‘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:

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 »

‘Keeping the last wild river in the [#ColoradoRiver] Basin intact is important to a healthy environment’ — Susan Bruce

December 2, 2013
Yampa River Basin via the Colorado Geological Survey

Yampa River Basin via the Colorado Geological Survey

Here’s a post arguing to keep the Yampa River riparian system as a baseline for a healthy river from Susan Bruce writing for the Earth Island Journal. Here’s an excerpt:

Governor John Hickenlooper’s directive to the Colorado Water Conservation Board earlier this year to create a Colorado Water Plan by 2015 has put the Yampa, which has the second largest watershed in the state, under the spotlight.

Efforts to dam the Yampa go back to the proposed construction of Echo Park Dam, which Congress vetoed in 1952, bowing to a groundswell of public outcry led by David Brower, then with the Sierra Club. But in a compromise he later regretted, Brower supported the construction of two other dams: Glen Canyon on the Colorado River and Flaming Gorge on the Green River. The Green and Yampa rivers used to have similar flows and ecosystems. The construction of the Flaming Gorge Dam in 1962 modified the Green’s hydrograph, reducing sediment flow by half and tapering its seasonal fluctuations to a slower, more consistent flow, opening the way for invasive species like the tamarisk tree to crowd out native ones.

More recently, in 2006, there was a proposal to build a reservoir near Maybell, CO, and pump water from the Yampa to a reservoir about 230 miles away for municipal and agricultural use on the Front Range. But the plan was scrapped due to environmental and cost concerns; the reservoir would have cost between $3 billion and $5 billion.

The oil and gas industry is also eyeing the Yampa. Shell Oil had plans to pump about 8 percent of the Yampa’s high-water flow to fill a 1,000-acre reservoir, but it shelved the proposal in 2010, citing a slowdown of its oil-shale development program. Still, oil production in Colorado is at its highest level since 1957 and gas production at an all-time high. While industrial and municipal water needs are projected to increase with population growth, the largest water user, agriculture, will continue to divert the lion’s share of Colorado’s water, around 80 percent. All of which mean the pressure to suck up Yampa’s water is only going to grow.

The most unique characteristic of the Yampa is its wild and unimpeded flow, in particular the extensive spring flooding that washes away sediment, giving the river its brownish hue. This “river dance” helps establish new streamside forests, wetlands, and sandy beaches, as well as shallows that support species like the endangered Colorado pikeminnow and razorback sucker. By late fall, the water barely covers the riverbed in some stretches…

The rafting industry, which contributes more than $150 million to Colorado’s economy, has a strong voice when it comes to the Yampa’s future. Although damming the Yampa would provide a more consistent flow over a longer season, George Wendt – founder of OARS, the largest rafting company in the world – speaks for most outfitters when he says he would rather see the Yampa retain its natural state.

Conservationists also argue that the Yampa’s full flow helps meet Colorado’s legal obligation to provide water to the seven states within the Colorado Basin and Mexico. Measures being considered to protect the Yampa include an instream flow appropriation by the Colorado Water Conservation Board that would reserve Yampa’s water for the natural function of rivers, and a Wild and Scenic River designation by Congress.

Many proponents of keeping the Yampa wild point to its value as a baseline – an ecosystem naturally in balance. “If things go awry on dammed rivers, which they do, we have a control river, so to speak,” says Kent Vertrees of The Friends of the Yampa. “Keeping the last wild river in the Colorado Basin intact is important to a healthy environment and so future generations can experience in situ millions of years of history little changed by man.”

More Yampa River Basin coverage here and here.

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.


November 27, 2013

Coyote Gulch:

More Shoshone plant coverage here.

Originally posted on Your Water Colorado Blog:

Interstate 70 through Colorado

This small hydroplant, tucked away behind I-70 in Glenwood Canyon can be hard to spot– many drive right past without knowing its there– but, thanks to its water right, Shoshone has a big impact. Listen to our latest show in the radio series Connecting to Drops to hear about the critical role Xcel Energy’s Shoshone plays on the upper Colorado.

From the article, Phoning for Flows, in the Summer 2011 issue of Headwaters magazine.

The single most important water right in understanding management of the Colorado River, however, is far from the oldest. It belongs to the Shoshone hydroelectric plant in Glenwood Canyon. Driving through the canyon since the completion of Interstate 70, it’s easy to miss the pumpkin pie-colored buildings now located below road grade. Water people don’t. They understand the influence of the water rights there, which affect the distribution of water both east to Denver and west…

View original 201 more words

Lincoln Park/Cotter Mill superfund site: November 5 spill caused by pipeline joint failure

November 23, 2013
Lincoln Park/Cotter Mill Site via The Denver Post

Lincoln Park/Cotter Mill Site via The Denver Post

From the Cañon City Daily Record (Christy Steadman):

Jennifer Opila, Radioactive Materials Unit Leader for the CDPHE, explained how the 1988 pumpback system at Cotter functions. Opila said the cause of the Nov. 5 spill was that a joint in the pipeline of the pumpback system broke. She described it as a “catastrophic break,” meaning it was not a “slow and seeping” spill.

Opila said employees found “water coming out of the ground” just north of well No. 333 and “that’s how they knew the pipe had ruptured.”

According to Cotter’s Environmental Coordinator/Radiation Safety Officer Jim Cain, the spill was measured within a 12-hour window and based on inspection times and flow, an estimated 4,000 to 9,000 gallons of water was spilled. A water sample was collected and the analysis reported that .03 pounds of uranium and .15 pounds of molybdenum was found, according to Cain.

Cotter made the required oral report of the spill and provided a requested written report, Opila said, and the pipe was repaired and operable by the next day.

The pipeline is three feet underground and consists of 3,856 linear feet of six-inch schedule 90 PVC pipe and 3,053 linear feet of four-inch schedule 90 PVC pipe.

Vice President of Cotter Mill Operations John Hamrick said there have been three leaks “in three different years, all for different reasons.”

More Lincoln Park/Cotter Mill superfund site coverage here and here.

First Small Hydro Project in Colorado Moves Forward Thanks to Regulatory Efficiency Act

November 23, 2013
Mayflower Mill

Mayflower Mill

Here’s the release from US Senator Michael Bennet’s office:

Colorado U.S. Senator Michael Bennet today announced that the Silverton-based San Juan County Historical Society’s small hydro project would be allowed to move forward without undergoing the burdensome and expensive federal permitting process thanks to the Hydropower Regulator Efficiency Act. The bill, which Bennet cosponsored, cuts red tape for noncontroversial hydro projects that are less than 5 megawatts.

The Federal Energy Regulatory Commission officially announced last night that the project would not be subject to the federal permitting process, thanks to the bill, which passed Congress unanimously in August. As a result, the 11-kilowatt Silverton project will be the first small hydro project in the state, and one of the first in the nation to take advantage of this streamlined system.

“The Hydropower industry has tremendous potential to stimulate economic growth and job creation in Colorado,” Bennet said. “This common-sense bipartisan bill removes unnecessary regulations to help small projects like this one get up and running in communities across the state. We should continue to look for ways to cut through red tape and promote these types of clean, cost-effective energy sources.”

“The Feds had previously said that our project needed to apply for a hydropower license, but requiring a federal license for a tiny, non-controversial hydro project on an existing pipeline didn’t make sense,” Beverly Rich, Chair of the San Juan County Historical Society, said. The Historical Society operates the Mayflower Mill site where the new hydropower project is being built. “We’re grateful to Senator Bennet for helping us cut through this red tape.”

In addition to Silverton, projects in Telluride and Orchard City are working to take advantage of this reform under the new law.

The Hydropower Improvement Act was a companion bill to H.R. 267, the Hydropower Regulatory Efficiency Act of 2013, sponsored by Reps. Diana DeGette (D-CO) and Cathy McMorris-Rogers (R-WA).

Background Info on the Hydropower Regulatory Efficiency Act:

Prior to the new law, the costly federal permitting requirements had been a barrier to entry for small hydropower developments. In many cases, the cost of federal permitting exceeded the cost of the hydro equipment.

The Hydropower Regulatory Efficiency Act solves this problem by creating a “regulatory off-ramp” from permitting requirements for small, non-controversial hydro projects on existing conduits, such as pipelines and canals. It doesn’t change any underlying federal or state environmental statute, it simply streamlines the federal approval process.

The Colorado Small Hydro Association estimates that 100 MW of new hydro development in the state could mean 500 new jobs in various fields including developers, engineers, plumbers, carpenters, and others.

For more details on the Silverton hydro project, feel free to call Beverly Rich, Chair of the San Juan County Historical Society, at 970-387-5488.

More San Juan Historical Society coverage here. More H.R. 267 coverage here. More hydroelectric coverage 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.

    Gov. Hickenlooper to announce proposed first-of-its-kind air regulation rules for oil and gas drilling today

    November 18, 2013
    Directional drilling from one well site via the National Forest Service

    Directional drilling from one well site via the National Forest Service

    From email from Governor Hickenlooper’s office:

    Gov. John Hickenlooper will be joined Monday by environmental groups and energy companies to announce proposed rules that would make Colorado the first state to directly regulate detection and reduction of methane emissions associated with oil and gas drilling. The rules would also further Colorado’s efforts as a national leader in environmental-friendly energy production.

    WHEN: 1 p.m., Monday, Nov. 18, 2013
    WHERE: West Foyer, state Capitol, Denver

    The comprehensive set of rules were crafted after an extensive process in which the Colorado Department of Public Health and Environment sought input from diverse stakeholders across Colorado.

    More oil and gas coverage here and here.

    Garfield County facing decision over continued groundwater sampling in the West Divide area

    November 17, 2013
    Looking over Hunter Mesa along Mamm Creek above Rifle via Aspen Journalism

    Looking over Hunter Mesa along Mamm Creek above Rifle via Aspen Journalism

    From The Grand Junction Daily Sentinel (Dennis Webb):

    A woman living south of Silt urged Garfield County commissioners Tuesday to continue groundwater sampling there despite new tests finding no clear evidence of a link between methane and benzene in test wells and natural gas development. Lisa Bracken made her plea after representatives of the firm Tetra Tech presented the county with results from the third phase of a nine-year groundwater study in the area. It was conducted after the 2004 discovery of natural gas and benzene in West Divide Creek. The state blamed a faulty Encana well.

    The latest tests involved three pairs of groundwater monitoring wells installed by the county, with each pair drilled to depths of about 400 and 600 feet deep in the Wasatch geological formation. The study found that methane in the shallower wells was biogenic, meaning from microbial sources, whereas methane in the deeper wells was thermogenic, resulting from geological heat and pressure. Thermogenic gas is what energy companies target for drilling.

    The Tetra Tech consultants believe all the gas in the test wells is likely naturally occurring rather than a result of oil and gas development. Geoffrey Thyne, a longtime consulting geologist for the county, agrees that the research demonstrates that there is naturally occurring Wasatch formation methane that helps explain at least some of the methane being found in a number of domestic water wells.

    But Bracken, who lives near the seep area, believes 600 feet is a suspiciously shallow level to be finding thermogenic gas. She said she also found “astonishing” the widespread detection of benzene, a carcinogen, in test well samples. Those detections were within safe drinking water standards in all but one case, and Tetra Tech theorizes the benzene also is naturally occurring.

    County commissioners plan to seek a meeting with Thyne, and state oil and gas and health officials, before determining whether the county should undertake any more research.

    Resident Marion Wells of Rulison said after Tuesday’s meeting that the latest research relies on several assumptions, including that carbon dioxide is present to allow for the kind of biogenic process believed to account for methane in the shallower test wells.

    More oil and gas coverage here and here.

    Northern Water to host meeting about reporting requirements for oil and gas production and exploration, November 18

    November 16, 2013
    Wattenberg Oil and Gas Field via Free Range Longmont

    Wattenberg Oil and Gas Field via Free Range Longmont

    Here’s the release from Northern Water via The Greeley Tribune:

    A meeting in Greeley next week will focus on water-reporting procedures for users providing water to oil and gas operations. The Northern Colorado Water Conservancy is hosting the meeting, which will take place at 1:30 p.m. Monday in Columbine Room A at the University of Northern Colorado’s University Center, 2045 10th Ave.

    As Northern Water officials explained in a press release, the significant increase in oil and gas activity in northern Colorado requires a portion of the region’s water supply. In response to the water needs, the Northern Water board adopted rules governing the use of its Colorado-Big Thompson Project water and Windy Gap Project water for such purposes.

    The rules require water users providing project water to oil and gas development to periodically report usage information to Northern Water.

    To further describe the reporting requirements, Northern Water officials developed water-use reporting and accounting procedures that became effective June 1, 2012. Northern Water officials are now proposing modifications to those procedures. The purpose of Monday’s meeting is to discuss the proposed modifications.

    For more information, go to http://www.northernwater.org, or contact Brian Werner at (970) 622-2229, or bwerner@northernwater.org.

    More oil and gas coverage here and here.

    A look at oil and gas water recycling and deep disposal

    November 15, 2013
    Deep injection well

    Deep injection well

    From the Northern Colorado Business Report (Steve Lynn):

    High Sierra, which has its roots in Greeley, has developed industry-leading treatment processes, allowing oil companies to turn over their used water to a High Sierra facility, where it is treated and transported back to the oilfields.

    This year the company expects to recycle about 2,000 barrels of water daily at its Weld County facilities, up from some 1,500 barrels last year…

    High Sierra has operations in the Denver-Julesburg Basin, which includes Northern Colorado, and also works in Wyoming, Oklahoma and Kansas. In Weld County, High Sierra owns two water-recycling facilities, one in Briggsdale and another in Platteville, which company representatives believe are the largest such facilities in Northern Colorado.

    “The field seems to be moving toward recycling slowly but surely,” said Doug White, vice president of High Sierra Water.

    Companies can use more than 3 million gallons of water per well during hydraulic fracturing, a well-completion technique that involves pumping water, sand and chemicals at high pressures to crack tight shale formations and release oil and natural gas. After the well is complete, water flows back to the surface where it is captured and transported offsite. Most of this contaminated water still is disposed of via deep-injection wells, but growing amounts are treated and reused.

