Piedra River: Say hello to Chimney Rock Farms #ColoradoRiver

April 15, 2014
Chimney Rock Farms photo via the Cortez Journal

Chimney Rock Farms photo via the Cortez Journal

From the Cortez Journal (Mary Shinn):

At Chimney Rock Farms on the Piedra River, Brewer has built two commercial-scale aquaponic greenhouses that house fish tanks and thousands of square feet of troughs where kale, lettuce and tot soy float on a foot of water in rafts from seed to harvest.

“We’re pioneering this, no doubt,” said Brewer. He said that the operation, located 6,600 feet above sea level, is the largest commercial aquaponics farm venture in Colorado.

Brewer plans to supply new Southwest Farm Fresh, A Farm and Ranch Cooperative, which was started in Montezuma County. He also plans to supply the Pagosa Springs farmers market, his Community Supported Agriculture membership, organic grocery stores and restaurants.

In March, the operation had already been supplying a grocery store for three weeks.

In the aquaponic environment, the greens mature in six weeks, which allows him to provide custom mixes of greens and meet demand quickly.

“It’s revolutionary for us,” he said.

In addition to greens, his tilapia – the “aquaponic” aspect of the hydroponic system – can also be sold. Brewer may sell the fish whole on ice at farmers markets, but they are not his main focus.

How it works

In the most basic terms, fish poop feeds plants. In technical terms, the tilapia excrete ammonia. Bacteria break the ammonia down into nitrites and then into nitrates, which feed the plants. The plant roots filter the water, and the water is pumped back to the fish.

The tilapia can’t be kept with the plants because they’d eat the roots. But very small mosquito fish clean the roots and fend off potential mosquitoes.

The seeds are germinated in soil, and the fish-fertilized water flows beneath. As the plants mature, they are transferred into rafts that allow for more space and push down the trough. This system reduces man hours and eliminates all weeds.

“We were spending 60 percent of the time to produce a leafy green, weeding our beds,” he said. To harvest, the roots just need to be trimmed off.

It is also very efficient in terms of water. Aquaponic systems use less than 5 percent of the water of traditional agriculture, Brewer said.

“This is a good fit for us in the desert Southwest,” Brewer said.

As green as possible

Brewer was looking for ways to grow year round, but the inefficiencies of a greenhouse held him back.

“Heating traditional greenhouses with fossil fuels – propane and natural gas – is a very, very tough way to make a living,” he said.

In his newly built greenhouses, the water is heated by solar panels, and a wood boiler. This allows him to grow when temperatures are below freezing outside. He also uses solar panels to power air and water pumps, and grow lights. The solar panels allow him to put electricity back into the grid, and his monthly electricity bill has dropped from more than $600 to just $16.

In the new greenhouses, he hopes to grow from mid-February through Thanksgiving.

He expects that he will make back his investment in his capital improvements in five to six years.

It was important to him to reduce his use of fossil fuels because they are limited resource and their ballooning costs can cut into thin farm profit margins.

“As a farmer, your margins are too thin to rely on fossil fuel costs as a line item,” Brewer said…

“Hopefully, we can prove the economic viability of this such that other people are willing to take the capital intensive risk to build a system like this to grow local food,” he said.

More San Juan Basin coverage here.


Pure Cycle Corporation Announces Second Fiscal Quarter 2014 Financial Results

April 14, 2014

waterfromtap

Here’s the release from Pure Cycle Water:

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

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

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

More infrastructure coverage here.


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

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

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

From the Glenwood Springs Post Independent (John Stroud):

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

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

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

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

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

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

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

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

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

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

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

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

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

From the Vail Daily (Melanie Wong):

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

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

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

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

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

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

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

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

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

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

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

More Colorado River Basin coverage here.


Managing Lake Powell’s power pool, will it benefit from the current snowpack? #ColoradoRiver

April 5, 2014
Glen Canyon Dam -- Photo / Brad Udall

Glen Canyon Dam — Photo / Brad Udall

From The Grand Junction Daily Sentinel (Gary Harmon):

Federal officials fretted for a year that they might have to take action as the water level in Lake Powell fell perilously close to the point that Glen Canyon Dam couldn’t generate electricity. Those fears were staved off, but not eliminated, after a meeting on Friday that involved top officials from the Interior Department and Bureau of Reclamation, according to Colorado officials who attended the meeting.

“They’ve been concerned since last year” when federal officials began modeling flows into Lake Powell and concluded that two dry years similar to 2012 and 2013 could threaten the intakes into the electricity-generating turbines, said Upper Colorado River Basin Commissioner John McClow on Wednesday.

