely impacting human health,” safety, or Colorado’s climate, water, earth and wildlife.

    The petition was filed Nov. 15 by the Boulder-based Earth Guardians with the Department of Natural Resources and the Colorado Oil and Gas Conservation Commission (COGCC), the state agency that regulates the state’s multibillion-dollar oil and gas industry. It’s available here, on the COGCC website.

    “The COGCC will consider initiating this rulemaking at the January 27-28, 2014 Hearings,” the agency said in a note posted on its website.

    COGCC Executive Director Matt Lepore said the petition was posted to the COGCC website Monday, after the commissioners decided to hear the children’s request for a new rule. The petition was filed under a state law that allows individuals to ask the state to make rules, change them or repeal them.

    Finally, here’s a look at finding common ground in the oil and gas debate from Allen Best writing for the Mountain Town News. Here’s an excerpt:

    In a lecture on Dec. 10 sponsored by the Center of the American West, oil-and-gas attorney Howard Boigon called this “the latest reel in a long-running movie.”

    This latest reel can be distilled into one word: fracking. Short for hydraulic fracturing, it’s a technical process, just one component in the broader activity of drilling. But the word is now fraught with additional meanings, depending upon who is using it.

    The rift has become so deep that, like gang colors, sides can be differentiated by how they spell the word. To drillers, the abbreviated word is spelled “frac.” To most everybody else, including those more neutral about the practice, it is “frack.”

    If we can’t agree how to spell the word, there’s even deeper division as to what it refers. Until a few years ago, it was clinically called a “downhole completion procedure,” one done only after a drilling rig had been laid down. So far, as Boigon noted, there are no confirmed cases of fracking fluids sullying potable drinking water — this after a million fracks during the last 60 years.

    In the language of some, thought, fracking involves much more—and is much more sinister.

    “In its most pointed form,” he said, “it is used to describe in a pejorative way the injection of known carcinogens underground which can percolate into groundwater, with the resulting production of large quantities of toxic fluids which are often spilled on the surface before having to be disposed of in underground wells that cause earthquakes.”[...]

    Boigon was at his best in dissecting the oil and gas industry. It is, he said, “an industry that in many ways is bolted to the past…A stubborn reliance on property rights as the sacred foundation of the industry underlies attitudes and actions. Oil and gas is found where it is found, therefore we must go and get it wherever it is, and our right to do is inalienable and must be protected…. Independence and self-reliance, the willingness to take risk, an aversion to interference by government or neighbor—these are the attributes of the oilman…Oilmen are competitive and notoriously self-confident, sometimes to the point of arrogance and dismissiveness, believing they know best how to do their business and that there is nothing they can’t do. “

    His acknowledgement of the technological prowess of drillers also bears citation:

    “The fact is that the oil and gas industry is one of the most innovative on the planet, and our civilization has benefited greatly from this. Think about the basic technology of the business, drilling a hole several inches in diameter miles below the surface to targets imperfectly identified, through virtually impenetrable rock under conditions of high heat and pressure, under surface conditions ranging from extreme cold to thousands of feet of water to dense jungle to challenging topography to fragile environments to urban surroundings, in political and regulatory contexts all over the world ranging from highly developed to primitive. The imperatives of meeting these challenges have generated extraordinary creativity and innovation, from deepwater platforms to multi-well pads to horizontal drilling to multi-stage hydraulic fracturing to pitless drilling, to water recycling, to fracking without fresh water, to name just a few. Technology is constantly evolving. You give them a challenge, and they figure out a way to meet it.”[...]

    I have made the argument that it wouldn’t hurt to have a few more drilling rigs in our midst, to retain an element of reality in our lives. Those drilling rigs are our rigs, after all. Our giant houses, 12 mph pickups, weekend flights to Las Vegas – we’re all part of this story. It’s not them vs. us. It’s us.

    Does this drilling give us the illusion of sustainability? The late Randy Udall probed this in a presentation at the Colorado Renewable Energy Society in March. We’ve chained ourselves to the drilling rig, he said, and thrown away the key.

    More oil and gas coverage here and here.


    High levels of hormone-disrupting chemicals have been found in water samples near fracking sites in Colorado

    December 16, 2013
    Williams Energy hydraulic fracturing operation near Rulison via The Denver Post

    Williams Energy hydraulic fracturing operation near Rulison via The Denver Post

    Here’s the release from the University of Missouri:

    University of Missouri researchers have found greater hormone-disrupting properties in water located near hydraulic fracturing drilling sites than in areas without drilling. The researchers also found that 11 chemicals commonly used in the controversial “fracking” method of drilling for oil and natural gas are endocrine disruptors.