    High Sierra Water owns nearly half of the 25 deep-injection wells operating in the greater Wattenberg area. These are designated specifically for wastewater and regulated by state authorities. The greater Wattenberg area spans nearly 3,000 square miles north of Denver and through a substantial portion of Weld County.

    High Sierra has developed water-treatment systems that remove elements such as barium, calcium, magnesium, silica, strontium and iron so companies can reuse the water for hydraulic fracturing.

    The company has the ability to treat water to match the quality of fresh water, company representatives said. In Wyoming, for example, the company operates a water-treatment facility that has recycled more than 32 million barrels of water and discharged more than 5 million barrels of highly treated water into the New Fork River, a tributary of the Green and Colorado rivers…

    Noble Energy said in October that it had recycled about 2 percent of its water so far this year, or 600,000 barrels.

    But Noble is in the midst of a major expansion of its water-recycling program. Today, about 80 percent of Noble Energy’s water comes from ponds and wells and 18 percent from cities, while 2 percent is recycled. Noble Energy plans to raise the capacity of its program to recycle 5.8 million barrels of water next year, nearly 10 times more than its current level.

    Despite the efforts of companies such as High Sierra Water and Noble Energy, water recycling remains uncommon in Northern Colorado despite heavy drilling activity.

    It is more common in Western Colorado, where about half of water used in oil and gas production is recycled, said Ken Carlson, a civil engineering professor at Colorado State University.

    More oil and gas coverage here and here.

    Broomfield fracking ban approved after outstanding ballots counted

    November 15, 2013

    More 2013 Colorado November election coverage here. More oil and gas coverage here and here.

    2013 Yampa Basin Water Forum recap

    November 12, 2013
    Yampa River Basin via the Colorado Geological Survey

    Yampa River Basin via the Colorado Geological Survey

    From Steamboat Today (Michael Schrantz):

    At the Community Alliance of the Yampa Valley’s 2013 Yampa Basin Water Forum, [Diane Mitsch Bush] and fellow presenters Kent Vertrees, Kevin McBride and Jay Gallagher talked through the issues and challenges ahead for the state as it races to meet the December 2014 deadline set out by Gov. John Hickenlooper’s executive order for a state water plan draft. Vertrees is a member of the Yampa/White Basin Roundtable, Gallagher represents the Yampa-White River Basin on the Colorado Water Conservation Board, McBride is on the board of the 2013 Colorado Water Congress, and Mitsch Bush serves on state house committees that oversee water issues. All four represent the interests of the Yampa River Basin in the complicated confluence of water and policy.

    Their presentation Monday night at Bud Werner Memorial Library briefed attendees on geology, hydrology and water law as it applies to the Yampa River and Colorado.

    The Yampa River, being largely a wild river with a natural hydrograph, is an anomaly among Colorado rivers, and as multiple members of the panel pointed out, that gives the basin a chance to buck the constraints of other basins across the state.

    The amount of water in the Yampa River Basin is large compared to other basins, McBride said…

    There’s pieces of Colorado water law that would push the Yampa toward developing the same constraints faced in the South Platte River Basin, McBride said, but there’s also opportunity to do something different.

    There are many constraints on the future water plan outlined in the presentation, such as highly variable annual flows, climate change, existing water laws and interstate and international agreements, local control and balancing the impact on existing uses and future growth.

    There are interests on the Front Range that would look to the Yampa as a reservoir for their needs, Mitsch Bush said, and if consensus can’t be reached with them, the Western Slope will have to stand by its interests…

    “Here in Northwest Colorado, we can have that wild river in some ways,” Vertrees said about the best case scenario from the state water plan. “We can have smart storage. We can continue to provide for agriculture needs.”

    More Yampa River Basin coverage here and here.

    ‘The Front Range is thirsty. They want our water, and they’ve taken it’ — J. Paul Brown

    November 11, 2013


    From The Durango Herald (Brandon Mathis):

    …La Plata County sheep and cattle rancher J. Paul Brown addressed a crowd of about 40 people at Christina’s Grill & Bar on Saturday morning to announce his plans to retake the House seat he lost by two percentage points in 2012 to Durango attorney Mike McLachlan. He called the district, which includes La Plata, Archuleta, Hinsdale, Ouray and a portion of Gunnison counties, one of the most beautiful places in the world and one of great importance to the state and nation.

    “We are the pull of all of Colorado,” he said. “Tourism, mining, gas and oil, hospitals. It’s a wonderful district.”

    While Brown, a Republican, said he is not yet ready to propose specific legislation, he did say he had a long list of issues and possible bills…

    “Water is an issue here, and it always will be,” he said. “The Front Range is thirsty. They want our water, and they’ve taken it.”

    Brown mentioned water-storage initiatives to keep water on the Western Slope and in the state.

    “Six hundred thousand acre feet of water just went to Kansas and Nebraska,” he said. “That’s our water – we just don’t have any way to keep it.”[...]

    La Plata County Planning Commissioner and beef rancher Wayne Buck supports Brown’s ideology. He called Brown a politician of moral fiber and character.

    “He’s honest, and Lord knows we need honest politicians in Denver and in Washington, D.C.,” Buck said.

    From The Denver Post (Kurtis Lee):</p.

    Steve House, a healthcare consultant from Brighton, will announce his candidacy for governor Monday in Adams County…

    House is now among five Republicans vying to unseat Democratic Gov. John Hickenlooper in 2014. Sen. Greg Brophy of Wray, Secretary of State Scott Gessler, former state Sen. Mike Kopp and former U.S. Rep. Tom Tancredo have all announced their candidacies for governor.

    More 2014 Colorado Election coverage here.

    Secretary Jewell Applauds President’s Intent to Nominate Neil Kornze as Director of the Bureau of Land Management

    November 10, 2013
    Photovoltaic Solar Array

    Photovoltaic Solar Array

    Here’s the release from the Department of Interior:

    Secretary of the Interior Sally Jewell today praised President Obama’s intent to nominate Neil G. Kornze as Director of the Bureau of Land Management (BLM). If confirmed by the U.S. Senate, Kornze would head a bureau that manages more than 245 million acres of public land under a multiple-use and sustained yield mission.

    “Neil has helped implement forward-looking reforms at the BLM to promote energy development in areas of minimal conflict, drive landscape-level planning efforts, and dramatically expand the agency’s use of technology to speed up the process for energy permitting,” said Jewell. “For more than a decade, Neil has been a key player in many of the nation’s major natural resource policy issues and has a reputation for being creative and results-oriented. His record at the BLM is marked by an inclusive approach and an openness to new ideas as the agency supports efforts to foster economic opportunities through safe and responsible energy development and increased access to the nation’s system of conservation lands.”

    Kornze has led the BLM since March 1, 2013, as Principal Deputy Director, overseeing its conservation, outdoor recreation and energy development programs. Prior to this role, Kornze served as the BLM’s Acting Deputy Director for Policy and Programs since October 2011. He joined the agency in January 2011 as a Senior Advisor to the Director and has worked on a range of issues, including renewable and conventional energy development, transmission siting and conservation policy. He also has been active in tribal consultation, especially regarding oil, gas and renewable energy development in Indian Country.

    Kornze played a key role in developing the Western Solar Plan, which established 17 low-conflict zones for commercial solar energy development and also identified lands appropriate for conservation, and the agency’s approval of 47 solar, wind and geothermal utility-scale projects on public lands, as a leader of the Department’s Renewable Energy Strike Team. When built, these projects add up to more than 13,300 megawatts – enough electricity to power 4.6 million homes and support 19,000 construction and operations jobs. He also has been a leader in reforming BLM’s oil and gas program, including the upcoming launch of a nation-wide online permitting system that could significantly reduce drilling permit processing times, and in the bureau’s efforts to enhance and increase visitors to the diverse system of national conservation lands.

    Before joining the BLM, Kornze was a Senior Policy Advisor to Senate Majority Leader Harry Reid, working on renewable energy, mining, water, outdoor recreation, rural development and wildlife conservation issues. He worked closely on developing and helping pass critical national legislation, including the Omnibus Public Lands Act of 2009 and the reauthorization of the Secure Rural Schools and Payment-in-Lieu-of-Taxes programs. Raised in Elko, NV, by a family with a long history in mining, Kornze has a master’s degree in International Relations from the London School of Economics and is a Phi Beta Kappa graduate with a degree in Politics from Whitman College in Walla Walla, WA.

    The BLM has an annual budget of $1.1 billion and 10,250 employees who carry out a multiple-use and sustained yield mission to sustain the health, diversity and productivity of the public lands – mostly in 12 western states – for the use and enjoyment of present and future generations. The BLM hosts more than 59 million visits annually and administers the National System of Public Lands, which encompasses about 13 percent of the total land surface of the United States and more than 40 percent of all land managed by the federal government. BLM also manages 700 million acres of sub-surface mineral estate across the nation.

    From the Denver Business Journal (Mark Harden):

    Environmental groups praised the choice.

    “Neil Kornze will bring his western upbringing and values, combined with conservation knowledge, experience, and judgment to the director’s office at BLM,” said Trevor Kincaid of the Denver-based Center for Western Priorities. “Mr. Kornze’s record of finding compromise between divergent positions makes him an ideal candidate for the challenges facing BLM.”

    Kornze faces confirmation by the U.S. Senate. U.S. Sen. Orrin Hatch, R-Utah, told the Salt Lake Tribune that while “the fact that Mr. Kornze is from the West is a good thing,” he plans to bring up such issues as sage grouse management and hydraulic fracturing as Kornze’s nomination is considered.
    In Colorado, some 1.7 million acres of BLM land are habitat for the greater sage grouse, whose dwindling numbers have led state and federal officials to weigh restrictions on energy development and grazing to protect the bird.

    From The Grand Junction Daily Sentinel (Gary Harmon):

    A former adviser to Sen. Harry Reid, D-Nev., will head the nation’s largest land-management agency, if Neil Kornze is approved by the Senate. President Barack Obama nominated Kornze to head the Bureau of Land Management on Thursday. The agency last had a permanent chief in May 2012.

    Kornze’s nomination won quick support from U.S. Sen. Michael Bennet, D-Colo., who cited in a statement his office’s good working relationship with Kornze.

    “Being from the West and having demonstrated experience in the Congress and at the bureau make him a qualified candidate for the job,” Bennet said. “We’re looking forward to hearing more about how his priorities for the BLM will help our state balance the need for responsible energy development with recreation and the protection of our public lands and wildlife habitat.”

    Kornze grew up in Elko, Nev., and has headed the Bureau of Land Management since March 1. He joined the agency in 2011 as a senior adviser to Director Robert Abbey, working on renewable and conventional energy development and conservation policy. He worked previously with Reid.

    U.S. Sen. Mark Udall, D-Colo., is reviewing Kornze’s nomination, Udall’s office said.

    Kornze’s position on state water rights is an important issue, U.S. Rep. Scott Tipton, R-Colo., said in a statement.

    Tipton has criticized the BLM and U.S. Forest Service for demanding state water rights in exchange for permits to graze or operate on federal lands.

    “It’s critically important that the director of the BLM understands the importance of multiple-use of public lands, and strives to achieve a balance of conservation and responsible use of the abundant natural resources on those lands,” Tipton said in a statement.

    Western Colorado is dependent on the bureau’s energy policies, David Ludlam of the West Slope Colorado Oil and Gas Association said.

    “So the responsibility falls to our community to reach out to Mr. Kornze early, often and constructively to open up access to the natural gas reserves so fundamental to our economy and quality of life,” Ludlam said.

    The BLM’s Grand Junction Field Office administers about 1 million acres in Mesa and surrounding counties, including U.S Forest Service lands it manages for the mineral deposits beneath them.

    The BLM administers more than 245 million acres of public lands nationwide.

    Lincoln Park/Cotter Mill superfund site: 9,000 gallon spill contained on mill property

    November 8, 2013
    Lincoln Park/Cotter Mill site via The Denver Post

    Lincoln Park/Cotter Mill site via The Denver Post

    From The Pueblo Chieftain (Tracy Harmon):

    Cotter Corp. Uranium Mill officials on Tuesday discovered contaminated water escaped a pump-back system at the mill site but the spill has been contained to the mill property. According to Warren Smith, community involvement manager for the state health department, the release of contaminated water was limited to between 4,000 and 9,000 gallons. The leak occurred at the junction of two pipe sections near the Soil Conservation Service pump back site, which is designed to prevent contaminated surface water from seeping into the neighboring Lincoln Park neighborhood.

    “The soil in the area of the release is saturated. It will be allowed to dry so the pipe can be excavated and repaired,” Smith said.

    Water samples were analyzed and based on concentration levels present, the maximum estimated release of uranium is limited to 1.1 ounces and the estimated molybdenum release is 2.6 ounces.

    Contaminated water usually is pumped, along with groundwater, to an onsite evaporation pond to prevent further contamination in Lincoln Park, which has been a part of a Superfund cleanup site since 1988. The now-defunct mill is in the process of decommissioning and has not been used to process uranium since 2006.

    From the Colorado Independent (Shelby Kinney-Lang):

    Cotter Corporation informed the health department of the leaking pipes on Tuesday in a “verbal report” delivered over the phone. No health department personnel have inspected the spill site, as yet, and no formal report has yet been filed. Cotter said it will let the contaminated ground dry before excavating and repairing the pipe…

    “We’ve got a company looking to walk away from a problem without actually cleaning it up,” said Travis E. Stills, an energy and conservation lawyer who has been working with community groups in Cañon City since the mid-2000s. Stills represents Colorado Citizens Against Toxic Waste on several ongoing state open records suits that seek information that passed between Cotter, the state health department and the Environmental Protection Agency concerning the uranium mill and the Lincoln Park Superfund Site, but which health department withheld from public review.

    Uranium is extraordinarily toxic. The health department reports that if the pipe did in fact leak 9,000 gallons, the concentration in the water of uranium would be 834 micrograms per liter and the concentration of molybdenum, also a toxic chemical, would be 2,018 micrograms per liter. For perspective, the EPA places the health safety level of uranium at 30 micrograms per liter…

    “They got a hole in the pipe and it leaked back into the ground,” he said.