“They’re nervous now,” said Eric Kuhn, general manager of the Colorado River Water Conservation District, “Six months ago, they were more nervous.”

Snowpack of 110 percent of average or more so far this year in the Colorado mountains has alleviated much of the immediate concern, McClow said.

“We’ve gotten a reprieve this year, but we’re still working” on plans that would forestall any need for federal involvement in river management beyond the bureau’s existing role, McClow said.

What expanded federal involvement might mean is unclear, but Mesa County Commissioner Steve Acquafresca, who represents the county on the Colorado River Water Conservation District board, said it’s extensive.

The issue isn’t whether the upper Colorado River is delivering enough water to meet the requirements of a 1922 compact among the seven basin states, but whether the water level in Powell is high enough to allow electricity generation.

“They’re talking about taking over management of the river if the power intakes (in Lake Powell) start sucking air,” Acquafresca said. “They’re not going to let that happen. You can’t start to develop a vortex in the reservoir.”

That vastly overstates the authority of the Bureau of Reclamation, said Larry Walkoviak, director for the bureau’s upper Colorado region.

“Each state has its own set of laws and we have to comport with those states’ water laws,” Walkoviak said. As the federal manager of the bureau’s dams and other facilities upstream from Glen Canyon, “I don’t have the authority to do something like that.”

The secretary of the Interior is the water master for the river below Glen Canyon, he noted, but not above.

Even at 39 percent full, the level of Lake Powell remains about 85 feet above the penstocks that feed the turbines in Glen Canyon Dam, so it seems that for the coming summer and probably more, the issue of electricity generation is likely moot, Walkoviak said.

Walkoviak was present at the meeting on Friday in Washington, D.C., that included Mike Connor, deputy secretary of the Interior; Anne Castle, assistant secretary for water and science; McClow; Kuhn; and James Eklund, director of the Colorado Water Conservation Board.

Eklund, Kuhn and McClow all stressed the significance of Colorado officials having contingency plans for low water levels in Powell at the ready when they met with the federal officials.

A three-party, state-developed contingency plan allayed much of the federal fear, McClow said.

“The bureau has given us every indication that it intends to work with us,” Eklund said

That plan calls for releasing more water than would otherwise be the case from the Aspinall Unit of dams on the Gunnison River, as well as Navajo Lake and Flaming Gorge; voluntary, compensated release of water rights by some users; and continued work to augment existing supplies.

The plan includes provisions for endangered species and for recreation and other uses, McClow said.

More Colorado River Basin coverage here.


Cotter and the CPDHE are still trying to work out a de-commissioning agreement for the Lincoln Park/Cotter Mill superfund site

April 5, 2014
Lincoln Park/Cotter Mill Site via The Denver Post

Lincoln Park/Cotter Mill Site via The Denver Post

From The Denver Post (Bruce Finley):

A broken pipe at Cotter Corp.’s dismantled mill in central Colorado spewed 20,000 gallons of uranium-laced waste — just as Cotter is negotiating with state and federal authorities to end one of the nation’s longest-running Superfund cleanups.

Colorado Department of Public Health and Environment officials said last weekend’s spill stayed on Cotter property.

In addition, uranium and molybdenum contamination, apparently from other sources on the Cotter property, has spiked at a monitoring well in adjacent Cañon City. A Feb. 20 report by Cotter’s consultant said groundwater uranium levels at the well in the Lincoln Park neighborhood “were the highest recorded for this location,” slightly exceeding the health standard of 30 parts per billion. State health data show uranium levels are consistently above health limits at other wells throughout the neighborhood but haven’t recently spiked.

“This isn’t acceptable,” Fremont County Commissioner Tim Payne said of the spill – the fourth since 2010. “(CDPHE officials) told us it is staying on Cotter’s property. But 20,000 gallons? You have to worry about that getting into groundwater.”

Environmental Protection Agency and CDPHE officials are negotiating an agreement with Cotter to guide cleanup, data-gathering, remediation and what to do with 15 million tons of radioactive uranium tailings. Options range from removal — Cotter estimates that cost at more than $895 million — or burial in existing or new impoundment ponds.

Gov. John Hickenlooper intervened last year to hear residents’ concerns and try to speed final cleanup.

Cotter vice president John Hamrick said the agreement will lay out timetables for the company to propose options with cost estimates.

The spill happened when a coupler sleeve split on a 6-inch plastic pipe, part of a 30-year-old system that was pumping back toxic groundwater from a 300-foot barrier at the low end of Cotter’s 2,538-acre property, Hamrick said.