    Endocrine disruptors interfere with the body’s endocrine system, which controls numerous body functions with hormones such as the female hormone estrogen and the male hormone androgen. Exposure to endocrine-disrupting chemicals, such as those studied in the MU research, has been linked by other research to cancer, birth defects and infertility.

    “More than 700 chemicals are used in the fracking process, and many of them disturb hormone function,” said Susan Nagel, PhD, associate professor of obstetrics, gynecology and women’s health at the MU School of Medicine. “With fracking on the rise, populations may face greater health risks from increased endocrine-disrupting chemical exposure.”

    The study involved two parts. The research team performed laboratory tests of 12 suspected or known endocrine-disrupting chemicals used in hydraulic fracturing, and measured the chemicals’ ability to mimic or block the effects of the reproductive sex hormones estrogen and androgen. They found that 11 chemicals blocked estrogen hormones, 10 blocked androgen hormones and one mimicked estrogen.

    The researchers also collected samples of ground and surface water from several sites, including:

  • Accident sites in Garfield County, Colo., where hydraulic fracturing fluids had been spilled
  • Nearby portions of the Colorado River, the major drainage source for the region
  • Other parts of Garfield County, Colo., where there had been little drilling
  • Parts of Boone County, Mo., which had experienced no natural gas drilling
  • The water samples from drilling sites demonstrated higher endocrine-disrupting activity that could interfere with the body’s response to androgen and estrogen hormones. Drilling site water samples had moderate-to-high levels of endocrine-disrupting activity, and samples from the Colorado River showed moderate levels. In comparison, the researchers measured low levels of endocrine-disrupting activity in the Garfield County, Colo., sites that experienced little drilling and the Boone County, Mo., sites with no drilling.

    “Fracking is exempt from federal regulations to protect water quality, but spills associated with natural gas drilling can contaminate surface, ground and drinking water,” Nagel said. “We found more endocrine-disrupting activity in the water close to drilling locations that had experienced spills than at control sites. This could raise the risk of reproductive, metabolic, neurological and other diseases, especially in children who are exposed to endocrine-disrupting chemicals.”

    The study, “Estrogen and Androgen Receptor Activities of Hydraulic Fracturing Chemicals and Surface and Ground Water in a Drilling-Dense Region,” was published in the journal Endocrinology.

    From the Epoch Times (Sarah Matheson):

    The chemicals “could raise the risk of reproductive, metabolic, neurological and other diseases, especially in children who are exposed to EDCs [endocrine-disrupting chemicals],” said one of the study’s authors, Susan Nagel, of the University of Missouri School of Medicine.

    Researchers took surface and ground water samples from sites with drilling spills or accidents in Garfield County, Colo. The area has more than 10,000 natural gas wells. Researchers also looked at control samples from sites without spills in Garfield County, as well samples from Boone County, Missouri.

    The water samples from drilling sites had higher levels of EDC activity that could interfere with the body’s response to the reproductive hormone estrogen, and androgens, a class of hormones that includes testosterone.

    Drilling site water samples had moderate to high levels of the hormone-disrupting chemical. Water samples from the Colorado River, which is the drainage basin for the natural gas drilling sites, had moderate levels.

    Researchers found little EDC activity in the water samples from the sites with little drilling…

    Researchers looked at 12 suspected endocrine-disrupting chemicals used in fracking. They measured the chemicals’ ability to mimic, or block, the effect of the body’s male and female reproductive hormones…

    The study, “Estrogen and Androgen Receptor Activities of Hydraulic Fracturing Chemicals and Surface and Ground Water in a Drilling-Dense Region,” was published online on Dec. 16.

    More oil and gas coverage here and here.


    COGCC expects to look at riparian setbacks in the wake of September flooding and Parachute Creek spill

    December 15, 2013
    Production fluids leak into surface water September 2013 -- Photo/The Denver Post

    Production fluids leak into surface water September 2013 — Photo/The Denver Post

    From The Grand Junction Daily Sentinel (Dennis Webb):

    The head of the Colorado Oil and Gas Conservation Commission said Thursday that no firm decisions have been made about how to deal with the question of riparian setbacks following contamination problems in Parachute and on the Front Range. But in response to a question from Rifle citizen activist Leslie Robinson at the quarterly Northwest Colorado Oil & Gas Forum, commission director Matt Lepore promised some kind of action soon.

    “We will sit down in the not-too-distant future in a little more formal way and look certainly at the flooding in September and certainly Parachute Creek as well, as sort of a lessons-learned — what in light of those incidents seems appropriate to change or require or what have you,” he said.