    Warren Smith, community involvement manager in the Hazardous Materials and Waste Management Division of the department, insisted there was no danger to public health.

    “There is no public health risk here, because there is no exposure to the public,” Smith said. “Health risk depends on two factors: the release and exposure. If there’s no receptor to be exposed to it, where’s the risk?”

    Smith said that the health department performs regular inspections of the Cotter site. The most recent was a September inspection. Because the pipe was buried, Smith said it would be a stretch to “characterize it as an [inspection] oversight.”

    Smith said it would be a serious lapse if Cotter had failed to report the spill. Inspections don’t occur often enough for the state to have happened upon the spill any time soon.

    More Lincoln Park/Cotter Mill superfund site coverage here and here.

    Boulder, Fort Collins and Lafayette pass bans on hydraulic fracturing, Broomfield = no by 13 votes (2:41 AM numbers)

    November 6, 2013
    Dilbert's company embraces hydraulic fracturing for competitive advantage

    Dilbert’s company embraces hydraulic fracturing for competitive advantage

    From the Denver Business Journal (Cathy Proctor):

    The votes in four Colorado cities on fracking within city limits — in Boulder, Broomfield, Fort Collins and Lafayette — attracted attention far beyond the state’s borders in recent weeks as the nation debates the pros and cons of the widely used practice. And those involved say the issues raised by the campaigns will continue to be debated for months and years to come.

    Boulder’s anti-fracking measure was passing handily late Tuesday, while those in Fort Collins and Lafayette saw smaller margins in the “yes” column.

    Meanwhile, the yes and no votes on Broomfield’s fracking measure were fairly close late Tuesday, although at least one anti-fracking advocate — Sam Schabacker, Mountain West regional director for Food & Water Watch — appeared ready to concede defeat there.
    “We are witnessing historic victories tonight with the anticipated passage of measures to stop fracking in Fort Collins, Boulder and Lafayette, and what appears to be a narrow defeat of a fracking moratorium measure in Broomfield,” he said in an emailed statement at 10:29 p.m. MST…

    Doug Flanders, a spokesman for the Colorado Oil & Gas Association, an industry trade group, said his organization…will continue to work with communities about the importance of energy and energy development.

    “We never believe a ban is necessary,” Flanders said earlier Tuesday, before the polls closed…

    The four initiatives:

    • Broomfield: Question 300, which would have imposed a five-year prohibition on all fracking.
    • Fort Collins: Its measure will place a five-year moratorium on fracking and storage of waste products related to the oil and gas industry in town.
    • City of Boulder: 2H imposes a five-year moratorium on oil and gas exploration.
    • Lafayette: Question No. 300 will ban new oil and gas wells in town. (Click here for more on the Lafayette measure, which goes further than the others.)

    More oil and gas coverage here and here.

    Cleveland Start-Up to Offer Smart Water Meter on Kickstarter

    November 5, 2013
    Sprav smart water meter

    Sprav smart water meter

    Here’s the release from Sprav Water, LLC:

    Sprav Water LLC, the makers of a smart water meter that allows users to determine, in real time, shower water and energy usage, today announced the launch of their Kickstarter campaign (http://kck.st/19QVpBg) to help fund the development of the revolutionary new product. The new meters, which easily clip onto the pipe behind the user’s existing showerhead, can help save consumers hundreds of dollars per year by reducing water and energy costs from showering.

    “The idea started as an extra credit assignment at Case Western where we were tasked with creating a tool to reduce energy consumption in homes,” said Craig Lewis, CEO of Sprav Water. “We all sat down and thought back to the days when we were kids getting yelled at for taking too long in the shower, and realized that this was a market with little innovation and great opportunity for growth.”

    Real-time feedback from an easy to view lighted indicator allows the user to manage shower duration and hot water usage. Users can also view periodic usage reports, set custom goals, and even view shower usage in real-time, through a simple mobile app on their smartphones or tablets. The device is designed to better control household water usage and drive greater awareness and action toward the conservation of local, state and national natural resources.

    The Cleveland start-up is comprised of three Case Western Reserve University engineering students and an industrial design graduate from the Cleveland Institute of Art. Sprav Water was recently seed-funded by Bizdom, a nonprofit entrepreneurship accelerator for tech-based companies who operate their business in the downtown cores of Detroit and Cleveland.

    “We’ve had a great deal of support from a variety of individuals and organizations both at CWRU and CIA, “said Craig Lewis, CEO of Sprav Water. “We have made extensive use of the 3D printing capabilities of think[box] at CWRU to help us quickly prototype designs. We also took advantage of several joint CWRU and CIA product competitions as well as the Blackstone Launchpad program. We are very fortunate to be located in an area where technical and creative resources can easily come together to create new businesses and potential jobs.”

    Project backers can donate to the campaign by going to (http://kck.st/19QVpBg) and they will receive a device in their choice of either chrome or satin nickel finish for $49 or $59 respectively. The first units will be shipped April 2014 to project backers, and eventually the meters will be available for purchase online at http://www.spravwater.com and at plumbing and hardware retailers nationwide.

    About Sprav Water
    Sprav Water LLC, is launching a smart water meter that allows users to monitor, in real time, shower water and energy usage. The device reduces water waste and energy consumption.

    More conservation coverage here.

    COGCC rule-making is on the agenda for the December 16-17 meeting: Tightened spill reporting?

    November 5, 2013
    Spill via Princess Sparkle Pony's Photo Blog

    Spill via Princess Sparkle Pony’s Photo Blog

    From The Grand Junction Daily Sentinel (Dennis Webb):

    Colorado’s oil and gas regulators next month will consider tightening spill reporting rules by going beyond what’s required under a newly passed state law. The Colorado Oil and Gas Conservation Commission rulemaking is slated for its Dec. 16-17 meeting. It was prompted by the need to implement legislation introduced by state Rep. Diane Mitsch Bush, D-Steamboat Springs, requiring companies to report within 24 hours exploration and production waste spills of more than one barrel (42 gallons) if they are outside berms or other secondary containment.

    The current rule requires 24-hour reporting in the case of all spills of more than 20 barrels, and within 10 days for spills of five barrels or more. Immediate reporting is required for spills of any size that impact or threaten to impact any waters of the state, occupied structure, livestock or public byway. A draft proposal by oil and gas commission staff would eliminate the 20-barrel reference and would require reporting within 24 hours for all spills of five barrels or more, regardless of whether confined within berms or other containment.

    The Colorado Oil and Gas Association has proposed keeping the 20-barrel and five-barrel reporting requirements as they are in the case of spills within contained areas.

    The Colorado Department of Public Health and Environment is endorsing the proposal for more rapid reporting of all spills over five barrels, said the health department’s oil and gas liaison, Kent Kuster, in written comments to the commission. Otherwise, spills as large as 840 gallons may not be reported in a timely manner, he wrote.

    “The majority of well pads are not designed to contain fluids and may contain areas where fill has been used. These fill areas may allow contaminated fluids to move quickly through the soil resulting in greater groundwater contamination,” he wrote.

    He said the proposal to require 24-hour reporting for all spills larger than five barrels would result in “increasing the attention to spills and releases and potentially minimizing the impact to ground water.”

    Colorado Oil and Gas Conservation Commission Director Matt Lepore said during a recent stakeholder meeting on the rulemaking that one point of the agency’s draft proposal is to simplify the rules by reducing the number of reporting thresholds. But he said there’s also concern about the fact that “20 barrels is a fairly sizable release, approaching a thousand gallons.”

    While secondary containment prevents lateral spreads of spills, it doesn’t necessarily prevent downward migration, depending on how it’s constructed, and even a 200-gallon spill can be of concern, he said.

    While the commission hasn’t yet changed its rules, the new law took effect Aug. 7 and companies have been expected to comply with it.

    Kirby Wynn, Garfield County’s oil and gas liaison, told county commissioners Monday that he has been receiving reports since then as required. He said that in his experience there has never been a case where a company hasn’t alerted him to a meaningful spill.

    Garfield County will be preparing its own comments on the commission’s proposal.

    Meanwhile, a presentation Wynn provided to commissioners shows that in the county, there’s been a gradual reduction in spills outside containment since 2008 and a corresponding drop in the percentage of spills affecting ground or surface water. The commission overhauled its rules in 2008, including tightening them for when containment is required around tanks. The county had 116 reported spills in 2008, rising to 140 by 2010, and declining to 59 last year and 65 so far this year. But spills outside containment numbered 64 in 2008 and just 21 last year. Spills affecting surface or groundwater steadily declined from 15 percent in 2008 to 3 percent last year.

    “There’s a lot more containment now” than there was before 2008, Wynn said.

    The commission has said that last year about 400 spills were reported statewide, including 66 cases where ground or surface water remediation was required.

    More oil and gas coverage here and here.

    DBJ Special Report: The fracking debate

    November 4, 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 Denver Business Journal’s special report page for hydraulic fracturing. Here’s the introduction:

    Hydraulic fracturing, or “fracking” — a practice widely used in the energy-rich West to extract natural gas from deep underground — has triggered controversy between the oil and gas industry and environmentalists.

    Fracking refers to injecting a mixture of water, sand and chemicals into rock at high pressure, fracturing the rock and creating or extending channels for gas to escape that might otherwise remain trapped.

    Some contend that the chemicals used in fracking can contaminate underground drinking-water supplies. The industry has long argued the practice is safe.

    The Denver Business Journal has been covering the debate over fracking and efforts to increase regulation and disclosure of chemicals used.

    Here are recent highlights of the DBJ’s coverage in print and online, most of it by DBJ energy and environment reporter Cathy Proctor.

    Most recent articles appear first. (Articles that appeared in the last month in the print edition are accessible to subscribers only.)

    More oil and gas coverage here and here.

    Weld County environmental groups hope to influence tougher air pollution rules for oil and gas

    October 31, 2013
    DJ Basin Exploration via the Oil and Gas Journal

    DJ Basin Exploration via the Oil and Gas Journal

    From The Greeley Tribune (Sharon Dunn):

    Some environmental groups are gearing up for a fight against proposed changes to emissions regulations on the oil and gas industry.

    Weld Air and Water and the Colorado Progressive Coalition issued press releases this week citing concerns that the proposed changes to emissions regulations in the state don’t go far enough to regulate the oil and gas industry.

    But state officials at the Colorado Air Pollution Control Division say no formal draft rules will be released until November and they will not comment on the draft until then. The division in the last few months has sought comment from those involved based on a loose draft set of rules forwarded to “stakeholders.”

    The division will issue a formal draft, taking into account suggestions from those stakeholders, in November, with a rule-making process to begin in February, said Christopher Dann, spokesman for the Air Pollution Control Division at the Colorado Department of Public Health and Environment.

    The environmental groups, however, have already sharpened their pencils for a revamp.

    “The new regulations (Gov. John) Hickenlooper’s team is recommending will continue to allow significant amounts of methane to escape into Coloradoan’s air,” Progress Now’s Joe Boven stated in a news release this week. “A recent study found that air pollution is a stronger environmental cause of cancer than second-hand smoke, yet while eliminating smoking from public facilities has gained momentum, this proposal would reduce many regulations for oil and gas emissions.”

    Weld Air and Water members wrote they were “bitterly disappointed” at the proposed language in the rules.

    “This proposal fails to solve any of our state’s pressing air quality problems,” said Matt Sura, an attorney who is representing communities in the rule-making process, in a news release. “These regulations do nothing to address the threat of toxic emissions of oil and gas facilities that are near homes. The proposed regulations will also be ineffective at bringing down dangerous levels of smog and ozone on the Front Range, and do little to reduce methane emissions that contribute to climate change.”

    Current rules regarding emissions control are tailored around reducing emissions so that 90 percent are controlled; the rules contain extensive documentation of emissions control equipment. The new rules will implement new Environmental Protection Agency rules.

    “State and federal air quality laws do not currently require formal self-inspections to the degree that the state is going to propose,” said Will Allison, director of the Air Pollution Control Division, in an e-mail response to questions. “For example, the use of infrared cameras is an emerging technology that improves upon existing inspection methods. The proposal will include a statewide leak inspection and repair program to further reduce emissions and complement the existing inspection framework. The proposal will be one of the first of its kind in the country, and will significantly strengthen existing rules.”

    Doug Flanders, of the Colorado Oil and Gas Association, said Colorado has some of the toughest regulations on the industry throughout the country.

    “Common sense and innovative standards are necessary to control air pollution, which is exactly why the new EPA rules, which CDPHE’s air rulemaking will implement, are based on Colorado existing rules and regulations,” Flanders wrote in an email. “As we have found in Colorado, there are positive aspects of the draft rule that promote conservation through the capture of natural gas and the resulting emissions reductions, and while methane is not considered an ozone precursor, it is captured by these devices as well.”

    The environmental groups say the draft language would only weaken existing state law because they require inspections of tanks, based on their sizes, quarterly to annually. The groups say they will advocate for monthly inspections instead.

    Emission controls on oil and gas companies have been in existence for the last decade in the state, updated every few years with more restrictions, but required storage tank inspections haven’t yet been a part of the mix. Operators are required to weekly inspect their emissions control equipment, according to the existing rules.

    The environmental groups say they will seek more frequent inspections, quicker turnarounds on required repairs, and greater emissions control standards for wells within a quarter mile of homes and schools.

    More oil and gas coverage here and here.

    The Atlantic: A 200,000-mile ‘canyon of fire’ erupts through the atmosphere of the sun

    October 28, 2013

    WRA report — Conservation Synergy: The Case for Integrating Water and Energy Efficiency Programs

    October 25, 2013


    Click here to download the report. Click here for the executive summary. Here’s an excerpt:

    The nexus between water and energy has been understood for several years, yet only a handful of utilities have fully capitalized on this knowledge by combining their efficiency programs.

    There are many inter-connections between water, electricity, and natural gas: Significant amounts of water are used for cooling during electricity gen- eration, and significant amounts of electricity and natural gas are used to pump, treat, and heat water for use in homes and businesses. Thus, when one resource is conserved, so is another.

    Utilities that have collaborated — a few of which are profiled here — have overwhelmingly found such programs to be a good business decision. The benefits are manifold: higher participation rates, increased customer satisfaction, coordinated and complementary program design, and an improved reputation from working smarter — not harder.