Lab analysis provided by Cotter showed the spilled waste contained uranium about 94 times higher than the health standard, and molybdenum at 3,740 ppb, well above the 100-ppb standard for that metal, said Jennifer Opila, leader of the state’s radioactive materials unit.

She said Cotter’s system for pumping back toxic groundwater is designed so that groundwater does not leave the site, preventing any risk to the public.

In November, Cotter reported a spill of 4,000 to 9,000 gallons. That was five times more than the amount spilled in November 2012. Another spill happened in 2010.

At the neighborhood in Cañon City, the spike in uranium contamination probably reflects slow migration of toxic material from Cold War-era unlined waste ponds finally reaching the front of an underground plume, Hamrick said.

“It is a blip. It does not appear to be an upward trend. If it was, we would be looking at it,” Hamrick said. “We will be working with state and EPA experts to look at the whole groundwater monitoring and remediation system.”

An EPA spokeswoman agreed the spike does not appear to be part of an upward trend, based on monitoring at other wells, but she said the agency does take any elevated uranium levels seriously.

The Cotter mill, now owned by defense contractor General Atomics, opened in 1958, processing uranium for nuclear weapons and fuel. Cotter discharged liquid waste, including radioactive material and heavy metals, into 11 unlined ponds until 1978. The ponds were replaced in 1982 with two lined waste ponds. Well tests in Cañon City found contamination, and in 1984, federal authorities declared a Superfund environmental disaster.

Colorado officials let Cotter keep operating until 2011, and mill workers periodically processed ore until 2006.

A community group, Colorado Citizens Against Toxic Waste, has been pressing for details and expressing concerns about the Cotter site. Energy Minerals Law Center attorney Travis Stills, representing residents, said the data show “the likely expansion of the uranium plume, following the path of a more mobile molybdenum plume” into Cañon City toward the Arkansas River.

The residents deserve independent fact-gathering and a proper cleanup, Stills said.

“There’s an official, decades-old indifference to groundwater protection and cleanup of groundwater contamination at the Cotter site — even though sustainable and clean groundwater for drinking, orchards, gardens and livestock remains important to present and future Lincoln Park residents,” he said. “This community is profoundly committed to reclaiming and protecting its groundwater.

More Lincoln Park/Cotter Mill superfund coverage here.


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

April 5, 2014
San Luis Valley Groundwater

San Luis Valley Groundwater

From The Pueblo Chieftain (Robert Boczkiewicz):

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

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

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

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

BLM said that it is reviewing the lawsuit.

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

More Rio Grande River Basin coverage here.


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

April 3, 2014

chemistryglassware

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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

April 2, 2014

The Shoshone hydroelectric plant and its 1,250 cfs, 1902 water right is not for sale according to Xcel #ColoradoRiver

March 26, 2014
Shoshone Falls hydroelectric generation station via USGenWeb

Shoshone Falls hydroelectric generation station via USGenWeb

From the Aspen Daily News (Brent Gardner-Smith):

“Shoshone is not for sale,” Eggleston told the Colorado River Basin Roundtable, which met Monday in Glenwood Springs, nine miles downstream from the Shoshone plant. “Don’t plan to sell it. Nothing in the future about selling it.”

That may be good news to those on the West Slope who fear a Front Range utility will buy the plant, shut it down, and extinguish the plant’s senior water rights — resulting in less water in the lower Colorado River.

But it also means the plant’s fate is left in the portfolio of Xcel Energy, a regional utility based in Minneapolis that operates 25 other hydro plants, serves 3.4 million electricity customers in eight states, and sees $10.1 billion a year in revenue.

Eggleston’s comments to the members of the Colorado roundtable were in response to an article in The Daily Sentinel of Grand Junction on March 17 about the prospect of the plant being bought by West Slope interests.

The Sentinel story quoted Louis Meyer of SGM Engineering, a consultant developing the Colorado roundtable’s “basin implement plan,” that buying the plant would be “one of the seminal things going forward in our plan.”

The article included several references to the plant not being for sale, and stated there was “no indication for now that the Shoshone Generation Station is even for sale.”

But an Xcel spokesman quoted in the story, Mark Stutz, said he couldn’t comment on whether the plant was for sale, or not.

That left the prospect lingering.

And Eggleston told the roundtable meeting he wanted to clarify any “mis-information.”

“Again, Xcel is not interested in selling,” Eggleston said. “They would not consider any first-right-of-refusals, or anything else that’s not within the interests of Xcel at this time.”

Eggleston said the article in the Sentinel caught the attention of Ben Fowke, the company’s chairman, president and CEO.

“It would be a good idea to do that every two or three years so that the executive management is reminded how important Shoshone is, and that Xcel Energy is making a commitment to everybody on the Western Slope to protect those water rights and operate that plant,” Eggleston said.