    Lepore was speaking in reference to massive floods that caused damage including the leaking of tens of thousands of gallons of oil and produced water from production facilities, and to last winter’s leak of natural gas liquids from a pipeline leaving Williams’ gas processing plant near Parachute Creek.

    During a major rules rewrite in 2008, the COGCC set aside action on the question of riparian setbacks, except for requirements it imposed to protect municipal water supplies. Some activists consider it to be unfinished business that recent events have shown needs revisiting.

    In an interview, Robinson, president of the Grand Valley Citizens Alliance, said she hopes the COGCC isn’t going to consider lessons learned just on its own. “I hope that they ask for input from environmental and conservation groups like the GVCA,” she said. She said while the Front Range probably has been more impacted by problems related to oil and gas infrastructure near rivers, she’s worried about the proximity of wells to the Colorado River in the Parachute area and potential vulnerability to flooding.

    The leak up Parachute Creek resulted in an estimated 10,000 gallons of natural gas liquids getting into groundwater, with benzene ultimately reaching the creek. Williams spokeswoman Donna Gray said Thursday no benzene has been detected in the creek since August.

    Results are pending on a quarterly round of water testing in November that involved hundreds of sampling points.”

    More oil and gas coverage here and here.


    New online database charts water quality regulations related to oil and gas development

    December 11, 2013
    Groundwater movement via the USGS

    Groundwater movement via the USGS

    Here’s the release from the University of Colorado at Boulder:

    A searchable, comparative law database outlining water quality regulations for Colorado and other states experiencing shale oil and gas development is now available on LawAtlas.org.

    The Oil & Gas – Water Quality database project is led by the University of Colorado Boulder’s Intermountain Oil and Gas Best Management Practices (BMP) Project in partnership with Temple University’s Public Health Law Research program and its LawAtlas.org website.

    The newly launched Oil & Gas – Water Quality dataset (http://www.lawatlas.org/oilandgas) was created as a comparative tool for examining water quality laws and regulations related to oil and gas activities in Colorado, Montana, New Mexico, New York, North Dakota, Ohio, Pennsylvania, Texas, Utah, West Virginia and Wyoming.

    The database allows policymakers, local governments, industry officials and citizens to study the scope of water quality law in their state or to make comparisons with other states. An interactive map allows for easy navigation across different jurisdictions, and downloadable PDFs are available that document each state’s water quality regulations.

    “Across the nation, local and state government jurisdictions are experiencing new or increased oil and gas development,” said Matt Samelson, dataset creator, attorney and consultant for the CU-Boulder Intermountain Oil and Gas BMP Project. “When development occurs in these jurisdictions, there is tremendous value in examining regulatory regimes already in effect in order to guide conversations about best regulatory practices.”

    Oil and gas production has increased nationwide as technological developments improved directional drilling and hydraulic fracturing practices, which involve pumping pressurized water, sand and chemicals deep down well bores to create fissures in the shale in order to free oil and natural gas.

    In October, the U.S. Energy Information Administration predicted that the United States would surpass Russia and Saudi Arabia as the world’s largest producer of oil and natural gas by the end of 2013.

    “The development of oil and gas wells, particularly in urban and suburban areas, coupled with the practice of hydraulic fracturing has stimulated interest in laws designed to protect water quality,” said Kathryn Mutz, director of CU-Boulder’s Intermountain Oil and Gas BMP Project.

    Because water quality regulations depend on the stage of development, the Oil & Gas – Water Quality database has been divided into five stages of oil and gas activities: Permitting, Design and Construction; Well Drilling; Well Completion; Production and Operation; and Reclamation.

    Web users can select multiple queries and search by statute categories or by state. The water quality dataset contains nearly 100 distinct questions and corresponding regulations addressing oft-cited oil and gas development issues, such as public disclosure of chemicals used in hydraulic fracturing fluid; baseline water source testing; disposal of water in hydraulically fractured wells; and spill and accident reporting.

    The Oil & Gas – Water Quality database is curated by CU-Boulder’s Intermountain Oil and Gas BMP Project, part of the CU-Boulder Law School’s Getches-Wilkinson Center for Natural Resources, Energy and the Environment.

    The Oil & Gas – Water Quality database is supported by the Environmentally Friendly Drilling Program and a Sustainability Research Network grant from the National Science Foundation. The dataset is part of Public Health Law Research’s LawAtlas, an online portal exploring variations in laws relating to current public health issues nationwide. In the coming year, datasets for water quantity and air quality pertaining to oil and gas development will be added to the website.

    To learn more visit http://www.lawatlas.org/oilandgas.

    More oil and gas coverage here and here.