    More energy policy coverage here.

    Lincoln Park/Cotter Mill superfund cleanup: Cotter wants to reduce the frequency of groundwater monitoring

    October 23, 2013
    Lincoln Park/Cotter Mill Site via The Denver Post

    Lincoln Park/Cotter Mill Site via The Denver Post

    From The Pueblo Chieftain (Tracy Harmon):

    Public comment is being sought on a Cotter Corp. uranium mill proposal seeking to reduce the frequency of groundwater monitoring on 11 new wells. The state health department has preliminarily approved the request and will take public input before making a final decision. Cotter Corp. Mill Manager John Hamrick indicated more than a year’s worth of sampling has been amassed on 11 new wells, which were dug in late 2011 to help establish the extent of groundwater contamination.

    “Once we’ve established 12 months of measurements, we generally move to quarterly sampling as we do with all the other wells,” Hamrick explained.

    The mill and a portion of the neighboring Lincoln Park community have been an EPA Superfund site since 1988 due to uranium and molybdenum contamination in groundwater and soils. Groundwater is not used by residents in the contaminated area of Lincoln Park as they all have been connected to the city water supply.

    Hamrick said the average uranium value for each of the new monitoring wells is below the Colorado Groundwater Quality Standard. Only three wells have exceeded the standard for uranium — one six times, another twice and the third just once.

    The average molybdenum concentration for most of the new wells also was below the state standard and only three wells have exceeded that standard out of 115 samples.

    The state health department reviewed the request as did the Cotter Community Advisory Group. Regulators feel, “Significant baseline data” has been collected to allow for quarterly monitoring instead of monthly, said Jennifer Opila, unit leader for the state heath department’s radioactive materials division.

    Public comment will be accepted Monday through Sept. 13. Comments can be sent to Warren Smith, community involvement manager, via email at warren.smith@state.co.us or by calling 303-692-3373.

    More Lincoln Park/Cotter Mill coverage here and here.

    Greeley’s wastewater treatment plant wins awards for energy efficiency

    October 22, 2013
    Wastewater Treatment Process

    Wastewater Treatment Process

    Here’s the release from the City of Greeley:

    Greeley’s Water Pollution Control Facility (WPCF) recently received statewide recognition for sustainability and energy reduction from the Colorado Environmental Leadership Program and the Colorado Industrial Energy Challenge. The awards ceremonies occurred on October 17 in Denver.

    For its energy reduction programs, the WPCF received the Partner of the Year award from the Colorado Industrial Energy Challenge (CIEC). The wastewater plant reduced energy use from 2011-2012 by 11.5 percent. Greeley received the top honor and only six other organizations were recognized. The program acknowledges achievements in energy efficiency for large industrial facilities with more than $300,000 in annual energy costs.

    The second award is from the Colorado Environmental Leadership Program (CELP).The WPCF received a Bronze Award for its efforts to reduce energy use at the wastewater treatment plant. The CELP is a voluntary program that encourages and rewards superior environmental performers that go beyond the requirements of environmental regulations and move toward the goal of sustainability.

    The WPCF has recently implemented several projects that have contributed to the decrease of energy use. The 2011 installation of high-speed turbo blowers improved aeration at the plant, increased energy efficiency, and lowered energy costs. In 2012, 2,106 solar panels were installed making it the largest solar farm in Weld County. Greeley’s Water and Sewer Department will continue to find ways to make the WPCF and other facilities more energy and cost efficient.

    Greeley recently scored some grant money from the state. Here’s the release from the City of Greeley:

    Gov. John Hicklooper announced today that 21 municipal wastewater and sanitation districts throughout Colorado will receive a total of $14.7 million in state grants to help with the planning, design and construction of facility improvements to meet new nutrient standards. The City of Greeley’s Water Pollution Control Facility will receive a total of $80,000 for planning and $1 million for design and construction.

    “Greeley is in the forefront of water quality and water management. This grant simply helps the City do its job with less cost to residents,” stated Greeley Mayor Tom Norton.

    Excessive nutrients harm water bodies by stimulating algae blooms that consume oxygen, kill aquatic organisms and ultimately lead to smaller populations of game and fish. While nutrients are naturally occurring, other contributors include human sewage, emissions from power generators and automobiles, lawn fertilizers and pet waste.

    “Coloradoans in rural and urban areas will benefit from these new water standards that improve and protect our water,” Hickenlooper said. “This grant funding will help communities offset the costs of bringing their systems into compliance. In addition, the grants announced today will help ensure safe and healthy water for wildlife, agriculture, recreation and drinking water purposes.”

    The state’s Water Quality Control Commission adopted new standards in September 2012 to help prevent harmful nutrients, such as nitrogen and phosphorus, from reaching state waters. The new regulation requires certain larger domestic wastewater treatment facilities to meet effluent limits for nutrients.

    The Nutrient Grant Program will help wastewater facilities with the costs of planning for, designing and implementing system improvements. Funding for the program was made available through HB13-1191 “Nutrient Grant Domestic Wastewater Treatment Plant,” sponsored by Reps. Randy Fischer and Ed Vigil and Sens. Gail Schwartz and Angela Giron.

    There are about 400 municipal wastewater systems in Colorado. The new nutrient standards apply to about 40 systems and will have the greatest impact on the waters of the state.

    More wastewater coverage here and here.

    School of Mines 33rd Oil Shale Symposium recap

    October 21, 2013
    Map of oil shale and tar sands in Colorado, Utah and Wyoming -- via the BLM

    Map of oil shale and tar sands in Colorado, Utah and Wyoming — via the BLM

    From The Grand Junction Daily Sentinel (Gary Harmon):

    It could require less than half a barrel of water to buoy up a barrel of oil from the high desert of the west, Shell Oil Co. said. One barrel of oil could be produced from oil shale for as little as a third of a barrel of water, Tom Fowler, commercial lead for the Shell project, said at the 33rd Oil Shale symposium at Colorado School of Mines.

    Water use has long been a point of contention in the running battle over the development of oil shale.

    Shell’s announcement comes on the heels of its decision to shift assets away from oil shale in northwest Colorado to other assets, among them a $12.5 billion shale-to-gas plant in Louisiana.

    “We were laser-focused on water,” and the techniques refined in Colorado “translate very well to other places, I’m specifically thinking of Jordan, where they also are very concerned about their water, Fowler said.

    Shell’s new estimates are based on a project producing 50,000 barrels of oil per day.

    One major factor in Shell’s reduction in anticipated water use was to switch from water cooling to air cooling, especially in the power-generation part of the process. Power is needed to heat the rock to about 700 degrees Fahrenheit to free kerogen from the rock. Vaporized kerogen condenses into crude oil that can be recovered.

    Shell also reduced its estimates of water use by targeting the deepest, though not richest, layers of oil shale, Fowler said. By recovering oil from the deepest layers, which lie beneath groundwater, the company eliminated any need to steam-strip the area from which it removed kerogen. That, combined with other efforts to reduce and better manage water, could reduce the ratio of water to oil to 0.3 barrels of water to 1 barrel of oil. It also would leave the richest layers of shale still available for development with more refined techniques in the future, Fowler said. Shell’s estimates include domestic water and usage for reclamation and other purposes.

    The most kerogen-rich oil shale in the world sits in northwest Colorado, under thousands of feet of overburden and Shell’s departure leaves one company pursuing development of shale in place, with little surface disturbance.

    Two companies, Enefit American Oil and Red leaf Resources, are mining more shallow resources in Utah and heating them to recover oil.

    Shell’s estimates don’t apply to those techniques, but Enefit American Oil says its methods will require between one and three barrels of water per barrel of oil, with the likely outcome closer to the lower end.

    Opponents of oil shale development frequently cite a Government Accountability Office report, widely panned by industry officials, citing water needs at seven barrels per barrel of oil produced.

    More oil shale coverage here via Gary Harmon writing for The Grand Junction Daily Sentinel:

    While oil shale development in the United States suffered a blow when Shell Oil announced it was pulling out of its much-touted Mahogany project, other nations are encouraging industry development. Genie Energy, which is still moving ahead on its project in northwest Colorado, has a new project in Mongolia. Irati Energy, based in Canada, is moving ahead on a pilot oil shale project in Brazil. Enefit American Oil, a subsidiary of Eesti Energia, the world’s largest oil shale company, also has a concession, or lease, in Jordan, to produce electricity and oil from shale deposits there.

    And while Shell pulled out of Colorado, it didn’t pull out of oil shale. The international energy giant still is working on an oil shale project in Jordan, despite abandoning its plans to produce oil from shale in the Colorado portion of the Green River formation.

    China, Morocco and other countries are seeing development of their oil shale deposits, as well.

    Northwest Colorado, the focal point of the richest, thickest deposits of oil shale in the world, however, is seeing no new interest in its deposit even as Enefit American Oil is working to produce oil from shale in neighboring Utah.

    David Argyle organized Irati Energy to begin work on the Brazil project and he’s on the lookout for new resources. He’s not looking immediately at the U.S., however.

    “We don’t have the time or patience” to work through the regulatory issues facing oil shale development in the United States, Argyle said, noting that he doesn’t reject development in the United States out of hand.

    The industry, however, has to overcome emotional opposition, despite having a good environmental record, Argyle said.

    “In Brazil, we’re getting quietly on with it. In Israel, they’re getting quietly on with it,” Argyle said of oil shale development.

    Boom-bust cycles aren’t a major issue because the Brazil project anticipates a 200-year lifespan, Argyle said.

    Another project in Brazil has a 300-year lifespan, he said.

    The development around the world demonstrates that “oil shale has a global footprint” that is growing, Argyle said. That footprint expanded into Mongolia by accident, said Claude Pupkin, Genie Energy CEO. Genie Energy sent a geologist to Mongolia on an unrelated mission and he stumbled on a “world class,” previously unrecognized oil shale deposit, Pupkin said.

    “We’ll do a pilot project that is smaller than AMSO,” Pupkin said, referring to the American Shale Oil project in Colorado.

    In both cases, the projects will be in-situ, meaning that there will be little surface disturbance. Genie obtained commercial production rights and is working with the government in Mongolia to establish a regulatory system for development, Pupkin said.

    Colorado’s deep oil shale deposits don’t fit with the retorting technology developed in Estonia, Enefit American Oil CEO Rikki Hrenko said.

    Update: From The Grand Junction Daily Sentinel (Gary Harmon):

    With the shadow of Nazi occupation looming over the country, Sweden turned to oil shale in 1940.

    “Oil shale got the Swedish economy through World War II,” Dr. Harold Vinegar said.

    Vinegar outlined for the Oil Shale Symposium at Colorado School of Mines last week how Sweden exploited a low-grade oil shale deposit near the town of Kvantorp, using an in-situ process that bore a striking resemblance to the in-situ process Shell Oil Co. was pursuing in northwest Colorado. Vinegar is an oil and energy scientist who spent more than 30 years with Shell.

    The Swedes already were mining the same oil shale deposit when they became frustrated by the cost and difficulty of digging to reach the shale they retorted to produce oil, Vinegar said.

    Fredrick Ljungstrom came up with the idea of heating the shale in place and leaving the soil above it undisturbed. Ljungstrom drove heating elements in a closely spaced hexagonal pattern down into the shale and sunk a collection well in the center.

    The heaters and wells were shallow, in the tens of feet instead of the thousands of feet below the surface in the Piceance Basin.

    Making the project more difficult was the lack of electricity. Ljunsgstrom could only get electricity to heat the shale four months of the year, during the spring runoff, when hydroelectric power was available, Vinegar said.

    During those months, Ljungstrom used a mobile transformer to direct power into the cells he was using at any given time to heat the rock to 400 degrees Fahrenheit.

    “It really was a brilliant idea,” Vinegar said.

    And it worked.

    The Ljungstrom process produced 90,000 barrels of oil from 1942 to 1945 and 1.5 million barrels during its production life that ended in 1959. The oil produced from Ljungstrom’s in-situ process was lighter and cleaner than the oil produced from the retort process on the same deposit, Vinegar said. Groundwater beneath the deposit was protected by an impermeable clay layer that prevented contamination, Vinegar said.

    In addition to inventing what is known as the Ljungstrom process for oil shale, Ljungstrom was also a co-inventor, with his brother, of high-pressure steam boilers, steam turbines and steam locomotives.

    He also was a sailing innovator and the Ljungstrom rig — an arrangement of sails — is named for him.

    The land he used to produce oil from shale over the years has changed.

    “The area revegetated naturally,” Vinegar said. “It’s now a park where the in-situ process was run.”

    More oil shale coverage here and here.

    A review of flooding impacts on the oil patch is underway #COflood

    October 20, 2013

    Flooded well site September 2013 -- Denver Post

    Flooded well site September 2013 — Denver Post

    From The Grand Junction Daily Sentinel (Dennis Webb):

    After last month’s Front Range flooding tore through oil and gas facilities, causing some tanks to leak and even become unmoored, employees with the energy producer Encana noticed an interesting trend. Although Encana’s tanks were damaged, the company didn’t experience the kind of damage that some other companies did from trees falling on tanks or being swept into them. As it happens, Encana spokesman Doug Hock said, the company typically fences in well pads where it operates in the flooded area because its operations there tend to be in more densely populated areas. While the fences weren’t installed for flooding purposes, they ended up helping keep out debris.

    “It was kind of an ah-ha, light-bulb moment to say, going forward we should do this because it helped protect those pads,” Hock said.

    As the energy industry continues cleaning up after the flooding and bringing wells back on line, companies, regulators and environmental advocates are all looking increasingly at what lessons can be learned from the disaster — what went wrong, what went right, and what can be done to reduce problems in the case of future flooding. Eventually, this consideration will likely turn to what possibly should be required of the industry in the future, including in terms of floodplain and riparian regulations.

    “I’d like to see us get a stakeholder group together to evaluate and assess the floods and also see what worked, what didn’t work, what we can make better” in terms of oil and gas operations, said state Rep. Diane Mitsch Bush, a Steamboat Springs Democrat who earlier this year got legislation passed tightening oil and gas spill reporting requirements.