The real value of the Shoshone plant to the West Slope is its senior water rights from 1902, which keep up to 1,250 cubic feet per second of water flowing down the Colorado River.

“The whole reason the West Slope, lead by the River District, would be interested in gaining the plant is because we want that water right held intact,” said Jim Pokrandt, a communications and education specialist with the Colorado River District…

Denver Water has long chafed at the restrictions imposed by Shoshone’s water rights, but Travis Thompson, media coordinator for the utility, said via email that “Denver Water has not made an offer to purchase the Shoshone plant over the last few decades, and there are no standing offers.”

Denver Water also drove the framing and adoption of the Colorado River Cooperative Agreement (CRCA), signed in 2012 by a list of regional entities.

“Under the CRCA, if Xcel decides to sell the Shoshone assets, they agree to do so in an open bidding arrangement,” Thompson, said.

He added that if the West Slope wanted to buy the plant, Denver Water also agreed it would support the idea and “assist the West Slope in acquiring Shoshone assets.”

But fear of Front Range water interests is still discernable in the Colorado River basin.

On Monday, Chuck Ogilby, a member of the Colorado roundtable, read a passage from the group’s vision statement: “The Shoshone call shall be preserved and protected for the benefit of the West Slope. This is non-negotiable.”

More Colorado River Basin coverage here and here.


HB14-1030 passes third reading in Senate, March 19, on to Gov. Hickenlooper #COleg

March 24, 2014

microhydroelectricplant

From HydroWorld.com (Michael Harris):

The legislation — officially HB14-1030 — streamlines state environmental review for small hydroelectric projects without weakening or changing any underlying state environmental requirements, according to the Colorado Small Hydro Association (COSHA).

Instead, the bill directs the Colorado Energy Office to facilitate project review by state agencies in a timely manner commensurate with federal agency timelines, making it possible for an applicant to simultaneously clear both federal and state reviews as quickly as 60 days for “non-controversial” projects.

The bill also streamlines the electrical inspection process by citing National Electrical Code (NEC) standards that electricians should be guided by when installing small hydro. According to COSHA, electrical inspectors will now determine if a project meets NEC standards for safety, quality and code compliance.

HB14-1030 mirrors legislation passed at the federal level in August 2013, which included the Hydropower Regulatory Efficiency Act and the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act.

“Last summer federal permitting requirements for small hydro were streamlined thanks to Colorado legislators in Congress,” said COSHA President Kurt Johnson. “Now thanks to leadership from Colorado legislators in Denver, similar streamlining legislation has been approved in Colorado. Congratulations and thanks to the sponsors of HB14-1030 for their leadership on this reform legislation which will serve as a model for other states nationwide.”

HB14-1030 came out of an October meeting of Colorado’s Water Resources Review Committee hearing led by Sen. Gail Schwartz…

“It has been a pleasure working with the Colorado Small Hydro Association on this legislation for rural Colorado,” Schwartz said. “HB14-1030 cuts red tape for small hydro development, helping to accelerate development of new small hydro installations and job creation.

“It’s a great example of Colorado common sense.”

More 2014 Colorado legislation here.


Many eyes are on the Shoshone 1902, 1,250 cfs water right #ColoradoRiver

March 18, 2014
Shoshone Falls hydroelectric generation station via USGenWeb

Shoshone Falls hydroelectric generation station via USGenWeb

From The Grand Junction Daily Sentinel (Dennis Webb):

Western Slope interests are beginning to speak with one voice about their interest in purchasing a historic Glenwood Canyon hydroelectric plant viewed by many as more valuable for its water rights than for its electricity. But there’s no indication for now that the Shoshone Generation Station is even for sale. And a purchase presumptively would involve a high price tag due to the considerable and highly senior water rights, meaning that a funding mechanism would need to be identified, not to mention a buying party.

“I’m sure if the plant was for sale something like that would be put together,” said Jim Pokrandt, spokesman for the Colorado River Water Conservation District in Glenwood Springs.

Controlling river

The 15-megawatt plant, owned by Xcel Energy, is tiny by hydroelectric facility standards. But its 1905 water right of 1,250 cubic feet per second wields a lot of power in the water world, ensuring the flow of that much water down the Colorado River at least as far as the Glenwood Springs area. If the right didn’t exist, it could open the door to further diversions of water to junior rights holders wanting it for municipal purposes on the Front Range.

“Shoshone’s really the controlling right on the river,” Pokrandt said.