    Hydraulic Fracturing and Water Quality: Selected USGS Publications, August 2012 to present

    December 9, 2013
    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates

    Click here to go to the USGS website with links to their publications about hydraulic fracturing since 2012.

    More oil and gas coverage here and here.


    Eagle River Watershed Council: Hydraulic Fracturing & Water an informational panel, Wednesday December 11th

    December 7, 2013
    Directional drilling and hydraulic fracturing graphic via Al Granberg

    Directional drilling and hydraulic fracturing graphic via Al Granberg

    Click here to read the announcement.

    More oil and gas coverage here and here.


    CSU, Noble Energy and DNR partner on groundwater monitoring project in the Wattenberg field

    December 6, 2013
    Groundwater monitoring well

    Groundwater monitoring well

    From The Greeley Tribune (Sharon Dunn):

    Like the crime scene investigators on television, researchers in northern Colorado will be taking an intense look at water wells throughout the oil patch in a demonstration study in the coming months to determine changes in the water over time. Conducted through Colorado State University in partnership with Noble Energy, the Colorado Water Watch demonstration project will soon begin water table monitoring in test wells at roughly 10 Noble production sites in a real-time look at how the water changes.

    “It was conceived not so much as a research project but as a tool to provide information to the public,” said project lead researcher Ken Carlson, an associate professor Civil and Environmental Engineering at CSU. “The oil and gas industry is taking the initiative here to provide some visibility.” Read the rest of this entry »


    ‘Groundwater will be a part of the state water plan’ John Stulp #COWaterPlan

    December 5, 2013
    Colorado Water Plan website screen shot November 1, 2013

    Colorado Water Plan website screen shot November 1, 2013

    From The Pueblo Chieftain (Chris Woodka):

    Call it a wet-headed stepchild. Colorado has puzzled for years about how to account for its underground water resources, with about the same impact as water sloshing in the bottom of a precariously carried bucket. A state water plan will attempt to incorporate groundwater management, including possible aquifer storage, even though the relationship between surface water and well water is not fully understood.

    “Groundwater will be a part of the state water plan,” John Stulp, the governor’s water adviser, told about 80 attendees of a groundwater conference this week. “There are a number of studies and plans that will go forward as the state water plan is developed.”

    The conference, organized by the American Groundwater Trust, was designed to address policy as a follow-up to more technical reports generated from a 2012 conference.

    While Colorado water rights stretch back to the mid-1800s, groundwater in the state was of little concern until more high-capacity wells were drilled in the 1950s and 1960s. It wasn’t until 1969 that well use was incorporated into the elaborate web of prior appropriation water right, explained Steve Sims, a water lawyer who once defended the state’s water rights in the attorney general’s office. But since then, a tug-of-war between the General Assembly and water courts has muddied how groundwater is treated. Non-tributary wells are regulated by a separate commission.

    “What we got was a hodgepodge of rules,” Sims said. “It’s been driven by real estate developers.”

    Key court cases eroded the jurisdiction of water courts themselves as well as the power of the state engineer to regulate wells, he said. The Empire Lodge case triggered a legislative fix to substitute water supply plans in 2002. The 2009 Vance case changed the way the state accounts for water produced by oil and gas drilling.

    Geography also plays a part. Alluvial well regulations differ in all of the state’s major river basins, as well as in non-tributary basins. There is little scientific understanding of the relationship of groundwater levels to surface flows, other than the common wisdom that surface irrigation or flooding increase the levels, while pumping and drought decrease them. But the timing of return flows, availability of underground storage sites and long-term effects of pumping are still unknown.

    “It’s not a precise science,” said Reagan Waskom of the Colorado Water Institute, which is completing a study of the South Platte basin mandated by the state Legislature in 2012. “If you had a valve and could put water back into the river when you need it, it would be great.”

    More Colorado Water Plan coverage here.


    Text of the Colorado Basin Roundtable white paper for the IBCC and Colorado Water Plan

    December 3, 2013
    New supply development concepts via the Front Range roundtables

    New supply development concepts via the Front Range roundtables

    Here’s the text from the recently approved draft of the white paper:

    Introduction
    The Colorado River Basin is the “heart” of Colorado. The basin holds the headwaters of the Colorado River that form the mainstem of the river, some of the state’s most significant agriculture, the largest West Slope city and a large, expanding energy industry. The Colorado Basin is home to the most-visited national forest and much of Colorado’s recreation-based economy, including significant river-based recreation.

    Colorado’s population is projected by the State Demographer’s Office to nearly double by 2050, from the five million people we have today to nearly ten million. Most of the growth is expected to be along the Front Range urban corridor; however the fastest growth is expected to occur along the I-70 corridor within the Colorado Basin.