    Alan Gilbert, special assistant for flood response to state Department of Natural Resources Executive Director Mike King, said while it’s still early, the department and Colorado Oil and Gas Conservation Commission staff are evaluating how things went during the flood and what can be improved in the future, including possibly through new regulations.

    “We take that very seriously. We think that’s true, we should do that and that’s what we will do,” he said.


    Photos of floating tanks and reports of leaks alarmed Front Range residents concerned about oil and gas drilling there. U.S. Rep. Jared Polis, D-Boulder, who shares some residents’ general concerns over drilling, called in late September for a congressional hearing on the flood-induced oil and gas damage.

    “Congress must deal with this issue to ensure that natural disasters do not also become public health disasters,” he said in announcing that request.

    More recently, though, state health officials reported no evidence of pollutants from oil and gas spills in rivers and streams affected by flooding, even as it found in some areas high levels of E. coli from sewage contamination. That contamination amounted to many millions of gallons, whereas as of Friday 47,106 gallons of oil and 28,149 gallons of produced water from drilling were reported spilled.

    Gilbert voiced some relief over no single catastrophic release or cumulative collection of spilled oil or other contaminants being found so far.

    “It’s an emergency and a tragedy and a terrible situation but this aspect of it is on the side where we are grateful for less rather than more contamination and releases,” he said.

    Although the sheer volume of floodwaters heavily diluted what spills occurred, oil and gas activist Dave Devanney of Battlement Mesa said he shares the concerns of Front Range residents about what happened there.

    “Any time you have volatile organic compounds and … chemicals in the waterways, that’s an issue. No matter how much it’s diluted it’s still there, and I think it’s something that the oil and gas conservation commission should be taking a look at and ensuring that there’s adequate protections for future oil and gas development at or near water sources.”

    He noted last winter’s natural gas liquids leak from a pipeline leaving a Williams gas processing plant outside Parachute. Contamination reached Parachute Creek and threatened the Colorado River.

    “We don’t want to see that happen again,” he said.


    Devanney believes preventing such problems means having the oil and gas commission take up the issue of riparian setbacks, which were unfinished business from its comprehensive 2008 rules rewrite, except for setbacks it established to protect municipal water supplies.

    “The events of the last few weeks on the Front Range demonstrate that it’s an important topic that needs to be addressed sooner rather than later,” Devanney said.

    Pete Maysmith, executive director of Conservation Colorado, agrees.

    “I mean, this is just an unfinished topic of conversation,” he said. “… If this isn’t a wake-up call to take a look at those issues I don’t know what would be.”

    Noble Energy, which like Encana also has operations in western Colorado’s Piceance Basin, reported four floodwater-related releases totaling about 9,000 gallons. But it also points to several things it believes minimized flood-related damage, including proactive emergency response training of more than 150 workers on the Front Range, and automatic technology that let it shut in 85 percent of its wells remotely, with almost all the rest being manually shut in by the time the water reached flood level.

    “Overall, our equipment held up amazingly well and was a testament to our engineering and facility design,” the company said in an emailed response to inquiries for this story.

    “… We believe we can successfully operate in the flood plain, as proven by this event. We are in the process of evaluating our operations in and around flood plains, and we’re working with the state of Colorado and all stakeholders on how we can improve future preparedness. We will use lessons learned to create new best management practices in those areas.”


    Gilbert said the industry’s proactive effort to shut in wells ahead of the flooding, oftentimes through automated means, was a significant action because it was designed to ensure fluids aren’t moving up wells if the wells are damaged.

    Of note was that damage to wells in general was relatively slight compared to the more significant tank damage that occurred, he said. And like Encana, the state has noticed the extra protection that metal fences or berms seemed to provide to tanks and other infrastructure.

    “We will take a look at that in more detail and talk to everybody to find what their experiences were as well with that,” he said.

    He said something else of note applied to tank batteries in wetlands. State rules require them to be tied down, but companies do so in different ways, some “relatively flimsy,” he said.

    “We have noticed some of those ways have held better than others,” he said.

    The degree to which it will be left to companies to apply lessons learned as they see fit, as opposed to being required to do so by state rules, is likely to be one of the decisions oil and gas regulators will be left to make.

    “Why wouldn’t we require best practices? Why shouldn’t we hold the oil and gas industry to the highest possible standard?” Conservation Colorado’s Maysmith said. “I think the answer is, we should.”

    Maysmith also has been critical of the state for not requiring rather than requesting information from the industry pertaining to the status of facilities potentially impacted by flooding. But Gilbert said it hasn’t mattered whether the state asked or required: “The industry is giving us the information we’re asking for.”


    Mitsch Bush, who sits on the House Agriculture, Livestock and Natural Resources Committee, credited both the oil and gas commission staff and the industry for their post-flooding responses, and said it’s still too soon to know what regulatory or other changes should occur due to what the flooding has taught the state.

    “I don’t want to be jumping to any conclusions. … Let’s get all the input from all the sides on what happened and get some technical assessment from (the Colorado Department of Public Health and Environment) and COGCC and really understand the impacts,” she said.

    The flooding only added to the highly contentious debate over oil and gas development on the Front Range, but Encana’s Hock believes a lot of the more strident voices critical of the industry as it pertains to flood impacts “are opposed to oil and gas whether there’s a flood or not. So that really didn’t change anything.”

    For Maysmith, things such as the flooding and the Parachute Creek contamination demonstrate the need to protect an important natural resource in the West.

    “We’ve got to be asking ourselves, are we doing all we can to protect our water sources?” he said.

    He worries when he sees well pads close to creeks, and knows tanks can be knocked over or other things can cause leaks and benzene and other toxic substances to reach waterways.

    “That says we have a problem. That says we don’t have this figured out,” he said.

    From The Grand Junction Daily Sentinel (Dennis Webb):

    While ruptured oil and gas infrastructure was part of the problem when it came to the recent Front Range flooding, the energy industry also was part of the solution in terms of providing flood relief. Companies have contributed more than $2 million to American Red Cross relief efforts. Some of the donations initially were prompted by a $500,000 contribution by Noble Energy, a major Front Range oil and gas developer that also has operations in Garfield County. Noble challenged other Colorado Oil & Gas Association members to match its gift and raise a total of $1 million, an amount that now has been more than doubled.

    At last report, donations by COGA members had reached about $2.15 million. That doesn’t include donations from company employees or company matches for those donations. It also doesn’t include relief-related contributions from companies who are not members of COGA, such as Encana, which contributed $250,000 to local United Way entities and other organizations assisting in relief. Some of the COGA-member contributors with Western Slope operations include Chevron ($250,000), ConocoPhillips ($200,000), Whiting Petroleum ($100,000), Bill Barrett Corp. ($25,000), Marathon Oil Co. ($10,000), Calfrac ($5,000) and Black Hills Exploration and Production ($2,500). Utility Xcel Energy gave $50,000.

    “Their members have been a very generous supporter of our flood relief as well as donating to our general disaster relief over the last month,” said Patricia Billinger, spokeswoman for the American Red Cross of Colorado.

    She said her organization’s flood-relief costs alone at this point are around $7 million, and it has received flood-designated donations of about $4 million. But general-relief donations also have helped enable the organization to respond to continuing other needs such as families left homeless by house fires.

    “The recovery process is going to be long, and for some, very difficult,” Michael DeBerry, area manager for a business unit of Chevron U.S.A. Inc., a Chevron subsidiary with operations in Colorado, said in a news release. “We want the people who have been affected by these devastating storms to know that they are in our hearts. With longstanding ties to Colorado, we hope this donation eases the hardship.”

    COGA has said that in cases in which companies’ personnel and equipment could be freed up, they were made available for rescue and relief efforts, such as by providing pumps, trucks and earth-moving equipment to affected communities.

    Noble says its employees bought and delivered 14 truck- and SUV-loads of relief supplies for one shelter, and served meals three times a day for five days at shelters in Greeley and Evans, and 60 of its workers processed and sorted 57,000 pounds of food in a day for the Weld County Food Bank. The company and a contractor also provided 200 portable toilets in Evans, where a no-flush rule was in effect.

    The company also has matched $40,000 in employee donations.

    “We have 450 employees who live and work in the Greeley area, where we have operated more than 30 years — we are committed for the long-term,” Noble said in a prepared statement.

    More oil and gas coverage here and here.

    Only a small amount of water used for hydraulic fracturing in northern Colorado is recycled

    October 20, 2013
    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates

    From the Northern Colorado Business Report (Steve Lynn):

    In Northern Colorado, estimates have put water recycling levels at just 2 percent of water used for fracking.

    Noble Energy Inc. (NYSE: NBL), for example, has recycled about 2 percent of its water so far this year, or 600,000 barrels, said Adam Prior, technical water specialist for the company. Noble Energy, one of the largest oil companies in Northern Colorado, is working with CSU to improve its water recycling capabilities, but most of its water still comes from water wells and ponds.

    “It’s not economical right now,” Prior told an audience at the 2013 Natural Gas Symposium on Wednesday. The CSU event drew hundreds of people from the oil and gas industry, environmentalists and students.

    Prior was one of three panelists who spoke about the barriers to water recycling in the Denver-Julesburg Basin, which includes Northern Colorado. The low cost of fresh water, prevalence of wells used by companies to dispose of used fracking to dispose of used fracking water, recycling infrastructure challenges and a lack of regulations have led to lower water-recycling levels in the region, panelists said…

    Noble has improved its water-recycling program since 2011, when all of its water came from cities. Today, about 80 percent of Noble Energy’s water comes from ponds and wells, 18 percent comes from cities and 2 percent is recycled…

    Increased water recycling by companies can improve people’s opinion of oil and gas companies, said David Ellerbroek, vice president of MWH Global, an engineering company focused on water.

    More oil and gas coverage here and here.

    Colorado Foundation for Water Education Energy Tour November 8

    October 20, 2013

    Directional drilling from one well site via the National Forest Service

    Directional drilling from one well site via the National Forest Service

    Click here for the pitch.

    Wastewater: Greeley’s Water Pollution Control Facility reduced energy use by 11.5% from 2011-2012 — Greeley Water

    October 16, 2013

    ‘Worldwide production of oil shale has nearly doubled in the last six years’ — Jeremy Boak

    October 16, 2013
    Map of oil shale and tar sands in Colorado, Utah and Wyoming -- via the BLM

    Map of oil shale and tar sands in Colorado, Utah and Wyoming — via the BLM

    From The Grand Junction Daily Sentinel (Gary Harmon):

    Reports of the death of the oil shale industry are grossly exaggerated, a Colorado School of Mines expert said.

    Oil shale “is no longer in its infancy,” Jeremy Boak, director of the Center for Oil Shale Technology and Research at Mines, said during the opening of the 33rd annual Oil Shale Symposium here. “It might be in its rambunctious adolescence.”

    Worldwide production from oil shale has nearly doubled in the last six years from 18,000 barrels per day of crude oil from oil shale to 35,000 barrels per day, Boak said.

    The states of Colorado, Utah and Wyoming contain the richest deposits of oil shale in the world. The deposits of northwest Colorado are the most significant of them.

    Shell Oil, however, this year announced it was pulling out of its Mahogany Project in Rio Blanco County, citing increased risk and competition. Shell was working on producing oil from deeply buried oil shale with little surface disturbance. Even though it is ceasing its Colorado operations, Shell is continuing to work in Jordan on a project, Boak said.

    Other energy giants, such as Petrobras in Brazil, and Total in France, are continuing to work on oil shale production.

    Planned projects and others in the works could account for production increases of as much as 10 percent over the next five to 10 years, Boak said.

    Though critics have questioned the amount of water an industry would use, “I think we’ve got a perfectly good estimate of water use,” about 0.4 percent of the water used annually in Colorado each year, Boak said.

    More oil shale coverage here and here.

    Big Thompson River: Twilight for the Idylwilde Dam #COflood

    October 9, 2013
    Idylwilde Dam via Loveland Water and Power

    Idylwilde Dam via Loveland Water and Power

    From the Loveland Reporter-Herald (Jessica Maher):

    In a resolution added to Tuesday’s special meeting of the Loveland City Council, councilors voted unanimously to authorize negotiations with Kiewit Corp., the contractor selected by the Colorado Department of Transportation for the U.S. 34 reconstruction project.

    The agreement will include demolishing and disposing of the Idylwilde Dam. The silt, sand, cobbles and boulders now located behind the dam would go to Kiewit for much-needed project material.

    Loveland Water and Power Director Steve Adams said he worked last week with the U.S. Army Corps of Engineers, the Federal Energy Regulatory Commission (FERC) and the U.S. Forest Service to fast track approvals needed to move forward with negotiations.

    “We felt like this is an opportunity that presents itself to us and we wanted to take advantage of it,” Adams said. “We feel like the dam has been compromised — it was compromised in its reconstruction by a quarter of it not being anchored to bedrock — and this was even more evidence to us that the dam should be removed for safety purposes and also to help the reconstruction effort.”[...]

    The Idylwilde Dam went online in 1925 and was at that time the power plant for the city. It generates about 900 kW, which is now a fraction of what Loveland Water and Power now produces, and the facility was used in recent years to help reduce the city’s costs when the Platte River Power Authority hit its peak demand.

    The dam area represents about 100,000 cubic yards that contractor could use to help reconstruct the highway, according to Adams, who said the city has been in contact with Kiewit Corp officials.

    From the Longmont Times-Call (Tony Kindelspire):

    Longmont homeowners will see an increase in their average monthly utility bills of about 12 1/2 percent starting Dec. 1, according to votes passed Tuesday night by the Longmont City Council. Primarily because of stormwater and parks and greenway maintenance fee increases, Longmont residents’ utility fees will soon be $153 a month, up from $136 a month. The Longmont City Council voted unanimously to increase stormwater fees to $13.60 a month, which is nearly double what was proposed by the city’s public works and natural resources department. That increase — ironically — included flood control measures on stretches of the St. Vrain River.

    Dale Rademacher, director of public works and natural resources, said the preliminary cost estimate of total damage to the river is about $80 million.

    Barbara McGrane, the business manager for the public works department, told council that the city originally had planned $470,000 in capital projects for 2014. Post-flood, that figure is now about $3.6 million, she said. Federal Emergency Management Agency funds will reimburse the city for a portion of the needed repairs, but how much remains to be seen, McGrane said.