The Shoshone flows are so important to Western Slope governments, irrigation districts and other entities that part of a recently finalized, wide-ranging agreement dozens of them struck with Denver Water formalizes a protocol for generally continuing flows required by the plant during plant outages. The deal also seeks to mimic those flows even if the plant no longer is operational. Under the deal, Denver Water also would support possible purchase of the plant by a Western Slope entity.

Meanwhile, a Colorado River Basin roundtable group currently is helping draw up a basin-wide plan to submit for consideration as part of development of a state water plan. Louis Meyer, a Glenwood Springs engineer who is doing public outreach around the basin as the group prepares its recommendations, said he’s hearing a unanimous consensus in support of buying the plant.

“I believe that will be one of the seminal things going forward in our plan,” he said.

Revenue stream

He said one of the things driving the concern is that while there may be a deal with Denver Water, other Front Range entities aren’t bound by it. Pokrandt, who chairs the roundtable group, said the fear is that an entity would buy the plant just to close it down and retire its water rights, enabling it to divert more water with junior rights.

He said it’s good to see the concept of buying the plant take root, but added, “it would be a very expensive proposition.”

Meyer agreed, but said that if the cost is spread among numerous counties, “it’s not very much at all.”

Pokrandt said the river district would be the logical entity to take the lead in a purchase.

“But we certainly couldn’t do it on the revenues that we have for our current operations. A revenue stream would have to be figured out,” he said.

“… The financial package would definitely have to be a West Slopewide discussion.”

He said there’s an increasing recognition on the Western Slope of the Shoshone rights’ value in keeping water in the river for environmental and recreational purposes, and ensuring its availability for municipal consumption, Grand Valley irrigation and other purposes downstream of the plant.

Electricity demand

The water rights are designated for electricity generation, which would mean the buyer would have to continue operating the old plant to keep the rights. Pokrandt said that wouldn’t be easy for the river district, but it already does things such as operate reservoirs.

But he was quick to point out about the Shoshone plant, “It’s not for sale, though.”

Xcel spokesman Mark Stutz said he can’t comment on whether the plant is for sale, due to general company policy about not speaking on acquisitions or sales of assets “unless there is some cause for doing it.”

He said people “shouldn’t read too much into that one way or the other.”

Even with its small size, the plant is a component for meeting electricity demand in the area, he said.

“It’s obviously a relatively modest facility but it still provides a big benefit to the company in supporting the grid in what’s obviously a more geographically challenging part of our service territory,” he said.

Xcel investment

Building transmission and generation is harder in the mountains, and Shoshone “remains a very important piece from the grid support standpoint,” he said.

Xcel spent $12 million repairing the plant after a penstock ruptured in 2007, putting it out of service.

“We will continue to operate that facility based on that investment,” he said.

Pokrandt said that in probably the best of all worlds, Xcel would continue to own and operate the plant.

He added, “I think Xcel also understands the politics of the situation and the preferred status quo of operating the plant under the current conditions.”

Stutz said the company understands the significance of the plant to entities in the region, and tries to be a good neighbor.

“We’ve always tried to work with any agreements made with other entities in terms of where that water goes,” he said.

More Colorado River Basin coverage here and here.


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

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

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

From the Denver Business Journal (Cathy Proctor):

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

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

From the Northern Colorado Business Report (Jerd Smith):

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

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

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

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

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

From the Associated Press via The Colorado Springs Gazette:

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

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

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

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

More oil and gas coverage here and here.


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

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

Flooded well site September 2013 — Denver Post

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

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

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

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

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

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

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

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

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

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

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

From The Denver Post (Mark Jaffe):

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

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

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

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

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

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

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

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

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

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

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

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

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

More oil and gas coverage here and here.


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

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

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

From The Denver Post (Mark Jaffe):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

More oil and gas coverage here and here.


ExxonMobil and Natural Soda Holdings, Inc. to research oil shale development #ColoradoRiver

March 11, 2014
Colony Oil Shale Project Exxon -- Photo / Associated Pres

Colony Oil Shale Project Exxon — Photo / Associated Pres

From The Grand Junction Daily Sentinel (Dennis Webb):

ExxonMobil and Natural Soda Holdings Inc. have edged another step closer to undertaking oil shale research-and-development projects with the Bureau of Land Management’s approval of their development plans. The approvals are for the company’s research, demonstration and development leases on federal land southwest of Meeker in Rio Blanco County. The projects still must undergo review by the Colorado Division of Reclamation, Mining, and Safety.

For ExxonMobil, its project marks a renewed attempt to commercially extract petroleum from oil shale after what was then Exxon shut down its Colony Project in 1982. That shutdown resulted in some 2,000 workers losing their jobs and caused economic repercussions for years from Glenwood Springs to Grand Junction.