    Read the rest of this entry »


    Proposed oil and gas methane rules: Gov. Hickenlooper makes some headway with the environmental community

    November 29, 2013
    Governor Hickenlooper announcing new methane rules -- Associated Press via the Washington Post

    Governor Hickenlooper announcing new methane rules — Associated Press via the Washington Post

    From The Colorado Statesman (Peter Marcus):

    …the governor — who has experienced an increasingly tense relationship with environmentalists, a core base of his Democratic Party — still has a lot of work ahead of him if he’s to win the trust of the environmental world.

    Much of the controversy rests with Hickenlooper’s support of hydraulic fracturing. The governor, a former geologist, has unequivocally stated his support for so-called “fracking,” despite five local communities having banned or imposed moratoriums on the drilling process. First, Longmont voters banned fracking last year. Then this year, Broomfield, Fort Collins and Boulder joined with five-year moratoriums. Lafayette passed a ban on new oil and gas activities. The bans passed despite big spending by the Colorado Oil and Gas Association. Proponents of the bans, a largely grassroots uprising, spent about $27,500 in the four municipal elections, as of the last filings before the election. COGA, however, spent about $883,000 to fight the proposed bans…

    Hickenlooper says he is listening. At a news conference on Monday, he said the issue is about striking a balance between the energy needs of the state and the concerns expressed by citizens and communities.

    “What we’ve done is work with the environmental community and oil and gas community to try and find compromises and use common sense to say, ‘How can we make sure we get to the cleanest possible outcomes in terms of air quality?’ Yet at the same time recognize that we have businesses here that employ our citizens and are helping solve the energy challenges that we face as a country,” Hickenlooper said, as he proposed new pollution rules for the Air Quality Control Commission to adopt.

    The commission met on Thursday when it set a public hearing for February 2014. The tentative date is for a three-day hearing from Feb. 19-21. The commission heard about two hours of public comments from a wide spectrum of stakeholders, including industry leaders and environmentalists, as well as concerned citizens, such as mothers worried about the health of their children.

    The thrust of the public comments was on whether the commission should set the proposal for a public hearing. Most of the witnesses agreed that even if the draft isn’t perfect, it should move forward so that the process can evolve.

    When the commission conducts its public hearings in February, the comments will focus more on the rules themselves after stakeholders have had a chance to thoroughly review the recently released proposal.

    Several elected officials testified in support of setting a hearing for the rules, including Democratic Reps. Su Ryden of Aurora, Mike Foote of Lafayette, and Max Tyler of Lakewood, among others…

    Former Sen. Dan Grossman, regional director for the Environmental Defense Fund, represented the environmental side of the debate.

    “What you see today here is a remarkable coalition of earnest individuals who came together and decided to try and make something work and address air pollution from the oil and gas sector in a meaningful and reasonable way,” explained Grossman.

    Conservation Colorado is also “encouraged” by the proposed rules specifically that it includes methane.

    “The proposed rule is a strong step forward to capture emissions from oil and gas facilities of harmful air pollutants that hurt all Coloradans,” said Pete Maysmith, executive director of Conservation Colorado.

    “Oil and gas development is booming in Colorado and the state must move aggressively to protect our climate, public health and communities,” he added. “Given the devastating impact on Coloradans from climate change and increased ozone pollution, there is no margin for error.”[...]

    But not everyone in the environmental and oil and gas worlds is currently on board with the proposals. Stan Dempsey, president of the Colorado Petroleum Association, pointed out that his organization was not included in the stakeholder meetings and did not see the rules until Monday.

    “We’ve expressed our disappointment that it wasn’t a larger, broader stakeholder process,” said Dempsey, who added that his organization is currently speaking with members to decide how to proceed…

    More oil and gas coverage here and here.


    ‘[Governor Hickenlooper] should talk to the people who approved the bans, not the people who oppose them’ — Dan Randolph

    November 28, 2013
    Directional drilling and hydraulic fracturing graphic via Al Granberg

    Directional drilling and hydraulic fracturing graphic via Al Granberg

    From Colorado Public News (David O. Williams/Dale Rodebaugh) via The Durango Herald:

    “The fracking ban votes reflect the genuine anxiety and concern of having an industrial process close to neighborhoods,” Hickenlooper said recently in a prepared statement. The statement came after a tally of final votes showed residents in Broomfield successfully passed a fourth so-called “fracking ban” in Colorado.

    Fort Collins, Boulder and Lafayette voters passed similar bans by much wider margins earlier this month, but Broomfield’s vote was so close (10,350 to 10,333) that it has triggered an automatic recount.