    “We don’t really know yet what FEMA is going to want us to do with the river, but the riverbed repairs — big dollars,” McGrane said.

    From The Denver Post (Electa Draper):

    Garbage day after the Colorado floods is turning apocalyptic. The potential volume of flood debris is mind-blowing, given preliminary estimates of more than 1,800 homes destroyed and more than 16,000 damaged and full of soggy ruins.

    State regulators are working on waivers for safety and environmental standards at landfills so they can handle the toxic mounds of refuse heaped in city drop-off sites and piled in debris fields along creeks and rivers.

    Earlier this week, traffic leading to dumps, including two in Erie, was so heavy that haulers pulled out of long lines in frustration with wait times.

    “It’s been wild,” said Dan Gudgel, division manager for Waste Connections, which runs the Erie landfills. “We’ve had a tremendous amount of rain here — 15 to 20 inches — and we drive on soil. We struggled Monday, but now we’re going full-bore.”

    Heaps of ruined possessions are an immediate threat to public health, but they also are constant reminders of the disaster and are among the biggest obstacles to economic recovery and a restored sense of well-being, FEMA spokesman Jerry DeFelice said.

    “At the forefront of recovery is debris removal,” DeFelice said.

    FEMA reformed policies for helping communities with the high cost of cleanup after Hurricane Sandy, now offering reimbursement along a sliding scale for speedy removal — in excess of 75 percent of eligible costs.

    “The idea is to give communities incentives to plan for disaster cleanup,” DeFelice said.

    The Colorado counties so far eligible for this type of FEMA assistance are those hardest hit — Adams, Boulder, Larimer and Weld — among 17 flooded counties. The volume of refuse the cleanup will generate is impossible to estimate, Colorado Department of Public Health and Environment officials said.

    Waste Connections — which operates the adjacent Denver Regional and Front Range landfills in Erie — has sent out several hundred 30- to 40-cubic-yard roll-off trash containers to storm- wrecked communities. A half dozen other companies have placed hundreds more containers.

    The huge debris-filled bins are due back soon, perhaps at the end of this week, Gudgel said.

    “The order of magnitude here is unreal. I couldn’t begin to guess at an amount,” Gudgel said. “I worked back east, with debris from tornadoes and ice storms, but this is unbelievable.”

    It’s also impossible to determine the health risks of muck-coated possessions, including some contamination by raw sewage and now mold.

    Hard-hit homeowners vouch that the yuck factor is off the charts.

    “There are a lot of people who are going to be involved with this (cleanup),” said Roger Doka, CDPHE’s solid-waste permitting unit leader. “We are meeting with our water quality, hazardous waste and air pollution divisions and with local governments.”

    Flood-damaged furnishings and other possessions on private property are the responsibility of the property owner, said Colorado Office of Emergency Management spokeswoman Micki Trost.

    But with whole houses collapsed into waterways, propane tanks hissing down fast-moving creeks and unidentifiable objects bobbing along or deposited along stream banks, local governments aren’t sure when they’ll get on top of this mountain of debris.

    Larimer County hasn’t had a break in disaster-generated debris since the 2012 High Park fire, county

    Mark Taylor helps neighbors unload flood-damaged belongings Wednesday at a dump in Boulder, where residents started to clean up from last week’s massive flooding. (RJ Sangosti, T he Denver Post)
    recovery manager Suzanne Bassinger said. Residents there were given three years from the date of the fire’s containment, June 30, 2012, to remove charred materials from their properties. Fire debris has been washing down creeks for months in post-fire flooding previous to last week’s catastrophic flooding in northeastern Colorado.
    “We’ve never really had any let-up,” Bassinger said.

    In Boulder County, emergency managers are still focused on evacuating people and using resources to carve routes to stranded communities.

    “You are asking ‘the recovery question.’ We’re still trying to get our hands around that,” Boulder Office of Emergency Management spokesman Ben Pennymon said.

    Managers from different departments are beginning to form a team to coordinate cleanup, he said.

    But Boulder residents already are dumping around the clock into containers at 21 collection sites — even burying and surrounding them with trash. Crews are working around the clock to haul full containers away but are struggling to keep up.

    The state health department is working to develop waivers that will allow landfills to accept some amounts of typically prohibited materials, such as asbestos-contaminated construction debris, Doka said.

    “Every landfill has the right of refusal for materials,” Doka said. “But they all are positioning themselves to accept flood debris. I’ve contacted all of the landfills in the area to ask about air space — or how much room they have. They all say they have adequate space.”

    Yet it could turn out that some landfill operators will have to excavate additional cells, he said.

    Gudgel said the Erie landfills have room — including a new $2.5 million cell (a large hole for waste lined with clay and plastic and graded so fluids drain out). Work began on it earlier this summer and could be completed in a few weeks.

    The Erie landfills have a remaining life expectancy of 40 years, he said, and he doesn’t think the flooding will significantly diminish that.

    “We’ve got room,” Gudgel said.

    Water used for hydraulic fracturing poses treatment and disposal problems

    October 7, 2013
    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates

    From The National Geographic (Bill Chameides):

    …a paper published this week in the journal Environmental Science and Technology by Nathaniel Warner formerly of Duke University and colleagues focuses on another of those environmental costs: disposal of wastewater.

    Hydraulic fracturing, as the term implies, involves water — both at the front end with fracking fluid, the water-based chemical cocktail that is injected into the shale, and at the back end where there is flowback water and produced water.

    Flowback water (which literally “flows back” during the fracking process) is a mixture of fracking fluid and formation water (i.e., water rich in brine from the targeted shale gas-rich rock). Once the chemistry of the water coming out of the well resembles the rock formation rather than the fracking fluid, it is known as produced water and can continue to flow as long as a well is in operation…

    As a general rule, you would not want to take a shower much less drink flowback or formation water, nor would you want to just pour the stuff into a river or stream (although that has been known to happen, as described here and here). Fracking wastewater can contain massive amounts of brine (salts), toxic metals, and radioactivity. And so the gas companies have a problem: what to do with the stuff.

    Ideally, the water would be reused or recycled, eliminating the need for immediate disposal. And indeed there is a lot of that. In the Marcellus Shale gas country of Pennsylvania, for example, a large percentage of the water, in the vicinity of 70 percent, is currently reused. And methods to reuse more are being developed. Even so, that leaves a massive amount of toxic wastewater to be disposed of.

    One disposal route is injection into deep wells, and a good deal of flowback and produced water from the Marcellus Shale is transported to Ohio for just such a deep burial. But this method has its own problems — the injection process has the inconvenient habit of causing an earthquake every now and again.

    Another alternative is waste treatment: removing the contaminants and then dumping the“clean” water into a nearby sewer or river. But you can’t use a standard municipal water treatment plant to treat flowback and produced water as those facilities are just not designed to handle the level of contamination, especially radioactivity, found in these waters.

    But there are so-called brine treatment plants that are at least in principle equipped to handle that level of contamination. Although they’ve been in use for quite some time to treat water from conventional oil and gas operations, many facilities of this type have been found lacking and some have even incurred fines for failure to meet Clean Water Act or other regulatory standards.

    More oil and gas coverage here and here.

    Colorado River Basin: Water shortages on the horizon? #ColoradoRiver

    October 7, 2013
    Colorado River Basin including out of basin demands -- Graphic/USBR

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

    From MSN.com (Bob Berwyn):

    “The bottom line is, the [2007 shortage sharing agreements] were major progress — people could agree on reservoir levels where things are out of the normal, and we’ve hit that,” [Eric] Kuhn told MSN News. With the overall climate picture shading toward drier conditions, water managers need to be very cautious in planning for the next few years and beyond, he added.

    In a July 1 memo that outlines what the looming shortages could mean for the region, Kuhn wrote that several more dry years would lead to even greater cuts in water deliveries to the arid Southwest. He said there also would be huge impacts to hydropower generation at the Hoover Dam, on the border of Arizona and Nevada.

    More Colorado River Basin coverage here and here.

    Chaffee County green-lights geothermal 1041 regulations

    October 6, 2013
    Geothermal Electrical Generation concept -- via the British Geological Survey

    Geothermal Electrical Generation concept — via the British Geological Survey

    From The Mountain Mail (James Redmond):

    Chaffee County commissioners passed a resolution approving the county’s new geothermal 1041 regulations and lifting the moratorium on geothermal development in the county during their meeting Tuesday. The county commissioners heard and incorporated comments from Chaffee County attorney Jenny Davis on the proposed geothermal 1041 regulations. Her recommendations changed some of the recommendations made to county commissioners by the Chaffee County Planning Commission.

    In July the planning commissioners asked the county commissioners to postpone any decision on their draft 1041 regulations for “Use of Geothermal Resources for the Commercial Production of Electricity.”

    At the county commissioners’ Sept. 3 hearing on the proposed 1041 regulations, commissioners instructed staff members to incorporate most of the Chaffee County Planning Commission recommendations.

    The Planning Commission had recommended that the 1041 regulations not govern surface uses related to geothermal development, leaving surface uses to be addressed through a county land-use change permit. Davis recommend the 1041 regulations include surface uses and not require the applicants to go through both the 1041 and the land-use change processes. Having an applicant go through both “would be a redundant process,” Davis said. Having the 1041 process address the above-ground uses would allow for more flexibility in a process tailored for geothermal projects.

    Davis also recommended the commissioners keep existing language regarding use of geothermal resources in the environmental impact analysis section of the application process and not limit those uses to “legal uses.” With a domestic well, the owner has no legal right to the water’s heat, only the water itself, Fred Henderson, chief scientific officer for Mt. Princeton Geothermal, said previously. People using heat from geothermal water without a legal right to the heat can change their well permits to define and allow use of the heat, he said. Some businesses, such as bed and breakfasts or vacation rentals, may have used the heat from their wells for years, not realizing they need to change their permit to authorize that use, Don Reimer, Chaffee County development director, said previously.

    Leaving the language open to all uses allows the commissioners to hear comment from all users, Davis said.
    Henderson spoke in favor of keeping the change that requires a notification for exploratory drilling to a depth of less 2,500 feet, and the commissioners concurred.

    Jeanne Younghaus with Chaffee County League of Women Voters, said the league has concerns about companies drilling and leaving without cleaning up their exploration.

    More information about the county’s geothermal 1041 process is at http://chaffeecounty.org/Geothermal-1041.

    In other business, Chaffee County commissioners instructed staff to draft a resolution that would amend Nestlé Waters North America Inc.’s 1041 and special land use permits to allow them to switch their augmentation agreement from the city of Aurora to the Upper Arkansas Water Conservancy District.

    More geothermal coverage here and here.

    ’11,000 homes, 200 miles of road, destroyed…You can’t plan for that’ — Tisha Schuller #COflood

    October 6, 2013
    Production fluids leak into surface water September 2013 -- Photo/The Denver Post

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

    From The Denver Post (Mark Jaffe):

    As floodwater started to rise Sept. 11, some oil and gas operators began shutting wells and securing facilities. It would be five days before state regulators announced their plans. “Did the state have a disaster plan for the oil and gas fields?” asked Bruce Baziel, energy program director of the environmental group Earthworks. “It was hard to tell.”

    From the start, state oil and gas regulators were gathering information and passing it on to the incident commander overseeing disaster response, said Alan Gilbert, a Colorado Department of Natural Resources official. “That’s our role as a technical agency,” Gilbert said.

    Throughout the weekend, oil companies were providing information on their operations to the Colorado Oil and Gas Conservation Commission. “Demands on us to be transparent were high,” said Tisha Schuller, president of the Colorado Oil and Gas Association, an industry group.

    Yet as pictures of bubbling pipes, spouting wells and floating tanks began to appear on social media, fears rose about what was happening in the flooded oil fields.

    On Sept. 16, as the flood covered parts of the oil-rich Denver-Julesburg Basin, additional steps to assess impacts were announced by the oil and gas commission staff. “We intend to compile an ongoing spreadsheet with the status of operations,” said Matt Lepore, executive director of the commission.

    Regulations require operators to report spills, but for the rest Lepore asked for voluntary cooperation of the industry on assessing the status of all wells. “In the middle of a disaster, it strikes me that this ought to have been required,” said Peter May-smith, executive director of Conservation Colorado. “If it wasn’t required by regulation, the governor should have issued an executive order,” May-smith said.

    The steps announced were “ad hoc,” but the commission had been monitoring the situation, DNR’s Gilbert said. “We are going to have a formal review,” Gilbert said. “We’ll look at what worked and what didn’t work.”

    Within days, the commission had about 18 inspectors in the field checking sites. The commission used its mapping capabilities to identify wells and facilities in floodplains and focus on those. About 1,500 wells were identified in the floodplains of the South Platte and other Front Range rivers, Gilbert said.

    “For years, conservation groups have pressed for limited drilling in floodplains, and the state and the industry have fought it,” said Gary Wockner, Colorado program director for Clean Water Action. “Part of this wasn’t a natural disaster but a man-made disaster,” Wockner said.

    The industry estimated that at the height of the flooding, 1 ,900 wells were shut in — there are more than 20,000 wells in the basin.

    State inspectors have counted 14 “notable releases,” primarily from overturned or damaged tanks, accounting for 1,042 barrels (43,764 gallons) of petroleum products. There also were 13 releases of produced water — which contains well impurities — totaling 430 barrels (18,060 gallons), according to the state.

    “That’s thousands of gallons of pollutants poisoning our waterways,” Wockner said. “It isn’t something to be dismissed.”

    By Thursday, inspectors had covered 90 percent of the wells and facilities in the floodplains, Gilbert said.

    “When you have an industrial activity of this scale, you need clear contingency plans,” said Conservation Colorado’s May-smith. “A clear plan in advance.”

    In their review, state officials will evaluate how effective the regulations were in preventing flood spills and whether reporting was adequate and the emergency plans adequate, Gilbert said. Could that lead to new rules or plans? “That is what we are going to look at,” Gilbert said.

    Still, in the face of a 500-year flood , state and industry officials contended the performance was good.