Natural Soda, meanwhile, has extensive experience with another kind of mining at a site just north of its federal lease. It injects hot water underground to solution-mine for baking soda, known as nahcolite in its natural form. On its lease, it proposes first removing the nahcolite using its normal process, then producing oil from underground by heating it using either a downhole burner or a closed-loop steam system.

ExxonMobil also is proposing an in-situ, or in-place, development project involving heating the oil shale underground and then pumping out the oil — a process different from the Colony Project, which involved surface mining and heating of oil shale. Exxon wants to hydraulically fracture the oil shale, fill the fractures with conductive material and then electrically heat the shale.

The companies acquired the leases under a second round of R&D leasing conducted by the BLM. The leases initially cover about 160 acres but potentially can be enlarged by some 480 acres for commercial development if certain conditions are met.

Shell, Chevron and American Shale Oil hold R&D leases in Rio Blanco County from the earlier round of leasing — including three leases in Shell’s case — with the potential to convert each lease to nearly eight square miles for commercial development. But while AMSO continues to work on an in-situ project, Chevron, and more recently Shell, have ended their oil shale projects in connection with their leases. Shell had done the most work of any company on an in-situ shale project in Colorado before shutting it down last year.

Economics, environment

In approval documents for the ExxonMobil and Natural Soda plans, BLM White River Field Office manager Kent Walter wrote that each proposed action “with mitigation represents an opportunity to develop domestic energy sources and to inform and advance knowledge of commercially viable production, development and recovery technologies of oil shale resources consistent with sound environmental management. It also will provide a basis for informed future decisions about whether and when to move forward with commercial scale development and allow for the assessment of its impacts on the environment.”

David Abelson, an oil shale policy advisor for the Western Resource Advocates conservation group, said that if history is any indication, there’s a strong likelihood the latest projects won’t prove economically viable.

But he added, “One thing I think we have learned over the years is to proceed cautiously so we don’t repeat what happened in western Colorado in the early ‘80s.”

He said both Shell and Chevron showed a big difference from companies’ past practice in acknowledging failure early on rather than proceeding to the point where shutting down a project is economically devastating.

New approach

He said ExxonMobil and Natural Soda also will operate under a framework governing the second round of leases that requires more reporting regarding protection of air and water quality and other concerns.

“And that is good public policy. That’s the basis for making smart decisions,” he said.

ExxonMobil repeatedly has emphasized the desire to take a prudent, step-by-step approach to its new oil shale undertaking, something reiterated in its development plan.

“It is recognized that development of a commercial(ly) viable in situ oil shale technology will require a paced approach to thoroughly evaluate and optimize technology viability, with appropriate focus on environmental protection, water conservation and responsible land use,” the company said in the plan.

It plans to first conduct an appraisal phase involving drilling one or more test wells to ascertain the oil shale resources within the lease, along with groundwater monitoring wells to do baseline testing of water quality before further work ensues.

It currently estimates a resource of 600 million barrels of oil are contained in the shale within its lease.

The appraisal phase would be followed by three experimental phases, first to establish the ability to install the technology in the test zone, secondly to heat the zone, and then to do a pilot test to determine commercial viability on a field scale.

“ExxonMobil has consistently proposed a staged and deliberate development program that allows for technical advancement while minimizing the potential for environmental impacts,” its plan says.

Natural Soda also is outlining a phased approach in its plan, starting with a monitoring well to be drilled as soon as this year. That would be followed by steps such as building processing facilities, installing heating elements, operating the facilities and expanding and replicating the process over a period of up to nine years.

More oil shale coverage here and here.


Lincoln Park/Cotter Mill: New spill contained onsite

March 11, 2014
Lincoln Park/Cotter Mill superfund site via The Denver Post

Lincoln Park/Cotter Mill superfund site via The Denver Post

From The Pueblo Chieftain (Tracy Harmon):

For the second time in five months, Cotter Corp. Uranium Mill officials have discovered a leak of contaminated water, but both spills reportedly were contained on-site. On Monday, Cotter personnel reported to Colorado Department of Public Health officials a release of greater than 500 gallons of water from the barrier system pump-back pipeline. The water spilled was contaminated groundwater recovered by the barrier system and being pumped back to the facility.

The spill was discovered at 8 a.m. Monday and mill personnel were last on-site at approximately 4:30 p.m. Friday. The spill did not result in contaminated materials leaving the Cotter property. More information will be provided as the investigation continues, according to Deb Shaw, health department program assistant. A similar spill occurred in November when between 4,000 and 9,000 gallons of contaminated water seeped from the same pipeline.