    Christi Zeller, director of the La Plata County Energy Council, said the votes in Boulder and Lafayette are symbolic. Boulder County has some production, but the city of Boulder’s last gas well was plugged in 1999, she said.

    “The bans are an emotional response,” Zeller said. “A lot of professional agitators are manipulating people’s response.”[...]

    Hickenlooper said mineral rights need to be protected and that the four communities can work with the state’s chief regulatory agency, the Colorado Oil and Gas Conservation Commission, to mitigate environmental and health concerns.

    “Local fracking bans essentially deprive people of their legal rights to access the property they own. Our state Constitution protects these rights,” the governor said. “A framework exists for local communities to work collaboratively with state regulators and the energy industry. We all share the same desire of keeping communities safe.”

    But Dan Randolph, director of the San Juan Citizens Alliance, said that Hickenlooper, as a former gas and oil industry employee, doesn’t get it.

    Randolph said there are legitimate concerns tied to gas and oil production. He cited health, water quality and noise.

    “There is no question that there is an increase of volatile organic compounds in the air during gas and gas development,” Randolph said. “There are and have been serious concerns elsewhere. This is not unique to Colorado.

    “He should talk to the people who approved the bans, not the people who oppose them,” Randolph said. “His credibility on oil and gas issues is very low with the general public.”

    More oil and gas coverage here and here.


    Governor Hickenlooper and US Rep. Jared Polis differ regarding Colorado regulation of hydraulic fracturing

    November 20, 2013

    From The Denver Post (Allison Sherry):

    On the U.S. House of Representatives floor Tuesday, Rep. Jared Polis ripped Colorado’s state regulations involving hydraulic fracturing, saying the growth of fracking in the state “without common-sense federal guidelines, without common-sense state guidelines” has caused friction for his constituents.

    Polis, a Boulder Democrat, represents three municipalities — Boulder, Lafayette and Fort Collins — whose voters earlier this month approved moratoriums on the deep horizontal drilling technique. A fourth town, Broomfield, also had a moratorium proposal on the ballot, but officials are recounting that measure because the vote was so close.

    Polis never took a position on the fracking bans, but Tuesday he said fracking “is occurring very close to where people live and work and where they raise families.”

    “Yet our state doesn’t have any meaningful regulation to protect homeowners,” Polis said in a floor debate on a series of energy measures. “Unfortunately, the fracking rules are overseen by an oil and gas commission that is heavily influenced by the oil and gas industry. They don’t have at their disposal the independence or the ability to enact real penalties for violations of our laws and their charge is not first and foremost to protect homeowners and families and health.”

    Democratic Gov. John Hickenlooper’s office disagreed, saying ” the Colorado Constitution protects the rights of people to access their property above and below ground.”

    More oil and gas coverage here and here.


    Hydraulic fracturing, water and Colorado

    November 19, 2013

    Originally posted on Your Water Colorado Blog:

    Interested Coloradans joined the Colorado Foundation for Water Education in early November for an energy-water tour. Here, participants are hearing from and seeing an Anadarko site in the Denver-Julesburg Basin just north of Denver.

    Hydraulic fracturing has become a contentious issue– no one is arguing with that. As of election day, a mere two weeks ago, three Colorado cities approved bans or moratoriums on hydraulic fracturing– Boulder, Fort Collins and Lafayette– while Longmont had already established a ban and is being sued by the Colorado Oil and Gas Association. And don’t forget about Broomfield, where the debate hasn’t yet ended. From the High Country News Goat Blog:

     …It’s the closeness of the vote on a Broomfield ballot measure to ban the practice for five years. When results came in after the Nov. 5 election, it had lost by a mere 13 votes, triggering a mandatory recount. Last Thursday, though…

    View original 1,967 more words


    Colorado set to become first state to regulate detection, reduction of methane emissions associated with oil and gas drilling

    November 19, 2013
    Governor Hickenlooper announcing new methane rules -- Associated Press via the Washington Post

    Governor Hickenlooper announcing new methane rules — Associated Press via the Washington Post

    Here’s the release from Governor Hickenlooper’s office:

    Proposed rules for air pollution released today would make Colorado the first state to directly regulate detection and reduction of methane emissions associated with oil and gas drilling and further Colorado’s efforts as a national leader in environmental-friendly energy production.

    The rules, which cover the lifecycle of oil and gas development (from drilling to production to maintenance), reflect a collaborative effort by the Environmental Defense Fund and Noble Energy, Encana and Anadarko oil and gas companies as part of the Air Quality Control Division’s stakeholder process.