    “It was chaos — 11,000 homes, 200 miles of road, destroyed,” the Oil and Gas Association’s Schuller said. “You can’t plan for that. You just have to be flexible and responsive.”

    More oil and gas coverage here and here.

    Parker-based Independent Energy Partners and the School of Mines are testing a new oil shale production technology

    October 5, 2013
    Geothermic fuel cell well field -- via Independent Energy Partners

    Geothermic fuel cell well field — via Independent Energy Partners

    From The Grand Junction Daily Sentinel (Dennis Webb):

    A Colorado company is working with the Colorado School of Mines on the next stage of testing for a novel approach to developing oil shale. Parker-based Independent Energy Partners is pursuing the concept of using what it calls a geothermic fuel cell to employ heat to produce oil from shale in-situ, or in place, underground. Strings of fuel cells would be stacked in wells drilled into the shale.

    The idea was first conceived by Marshall Savage, whose family has extensive land holdings in western Colorado’s Piceance Basin and who serves as IEP’s vice president of technology development.

    A fuel cell can convert a fuel like natural gas into electricity through a chemical process. The patented, downhole heater being developed by IEP will use the waste heat to warm up the oil shale rock in what’s called a geothermic process, versus the geothermal one of tapping heat from the ground.

    The company plans to use locally produced natural gas to get the fuel cells going, but under the concept the cells then will operate on gas generated along with oil in the heating process. Electricity production will be a side benefit of the process, and IEP President and Chief Executive Officer Alan Forbes said the process would be water neutral because water produced by the fuel cell would offset consumption. Carbon emissions would be minimal because there’s no combustion, he said.

    The company had Pacific Northwest National Laboratory do work to confirm the concept’s technical viability, and had Delphi, a solid oxide fuel cell maker, make a downhole prototype. Now, IEP is paying about $900,000 for the School of Mines to do prototype testing at its Colorado Fuel Cell Center. The school received a small unit earlier this year and a stacked one more recently.

    Initial testing will be followed next year by in-ground tests on campus, and then field tests in oil shale formations, with a goal of producing oil in 2015. IEP holds several leases on private property in Rio Blanco County.

    “It’s kind of an exciting research project,” said Jeremy Boak, director of the Center for Oil Shale Technology and Research at the School of Mines.

    Said Forbes, “We’re pretty confident it’s going to work fine, it will work as advertised.”

    Boak said one challenge the company might face is rock shifting when heated and damaging heaters. He said he thinks Shell faced such problems but was able to solve them. [ed. emphasis mine]

    The company is pressing forward even as Shell has announced the end of its Colorado oil shale research and development project, citing a desire to focus on other global opportunities.“I know that they haven’t been doing really well at a corporate level and I think they’re just readjusting their priorities,” Forbes said.

    He said IEP’s work is “moving right along.”

    “We’re quite pleased with the progress and the parties we’re working with right now.”

    Those parties include the energy giant Total, which also is a partner with American Shale Oil in an in-situ project in Rio Blanco County and is invested in Red Leaf Resources’ project to mine and process oil shale in Utah.

    “I think Total is very energized by this (IEP) approach and other approaches and is eager to see something proceed here,” Boak said.

    More oil shale coverage here and here.

    ‘In my experience, you don’t ever get a perfect solution’ — Diane Mitsch Bush #COflood

    October 5, 2013
    Flooded well site September 2013 -- Denver Post

    Flooded well site September 2013 — Denver Post

    From Colorado Public News (David O. Williams):

    Colorado state Rep. Diane Mitsch Bush says she plans to take up the issue of water contamination and greater setbacks for oil and gas wells from waterways in the wake of this month’s devastating flooding. Mitsch Bush, a Democrat representing Routt and Eagle counties on the Western Slope, told Colorado Public News new rules need to be considered for keeping drilling away from rivers and streams. The approach is similar to the state’s new setback rules for homes and public buildings, which went into effect Aug. 1. Current rules prohibit drilling within 300 feet of streams that provides municipal drinking water – extending five miles upstream of the water intake – but that setback doesn’t apply to bodies of water in general…

    Rivers across northeastern Colorado – including the South Platte and St. Vrain – have been inundated with a variety of contaminants from flooding that started Sept. 11. Mitsch Bush said she is concerned about potential health impacts of the 890 barrels of oil that regulators confirmed have spilled in the flood zone.

    “Any oil, any condensate, has the BTEX [benzene, toluene, ethylbenzene, and xylene] component and many others,” said Mitsch Bush. “All of those are very contaminating in a water body in relatively small portions. I think it’s really important that we don’t minimize what’s in there, but at the same time that we don’t have a huge overreaction either.”[...]

    Asked about the potential for new setback laws or rules as a result of the floods, a spokesman for the Colorado Oil and Gas Association, an industry trade group, said their continued focus is on recovery, safety and getting production back online.

    “Once flooding began, over 1,900 wells were shut in,” the group’s Director of Policy and External Affairs Doug Flanders said in an email, referring to the organization’s website for shut-in procedures. “To date, this has resulted in less than 1 percent of the wells having any isolated incidents due to debris-filled flood waters…

    “In my experience, you don’t ever get a perfect solution,” she said, “but you get a better, a good, a sufficient solution if you can work with all the groups and sit down, talk about it, work together and see what you can come up with.”

    More oil and gas coverage here and here.

    Environment Colorado releases report — ‘Fracking by the Numbers’

    October 4, 2013
    Dilbert's company embraces hydraulic fracturing for competitive advantage

    Dilbert’s company embraces hydraulic fracturing for competitive advantage

    Here’s the release from Environment Colorado:

    As Colorado assesses the extent of pollution from gas drilling sites swamped by September’s flood, a new report charges that since 2005, fracking operations in Colorado have generated 2.2 billion gallons of toxic wastewater. The Environment Colorado Research & Policy Center report “Fracking by the Numbers” is the first of its kind to measure the footprint of fracking in Colorado to date.

    “The numbers don’t lie—fracking has taken a dirty and destructive toll on our environment. If fracking continues unchecked, these numbers will only get more dire,” said Lindsey Wilson, field associate from Environment Colorado. “At the very least we need to make sure that the oil and gas industry is subject to standard environmental laws, like our nation’s hazardous waste law.”

    Water contamination—especially after the recent flooding across the front range—is a real concern. Cliff Willmeng, a trauma nurse who has been involved in East Boulder County’s efforts to ban fracking, was one of the first to document damaged oil and gas infrastructure during the Front Range’s historic floods. “All of these sites contain various amounts of hazardous industrial wastes that are capable of spilling into the waterways and onto agricultural land,” said Willmeng. “Many of these chemicals are carcinogenic, neurotoxic, and known endocrine disruptors.”

    In addition, the “Fracking by the Numbers” report measures other key indicators of fracking threats in Colorado, including 38,150 tons of air pollution produced in 2012, and 23 million tons of global warming pollution since 2005.

    The state of Colorado currently regulates oil and gas drilling, but several local communities have moved forward to ban fracking—even with the threat of lawsuits by the state looming over their heads.

    “State officials must allow cities, towns, and counties to protect their own communities from the dangers that oil and gas development pose through local bans and restrictions on fracking,” said Boulder City Councilor Macon Cowles. “It is not just City Councilors who are concerned about fracking, but entire communities.”

    Colorado ranks near the top of the list for all key indicators of fracking threats in the national data. In addition to the 2.2 billion gallons of toxic wastewater produced, 57,000 acres of land has been damaged by fracking since 2005—which is equivalent to one third of the acreage of Colorado’s state park system.

    “The bottom line is this: The numbers on fracking add up to an environmental nightmare,” said Wilson. “For public health and our environment, we need to put a stop to fracking.”

    At the federal level, the Obama administration received more than one million comments last month calling for much stronger protections from fracking for national forests and national parks. In addition, Rep. Matt Cartwright of Pennsylvania (D-Scranton) has introduced the CLEANER Act (H.R. 2825)—a bill to close the loophole exempting oil and gas waste from the nation’s hazardous waste law.

    “The data from today’s report shows that Coloradans are not protected from this dirty drilling,” said Wilson. “Federal officials must step in; they can start by keeping fracking out of our forests and closing the loophole exempting toxic fracking waste from our nation’s hazardous waste law.”

    More oil and gas coverage here and here.

    The COGCC is tracking 15 flood related spills #COflood

    October 3, 2013
    Flooded well site September 2013 -- Denver Post

    Flooded well site September 2013 — Denver Post

    From the TheDenverChannel.com (Phil Tenser):

    The Colorado Oil and Gas Conservation Commission reports the fifteenth release was discovered at a PDC location about a half mile east of Greeley, south of Highway 34. It was discovered since the commission’s Monday report.

    Sixteen other sites have evidence of a “minor” oil or gas spill.

    Additionally, the COGCC reports a total of 18,060 gallons of “produced water” — water extracted from the Earth along with oil or gas — have spilled from 13 locations. That liquid is regulated by the state and the EPA because of what it may contain.

    COGCC teams report they completed evaluations of 991 wells or production facilities covering 80 percent of the flooded area.

    From the Denver Business Journal (Cathy Proctor):

    Noble’s “blanket shutdown” involved wells scattered along the South Platte, Big Thompson and St. Vrain rivers, according to the company. Those rivers swelled to damaging levels after days of rain that started on Sept. 9. Noble employees raced rising waters to reach some well sites and physically shut down the wells themselves. More than 80 percent were shut down remotely, according to company officials. As of Tuesday, 394 of those wells remain closed, and Noble executives estimated that damage to their equipment might total between $7 million and $17 million…

    The company has reported four flood-related spills to the Colorado Oil and Gas Conservation Commission, totaling about 212 barrels (8,903 gallons) of oil, and 30 barrels (1,259 gallons) of “produced water,” or water pumped from the underground rock formation that carries small amounts of oil and gas with it…

    Some opponents of oil and gas operations have criticized the industry for the spills, calling for moratoriums on oil and gas operations in the flooded areas.

    And while company officials say any spills are too many, they’re surprised things aren’t worse given the widespread flood damage. “We feel fortunate,” said Dan Kelly, Noble’s vice president of the Denver-Julesburg Basin — a rich cache of oil and natural gas sprawls north and east of Denver, of how Noble’s operations stood up against the rushing floodwaters that wrecked roads, homes, businesses, dams and wastewater treatment facilities across 4,500 square miles.

    “To have four spills out of 758 wells shut down and the 400 facilities (storage tanks at the well sites) — our equipment did what it was supposed to do,” he said. Three of the four spills came from flood-damaged storage tanks. The fourth spill stemmed from a flow line connected to a tank ripped by the rushing water.

    More oil and gas coverage here and here.

    Reclamation Awards $27.5 Million Contract to Rebuild Four Glen Canyon Generators #ColoradoRiver

    October 2, 2013
    A high desert thunderstorm lights up the sky behind Glen Canyon Dam -- Photo USBR

    A high desert thunderstorm lights up the sky behind Glen Canyon Dam — Photo USBR

    Here’s the release from the Bureau of Reclmation (Lisa Iams):

    The Bureau of Reclamation has awarded a $27.5 million contract to Alstom of Littleton, Colo., to rebuild four of the eight hydroelectric power generation units at Glen Canyon Dam that have reached the end of their service life.

    “For nearly 50 years, Glen Canyon Powerplant has generated renewable, hydroelectric power to help meet the electrical needs in the West,” said Reclamation Commissioner Michael Connor. “The units being rebuilt under this contract have been in service for nearly 30 of those years. Replacing the generation units on schedule ensures continued reliability and optimal efficiency of the powerplant for the next 30-35 years as Reclamation supports the nation’s all-of-the-above energy strategy.”

    The four units to be replaced will have improved generator components – known as ‘stators’ – made from solid copper bars, increasing reliability and extending the life of the units by up to 10 years. Once the work is completed, all eight of the powerplant’s generators will have been rebuilt.

    Work is scheduled to begin in the summer and continue through December 2016 with the process to rebuild each generator taking approximately seven months to complete. Only one generator will be rebuilt at a time which equates to 173 megawatt reduction in the total power plant capacity while each unit is off-line.

    All power plant maintenance and replacement activities are scheduled in full coordination with the Western Area Power Administration which markets the power sold to municipalities, rural electric cooperatives, Native American tribes, and government agencies in Wyoming, Utah, Colorado, New Mexico, Arizona, Nebraska, and Nevada.

    Glen Canyon Powerplant has a total capacity of 1,320 megawatts and annually produces approximately five billion kilowatt-hours of power to help sustain the electrical needs of about 5.8 million customers.

    More Bureau of Reclamation coverage here.

    Green River Basin: Utah may get its first nuke electrical generation plant if the water is there #ColoradoRiver

    September 29, 2013
    Desert landscape NW of Green River, Utah -- Photo via Heal Utah

    Desert landscape NW of Green River, Utah — Photo via Heal Utah

    From the Deseret News (Amy Joi O’Donoghue):

    The fate of a proposed nuclear power plant — the first in Utah — turns on the ebb and flow of the Green River, where proponents of the project want to divert water to cool the plant’s nuclear reactors.

    For five days in a small courtroom in Price last week, Judge George Harmond — who once served on the Utah Board of Water Resources — listened to reasons why the decision to grant that water for the plant was within the law or, alternately, why it contravened the statute governing water allocations.

    Ultimately, whatever the 7th District judge decides — he took the case under advisement and will issue a decision within 60 days — the loser in this contest is destined to appeal.

    I wonder what is different in the new designs that makes them require less water than Fukushima Daiichi did. It seems to me that it requires unlimited volumes of water when you are fighting for control of a fission reaction. That sort of supply is not apparent in the landscape near the reactor site.

    More nuclear coverage here and here.

    Oil shale: Shell’s exit from the game does not worry companies left standing #ColoradoRiver

    September 29, 2013
    Colony Oil Shale Project Exxon -- Photo / Associated Pres

    Colony Oil Shale Project Exxon — Photo / Associated Pres

    From The Grand Junction Daily Sentinel (Dennis Webb):

    Some companies pursuing oil shale projects in Colorado and Utah voiced confidence in their efforts Wednesday even as they absorbed the news that Shell is shutting down its undertaking in Rio Blanco County.