Contaminated water usually is pumped, along with groundwater, to an on-site 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 Pueblo Chieftain (Tracy Harmon):

More details have emerged in connection with a Cotter Corp. Uranium Mill leak of contaminated water which occurred over the weekend south of town. State health officials reported Tuesday that about 20,000 gallons of the contaminated water leaked from the pump-back system pipeline.

“Analytical results show that the water contained 2,840 micrograms per liter of uranium and 3,740 micrograms per liter of molybdenum. For comparison, the groundwater standard in Colorado for uranium is 30 micrograms per liter and for molybdenum is 100 micrograms per liter,” said Deb Shaw, program assistant for the state health department.

At those concentrations of contamination the spill is not reportable to the National Response Center because the quantity is below 10.3 million gallons, Shaw said.

The contamination did not seep off of Cotter property.

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


Aspen: Both sides in the city’s hydropower abandonment case have engaged experts to determine streamflow needs

March 4, 2014
Pelton wheel

Pelton wheel

From Aspen Journalism (Brent Gardner-Smith) via the Aspen Daily News:

A collaborative committee, formed by opposing parties in a lawsuit claiming the city of Aspen has abandoned its rights to divert water from Castle and Maroon creeks for a proposed hydro plant, is making slow progress toward its goals.

When the settlement effort was announced last year after a “stay” was filed in the case, there were hopes that a stream ecologist could be agreed upon and hired early this year to study the proposed hydro plant and the streams and make recommendations about “stream health goals.”

Steve Wickes, a local facilitator guiding the committee and working for both parties in the case, said the committee’s goals were narrowly defined: Can the two sides, with the help of a mutually trusted expert, agree on how much water can be taken out of the creeks?

But before a “request for proposals” can be written to attract a third-party stream ecologist, the committee has agreed that two experts who are working for either side should first review the list of prior studies done on the two rivers to determine where there are information gaps…

To help review the existing studies and draft the request for proposal, the city has hired Bill Miller, the president of Miller Ecological Consultants of Fort Collins, who has been working for the city on river issues since 2009.

And the plaintiffs have hired Richard Hauer, a professor of limnology (freshwater science) at the University of Montana and the director of the Montana Institute on Ecosystems. Hauer appeared at an event in Aspen in 2012 to discuss the importance of keeping water flowing naturally through a river’s ecosystem…

On the committee from the city are Steve Barwick, Aspen’s city manager, Jim True, the city attorney, and David Hornbacher, the head of the city’s utilities and environmental initiatives.

Representing the plaintiffs on the committee are Paul Noto, a water attorney with Patrick, Miller, Kropf and Noto of Aspen, and Maureen Hirsch, a plaintiff in the suit who lives along Castle Creek.

The other plaintiffs include Richard Butera, Bruce Carlson, Christopher Goldsbury, Jr. and four LLCs controlled by Bill Koch. All of the plaintiffs own land and water rights along either Castle or Maroon creeks.

Wickes said the members of the committee have agreed with his suggestion that they not discuss their ongoing work with the media, and instead refer questions to him.

The claim of abandonment against the city was filed in 2011 water court, in case number 11CW130, “Richard T. Butera et al v. the city of Aspen.”

The case was poised to go to trial on Oct. 28, 2013 and both sides filed trial briefs on Oct. 14.

On Oct. 18, however, the parties filed a stay request with the court so they could “cooperate in engaging a qualified independent, neutral, stream ecology expert.”

The ecologist is to study the rivers and the proposed plant and then “determine a bypass amount of water, to be left in the stream by Aspen.”

The opposing parties are then supposed to “use their best efforts to define the stream health goals to be achieved by said amount of water.”

That could mean, as one example, that a flow regime is agreed upon, with varying levels of water being left in the rivers below the city’s diversions at different times of year, depending in part on the natural amount of water in the rivers during any given year.

Such a protocol exists today on Snowmass Creek as it relates to diverting water for snowmaking at the Snowmass Ski Area.

The city is currently proposing to divert up to 27 cubic feet per second of water from Maroon Creek and 25 cfs of water from Castle Creek for the proposed hydro plant, on top of the water it currently diverts from both streams for municipal uses and the existing Maroon Creek hydro plant.

The city also has a policy to keep at least 13.3 cfs in Castle Creek and 14 cfs in Maroon Creek below its diversion dams in order to help protect the rivers’ ecosystems…

The plaintiffs in the suit against the city have told the court they are concerned that if the city diverts more water for hydropower, it could hurt their ability to use their junior water rights on Castle or Maroon creeks. They also claim the city intended to abandon its hydro rights connected to an old hydro plant on Castle Creek, which the city concedes it has not used since 1961.