    The plan, with Gov. John Hickenlooper’s support and active engagement, constitutes the division’s official proposed rules and will now go before the state Air Quality Control Commission, which will meet Thursday, Nov. 21, and will be asked to set a February 2014 public hearing on the rules.

    “These proposed rules provide common sense measures to help ensure Colorado has the cleanest and safest oil and gas industry in the country,” Hickenlooper said. “The rules will help Colorado prepare for anticipated growth in energy development, while protecting public health and the environment. They represent a significant step forward in addressing a wider range of emissions that before now have not been directly regulated. We welcome the proposed rules and are grateful all of the interested parties worked together.”

    The comprehensive set of rules were crafted after an extensive process in which the Colorado Department of Public Health and Environment (CDPHE) sought input from diverse stakeholders across Colorado. The rules will now be subject to further input as the Air Quality Control Commission considers them under CDPHE’s formal rulemaking process.

    “Tackling smog and climate pollution from the oil and gas sector is a critical part of making sure communities are protected and that the lower carbon advantage of natural gas doesn’t simply leak away,” said Fred Krupp, president of the Environmental Defense Fund. “If this package is adopted, Coloradans will breathe easier, knowing they have the best rules in the country for controlling air pollution from oil and gas activities.”

    Anadarko, Encana and Noble jointly stated: “As citizens of Colorado, we all want clean air, and we support this joint proposal initiated by Gov. Hickenlooper. This collaboration is a good model for developing effective regulations and activities to monitor, control and reduce methane leaks and VOCs. The process and increased accountability established by the proposal will provide transparency and build public trust. We remain committed to continuously improving industry practices and protecting our communities through responsible energy development.”

    The rules will benefit Colorado’s public health, environment and economy by increasing the capture and use of clean burning natural gas. Highlights of the rules include:

  • A first-in-the-nation requirement for leak detection from tanks, pipelines, and other drilling and production processes, using instruments such as infrared cameras that can detect leaks that otherwise may not be discovered using other more conventional means.
  • Instrument-based monthly inspections on large sources of emissions.
  • An aggressive timeline for repair of leaks found using either these instrument-based methods or leaks found through sight, smell or sound.
  • Leak detection and repair of storage tanks, at well-site production facilities and at compressor stations.
  • Requirements for detection and repair of leaks of a wide variety of hydrocarbons, including VOCs and methane, another first in the country.
  • Expanding provisions statewide for reducing emissions of pollutants that today apply only in nonattainment areas, so anyone living near a well site would benefit.
  • New, more stringent limits on emissions from dehydrator units located near where people live and play.
  • “Colorado is fortunate to have a governor who is invested in protecting the state’s environment and who brought parties together to advance the draft regulations,” said Dr. Larry Wolk, executive director and chief medical officer at CDPHE.

    CDPHE estimates the package will reduce volatile organic compounds (VOC) emissions in Colorado by approximately 92,000 tons per year. That’s more VOC emissions than the VOCs emitted by all cars in Colorado in a year, and it would be a 34 percent reduction based on a 2011 inventory by CDPHE that showed oil and gas VOC emissions were approximately 275,000 tons. [ed. emphasis mine]

    The draft rules also include elements that have the unique and additional benefit of significantly reducing methane emissions.

    These kinds of significant reductions in VOC emissions will improve public health by decreasing asthma and other respiratory ailments.

    Colorado’s unique state rules would complete the state’s adoption of EPA rules that further reduce air pollution associated with oil and gas operations. Interested individuals and parties can submit comments on the proposed rules to the Air Quality Control Commission at cdphe.aqcc-comments@state.co.us. The proposal and related information may be found online here.

    From The Denver Post (Bruce Finley):

    State health officials rolled out groundbreaking rules for the oil and gas industry Monday to address worsening air pollution, including a requirement that companies control emissions of the greenhouse gas methane, linked to climate change. The rules would force companies to capture 95 percent of all toxic pollutants and volatile organic compounds they emit.

    This would cut overall air pollution by 92,000 tons a year — roughly equivalent to taking every car in the state off the road for a year, state health chief Larry Wolk said. Such reductions could help bring Colorado’s heavily populated Front Range, where smog and ozone are on the rise, back into compliance with federal air quality standards.

    No state has adopted rules directly limiting methane emitted by oil and gas operations. Federal government and United Nations authorities are developing rules to try to reduce such emissions because they are a large factor in global warming.

    “These are going to amount to the very best air quality regulations in the country,” Gov. John Hickenlooper said.

    He credited executives from Anadarko, Encana and Noble Energy — the state’s largest producers — for compromising and helping minimize environmental harm from drilling before the cost implications are fully known.