    Among them is American Shale Oil LLC, which holds a federal research, development and demonstration lease in Rio Blanco County and is working to develop oil shale in-situ, meaning in place underground. “AMSO’s still committed to its project. We still believe (oil shale) is a viable resource using our approach” to develop it, said Claude Pupkin, chief executive officer of Genie Energy, which owns a 50 percent interest in AMSO.

    In northeastern Utah, Red Leaf Resources continues to move “full-speed ahead” with its project, with the next goal being a commercial demonstration of its surface-mining and processing approach to develop oil shale, said CEO Adolph Lechtenberger.

    “Everything we look at in our technology says it’s certainly economic at today’s oil prices,” he said.

    Shell said this week it is ending its in-situ Colorado oil shale project, which it began in 1996. Shell has been a leader in oil shale research in the region and owns three federal RD&D leases in Rio Blanco County. Shell said it had decided to focus on other opportunities and assets in its global energy portfolio, including oil shale projects in Jordan and Canada.

    Last year, Chevron, which also holds a federal RD&D lease in Rio Blanco County, also said it was ending its oil shale project.

    ExxonMobil, which recently was granted a federal RD&D lease in Rio Blanco County for an in-situ project, declined to react to Shell’s decision, saying it doesn’t comment on the activities of other companies. But spokesman Patrick McGinn said it is continuing lab-based work on its process.

    Different barrel of oil

    ExxonMobil is hoping to fracture shale, fill fractures with conductive material and then heat the shale with an electric charge to produce oil. “We are concentrating our efforts on developing additional improvements in thermal and electrical process efficiency to further improve the economic and environmental factors of any commercial development.

    “Field experiments to test new developments could be conducted at either (the company’s Parachute-area) Colony Mine or the ExxonMobil RD&D lease in Rio Blanco County. We do not anticipate field tests in 2013,” he said by email.

    Lechtenberger said it’s unfortunate to see a player of Shell’s size pull out of Colorado. “They’ve done a lot of good work over the years and made pretty good strides,” he said.

    But he added, “I think we’re going after a different barrel of oil than Shell was going after.” Shell was targeting shale deep underground, he noted.

    “Our technology is going after shale closer to the surface, easier to mine, with a lower cost to remove,” he said.

    Enefit also is working on a surface shale project in Utah. Lechtenberger said he thinks the deeper-shale projects in Colorado “are going to be a challenge. I think they’re going to be capital-intensive and they’re going to take good technology to do it.”

    Companies pursuing the in-situ process in Colorado are targeting the heart of what is the world’s largest oil shale resource and extends into Utah and Wyoming. They also say their approach will result in fewer surface impacts.

    AMSO has been working through some challenges with heaters for its project and is currently evaluating alternative heaters it can use.

    Pupkin said it’s important to note that Shell isn’t pulling out of oil shale altogether. “They have a very active project ongoing in Jordan and our understanding is that it’s because Jordan not only has very attractive oil shale but they’ve put in place a regulatory framework that makes investment projects capital-attractive,” he said.

    Regulatory uncertainty

    Jeremy Boak, director of the Center for Oil Shale Technology and Research at the Colorado School of Mines, said the last he heard Shell has more than 200 people working on oil shale in Jordan. Worldwide, it has spent hundreds of millions of dollars on oil shale, he said. “They’re clearly not abandoning oil shale as a concept. They’re just deciding that Colorado is not the place they want to do it right now even though it’s (home to) the world-class resource.”

    Pupkin said he thinks the regulatory uncertainty related to the Bureau of Land Management’s changing position regarding royalties and other oil shale rules contributed to Shell’s decision. Shell has voiced concern over that uncertainty in the past but didn’t specifically cite it this week.

    The BLM also has sharply reduced the amount of land potentially available for oil shale leasing in the three-state region, and particularly in Colorado. “We think that the Obama administration has taken a pretty negative approach towards oil shale,” Pupkin said.

    Jeff Hartley of Red Leaf Resources noted that his company doesn’t face the constraints Shell faced with BLM lands because it is working on school trust lands instead.

    Viable technologies

    Chevron spokeswoman Cary Baird said she doesn’t believe her company raised regulatory concerns as an issue when it made its oil shale decision. Rather, it was just a matter of prioritizing what opportunities to invest financial and human resources in at a global level, she said, somewhat echoing Shell’s reasoning. “There are difficulties occasionally in getting good, qualified people to work on different projects and when you have a global portfolio it makes it more complicated,” she said.

    Shell’s decision comes as companies are using hydraulic fracturing to produce growing amounts of natural gas and oil. Shell just this week identified a location for a $12.5 billion natural-gas-to-liquids facility it hopes to build in Louisiana.

    “When you compare the challenge of oil shale to the viability of these other sources, Shell like Chevron decided to place their focus on viable technologies and viable business models,” said David Abelson, oil shale policy advisor for the Western Resource Advocates conservation group. He said he wasn’t surprised by Shell’s announcement, and that it’s learned what other companies have learned over a century about the “extremely challenging” economics of developing oil shale.

    “Shell has always said that this is a research project and they always talked about it being a heavy lift to create a viable fuel and what they learned is what Chevron learned,” he said.

    He said Shell hasn’t been among the strongest boosters of oil shale. “It was the elected officials that got ahead of Shell and claimed the viability of these technologies,” he said.

    More oil shale coverage here and here.

    USGS: Chemistry and Age of Groundwater in the Piceance Structural Basin #ColoradoRiver

    September 29, 2013
    Piceance Basin

    Piceance Basin

    Click here to read a copy. Click here for the release. Here’s the abstract:

    Fourteen monitoring wells were sampled by the U.S. Geological Survey, in cooperation with the Bureau of Land Management, to better understand the chemistry and age of groundwater in the Piceance structural basin in Rio Blanco County, Colorado, and how they may relate to the development of underlying natural-gas reservoirs. Natural gas extraction in the area has been ongoing since at least the 1950s, and the area contains about 960 producing, shut-in, and abandoned natural-gas wells.

    More oil and gas coverage here and here.

    Shell turns its back on the ‘Next big thing’ — plans exit from the oil shale game after 30 some years

    September 26, 2013
    Oil shale deposits Colorado, Wyoming and Utah

    Oil shale deposits Colorado, Wyoming and Utah

    Oil shale has been the “next big thing” in Colorado for over 100 years. It looks it will take a bit longer to develop as Royal Dutch Shell is pulling out of the play in western Colorado. Here’s a report from Cathy Proctor writing for the Denver Business Journal. Here’s an excerpt:

    “There’s been a shift in our oil shale project,” spokeswoman Carolyn Tucker said Tuesday. “The energy market has evolved since Shell first started its oil shale research project in 1981. We plan to exit our Colorado oil shale research project in order to focus on other opportunities and producing assets in our broad global portfolio,” she said in an email.

    “Our current focus is to work with staff and contractors as we safely and methodically stop research activities at the site,” she said.

    The announcement regarding the closure of Shell’s oil shale research and development work comes as the company announces plans to put its assets on the market across the United States, including oil and gas assets in northwestern and southeastern Colorado…

    …scientists have spent decades trying to unlock oil shale’s bounty, and many believe that breakthroughs are years away — if they ever happen. Chevron, another Big Oil major, abandoned its oil shale research efforts in February 2012.

    I hate to tell you that I told you so but here’s an article that I wrote in 2008 for the Denver Examimer.

    From the Glenwood Springs Post Independent (Hannah Holm):

    In 2008, the Colorado and Yampa-White Basin Roundtables, which are groups of stakeholders responsible for “bottom-up” regional water planning, commissioned a study on future water needs for energy development. The initial phase of the study raised eyebrows with the estimate that if oil shale really took off, the industry could be using nearly 380,000 acre feet of water/year by the 2040s, largely due to water use by power plants needed to provide the energy to extract oil from shale. An acre foot is approximately enough water to supply 2-3 households for a year.

    A later version of the roundtables’ study revised the oil shale water use projections down significantly, in part by changing assumptions about how the energy for the extraction process would be generated (with less thirsty natural gas-fired plants rather than coal-fired plants). This version settled on an estimate of 120,000 acre feet/year to supply a large-scale oil shale industry and concluded that it could be supplied mostly from the White River.

    Although significantly lower than the earlier estimate, 120,000 acre feet/year is still much more than the water needs projected for other energy development sectors in the region, including natural gas development. Water use of that magnitude could impact the state’s ability to develop water from the Colorado River and its tributaries for other uses, including meeting the needs of our growing cities. Current uses, such as irrigated agriculture, could also be impacted if senior water rights were applied to meeting the industry’s needs.

    So … does Shell’s withdrawal from oil shale research in the region mean water planners no longer need to account for this potentially large increase in the use of our region’s water? Not necessarily, since several other companies are still actively working on their oil shale research and development projects.

    However, since the water use estimates used in the roundtables’ studies were based largely on the technologies Shell was testing, the numbers will certainly need to be reconsidered, and the time horizon may be pushed back even further.

    From The Grand Junction Daily Sentinel (Dennis Webb):

    In a major setback to the effort to develop oil shale in the United States, Shell is closing down its research and development project in Rio Blanco County.

    The company was the biggest player in oil shale in Colorado, holding three federal research, development and demonstration leases.

    Shell spokeswoman Carolyn Tucker said the decision reflects an evolving energy market since Shell began its oil shale research in 1981.

    “We plan to exit our Colorado oil shale research project in order to focus on other opportunities and producing assets in our broad Global portfolio,” she said in an e-mail. “Our current focus is to work with staff and contractors as we safely and methodically stop research activities at the site.”

    In an interview, she said employment at Shell’s research site has ranged anywhere from 10 to 50, depending on activity levels.

    “It’s not going to be an abrupt exit,” she said.

    Shell has obligations and projects it needs to wind down, including reclamation and decommissioning work required by the Bureau of Land Management, she said.

    Chevron, which also received a research and development lease from the BLM, decided early last year to divest itself of the lease, saying it wanted to focus on other priorities.

    Just last month, Shell announced plans to sell its oil and gas project in Routt and Moffat counties. That followed an earnings decline and a review of Shell’s various oil and gas projects in the Americas, followed by a decision to keep those with the most growth potential.

    At that time, Tucker said that decision had no bearing on its oil shale project, saying it involved a separate business that’s still in the research stage.

    But she said this week’s decision results from another review project looking specifically at Shell’s oil shale assets, which also include holdings in Jordan and Canada.

    “A number of factors went into the decision. Based on those many factors we’ve chosen to put those resources into the other oil shale assets and not in Colorado,” Tucker said.

    More oil shale coverage here and here.

    Parachute Creek spill: No benzene detected in creek since August #ColoradoRiver

    September 24, 2013
    Location of spill on Parachute Creek 2013 -- Graphic/The Denver Post

    Location of spill on Parachute Creek 2013 — Graphic/The Denver Post

    From The Grand Junction Daily Sentinel (Dennis Webb):

    State regulators have finalized an agreement with a Williams subsidiary, finding it in violation of Colorado law and an associated rule in connection with a natural gas liquids leak near Parachute. Regulators also have cleared another company in the incident.

    The Colorado Department of Public Health and Environment and Bargath LLC reached what’s called a compliance order on consent in August. The department’s Hazardous Materials and Waste Management Division found Bargath in violation for having released hazardous materials to the environment without a permit.

    The leak from a pressure gauge on a pipeline leading from Bargath’s gas processing plant resulted in high benzene levels in groundwater and occasional small amounts of the carcinogen in Parachute Creek. No benzene has been detected in the creek since August.

    Meanwhile, the division has informed WPX Energy, an exploration and production company that owns the property where the leak occurred in a pipeline right of way, that it is closing enforcement action it had begun against WPX with no further requirements. The division indicated in a letter that WPX demonstrated “it did not cause or control the operations causing the release” of the natural gas liquids.

    Additionally, last week Colorado Oil and Gas Conservation Commission director Matt Lepore wrote to WPX that a notice of alleged violation it brought against WPX in March, when that agency first began investigating the case, has been closed. That’s because of COGCC’s decision to transfer the matter to the CDPHE after determining the leak wasn’t under its jurisdiction because it didn’t involve exploration and production waste.

    Bargath continues to contend the liquids were indeed such waste and not subject to the hazardous materials division’s jurisdiction. But in signing the consent order it chose not to contest the issue. “They stepped up to the plate and decided not to fight even though they felt strongly about this,” said David Walker, an environmental compliance officer with the division.

    The consent order includes no fines against Bargath, although that doesn’t preclude other state agencies from pursuing fines in the case. Division officials say the lack of a fine is based on the lack of negligence and the non-willful nature of the leak.

    The agreement does call for Williams to pay $8,400 to reimburse division staff for its time working on the matter to date, and the company will continue to be billed for future expenses.

    Walter Avramenko, the division’s hazardous waste corrective action unit leader, said Williams also probably already has spent several million dollars on the cleanup, which ultimately could cost it tens of millions of dollars.

    The compliance order’s focus is on establishing requirements and schedules for Williams’ continuing cleanup of the leak, which could last a couple of years, followed by a long period of monitoring, Walker said.

    In addition to other efforts, Williams has begun pulling contaminated groundwater from the ground, cleaning it with a treatment system and returning it to the aquifer.

    Williams believes the leak occurred from Dec. 20 to Jan. 3. It estimates about 50,000 gallons of hydrocarbons leaked, with most of that vaporizing but about 10,000 gallons reaching the ground. The violation is based on groundwater benzene levels at 11 monitoring points that exceeded 0.5 parts per million, the minimum amount for which the division considers to be benzene in a liquid to be a hazardous waste. Readings at those points ranged from 7.5 to 38 parts per million.

    However, the division is striving to have Williams clean up the benzene to the state’s much stricter groundwater standard of 5 parts per billion. That’s also the federal drinking water standard, although the state doesn’t consider the creek a drinking water source.

    Williams personnel first discovered the leak Jan. 3 but thought it involved perhaps 25 gallons. They had dealt with an air line freezing causing a valve to close, and assumed that overpressurized and broke the gauge, Walker said. Only later did they realize the gauge had broken much earlier. Williams discovered the actual size of the leak in March during excavation work for a new pipeline.

    More oil and gas coverage here and here.


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