    “They understand it is a shared responsibility,” he said, “and they have really stepped up.”

    Under the rules, companies would have to:

    • Detect leaks from tanks, pipelines, wells and other facilities using devices such as infrared cameras.

    • Inspect for leaks at least once a month at large facilities and plug leaks.

    • Adhere to more stringent limits on emissions from equipment near where people live and play.

    • Use flare devices to burn off emissions from facilities not connected to pipelines.

    Noble Vice President Ted Brown said the prescribed practices are “the right thing to do” but added that “it’s a tough rule.”

    He and counterparts from Anadarko and Encana said they support the proposed rules as a way to operate more safely and build public trust.

    “Regulatory certainty is important to the company, and doing the right thing also is important to the company,” Encana’s Lem Smith said. Reducing industry air pollution will bring a “quantifiable environmental benefit.”

    Colorado Petroleum Association president Stan Dempsey questioned the state’s authority and the need for new rules. Regulation of industry air pollution might better be done through the state’s overall air pollution control program or by the Colorado Oil and Gas Conservation Commission, he said.

    The COGCC, part of the state Department of Natural Resources, has a dual mandate of promoting and regulating the industry and has been the primary overseer after contentious rule-makings over where wells can be drilled and protection of groundwater.

    But state air pollution control division director Will Allison said statutes give the state’s Department of Public Health and Environment the authority to regulate hydrocarbons. “Volatile organic compounds are one type of hydrocarbon. Methane is another type of hydrocarbon.”

    An industry study estimated the costs related to the new rules, assuming monthly inspections for leaks, could reach $80 million a year. A CDPHE study estimated costs at $30 million.

    “I am very concerned that the costs — especially for small and midsize operations — will be quite significant,” said John Jacus, an attorney who represented five companies in CDPHE stakeholder sessions.

    Environment groups, led by the Environmental Defense Fund, helped craft the proposed rules.

    “First in the nation, direct regulation of methane from oil and gas production facilities is a big, exciting step forward,” Conservation Colorado director Pete Maysmith said.

    Around the nation, state regulators have not dealt comprehensively with increasing air pollution from the oil and gas industry — a challenge as companies ramp up domestic energy production. And, when it comes to emissions of methane, the industry is largely unregulated, even though state data show oil and gas operations are a major source.

    Colorado’s political landscape for oil and gas development has been toughening, however, with voters in four cities passing moratoriums and a ban on operations inside city limits.

    The new air rules, to be hashed out at formal hearings in February, do not include a proposal to raise the threshold of air pollution above which companies would have to obtain permits from the state — 4,000 this year. State health officials had proposed reducing their administrative workload by raising the reporting threshold to 25 tons of air pollution per year from 2 tons to 5 tons. But state officials dropped the effort because the “messaging” to residents would be difficult, Allison said.

    “It was going to distract from the overall process,” he said. “We want the focus in this rule-making to be on emissions reduction.”

    From the Denver Business Journal (Cathy Proctor):

    Unveiled Monday, the proposed rule will be formally sent on Thursday to the Air Quality Control Commission, a division of the Colorado Department of Public Health and Environment (CDPHE). Public hearings are expected to be held in February. The proposed regulation aims to reduce the amount of natural gas and methane leaking into the air at all stages of industry operations, such as the well itself as well as storage tanks, pipelines and other steps along the path to market.

    At a press conference at the Capitol on Monday afternoon, Hickenlooper joined with representatives from EDF, Anadarko Petroleum Corp. (NYSE: APC), Noble Energy Inc. (NYSE: NBL) and Encana Corp. (NYSE: ECA) to praise the effort that went into the proposed rules…

    If adopted as proposed, Colorado will be the first state in the nation to regulate methane — an element of natural gas that’s a powerful greenhouse gas…

    Cutting those emissions, which contribute to asthma and other respiratory ailments, is expected to improve public health, according to the health department.

    Hickenlooper said the proposed rules were a group effort, requiring compromise on all sides.
    “We recognize, and the people should recognize, that the rules, while they will be enforced, they weren’t imposed,” he said, referring to the stakeholder group that worked with state officials to craft the proposal.

    Industry and environmental representatives in turn credited the governor for pushing the group to make the rules tough…

    Ted Brown, Noble’s senior vice president for the Rocky Mountain region, said his company also supports the proposal “because it’s the right thing to do.”

    “It’s a tough rule, it’s an additional layer of regulations,” Brown said.

    “But we wanted to develop a sound solution based on science. [ed. emphasis mine] We believe this proposal sends a clear message — we can have a health environment, clean air, and responsible energy development here in Colorado,” Brown said.

    More oil and gas coverage here and here.


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