But the city has denied it ever intended to abandon its water rights and has challenged the plaintiffs’ standing to bring the suit.

Whether the September court dates are needed likely depends on whether the two sides can agree to hire a third-party stream consultant, and then agree to follow their recommendations.

If so, Wickes thinks such an exercise could influence how rivers and streams around the West are managed.

“I’m actually hopeful that when the study is completed, not only will it inform future conversations about the hydroelectric plant, it will inform a wide number of decisions about stream ecology, how we treat our streams, and how things are interconnected,” Wickes said.

More hydroelectric coverage here.


Flaming Gorge Pipeline: Aaron Million still has his eye on the prize #ColoradoRiver

March 2, 2014
Conceptual route for the Flaming Gorge Pipeline -- Graphic via Earth Justice

Conceptual route for the Flaming Gorge Pipeline — Graphic via Earth Justice

From the Green River Star (David Martin):

The Aaron Million water project continues on in the form of a request to the Bureau of the Interior. Million’s request, as published in the Federal Register Feb. 12, calls for a standby contract for the annual reservation of 165,000 care-feet of municipal and industrial water from the Flaming Gorge Reservoir for a transbasin diversion project…

Mayor Hank Castillon, who is a member of Communities Protecting the Green, said he isn’t sure what Million’s plans are with this latest move. Citing his previous denials from the Army Corp of Engineers and FERC, Castillon said the amount Million wants to use has dropped from the initial 250,000 acre feet of water his project would require. Castillon said he expects a battle to occur between the eastern and western sides of the continental divide. Castillon is aware Cheyenne and other cities in eastern Wyoming need water, along with locations in northern Colorado. The problem they need to address, according to Castillon, is the fact that the water isn’t available…

The Sweetwater County Commissioners commented on Million’s proposal Tuesday, voicing their opposition to the idea. Commissioner Wally Johnson said the transfer of water to Colorado isn’t in Sweetwater County’s best interest, saying “it doesn’t matter if it’s Mr. Million or Mr. Disney” making the proposal. Commissioner John Kolb also voiced his opposition, saying opposition to the idea is unanimous between Gov. Matt Mead, the Wyoming County Commissioners Association and the commissioners themselves.

“I’d like to see us not wasting our time on crazy, hare-brained schemes,” Kolb said. “(Transbasin water diversion) doesn’t work.”

More Flaming Gorge Pipeline coverage here and here.


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

March 2, 2014

The hydraulic fracturing water cycle via Western Resource Advocates

The hydraulic fracturing water cycle via Western Resource Advocates


Click here to register to download the report.

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

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

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

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

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

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

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

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

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

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

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

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

More oil and gas coverage here and here.


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

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

Wattenberg Oil and Gas Field via Free Range Longmont

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

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

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

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

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

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

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

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

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

    From the Denver Business Journal (Cathy Proctor):

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

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

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

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

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

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

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

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

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

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

    From the Denver Business Journal (Cathy Proctor):

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

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

    More oil and gas coverage here and here.


    The Tri-County Water Conservation District is bringing on two hydroelectric generation stations at Ridgway Dam

    February 24, 2014
    Ridgway Dam via the USBR

    Ridgway Dam via the USBR

    From The Watch (Samantha Wright):

    Over the past year and a half, two hydropower generators have sprung up at the foot of the dam: a smaller, 800kV generator that should run efficiently on the low, 30-60 cubic-feet-per-second flows in winter, and a larger, 7.2 megawatt generator to run on summertime release levels.

    Next week, on Feb. 24 or 25, the smaller of these two units will be turned on and start producing a steady stream of green electricity, said Mike Berry of Tri-County Water Conservation District, the entity that manages the Ridgway dam and is building the power-generating facility at its base.

    The big generator should be ready for testing by April or so, Berry said. When the project goes fully online later this spring or early summer, it will have a total plant capacity of 8 Megawatts – enough renewable power to run 2,250 homes and take the equivalent, in greenhouse gases, of 4,400 cars off the road.

    Both units will operate during high reservoir releases in the summer, and only the smaller unit will operate during lower wintertime releases.

    Tri-State Generation and Transmission, the wholesale electric supplier for San Miguel Power Association and the Delta-Montrose Electric Association, has built two short transmission lines at the hydropower plant. One will connect to the existing 115kV line running alongside the highway, and another will connect with the generating station.

    Power generation will have to be carefully calibrated in order to maintain historic release patterns at the dam – one of the requirements of the Bureau of Reclamation’s final Environmental Assessment of the project – while maintaining healthy lake levels and maximizing power production.

    In times of drought, the water rights of downstream irrigators, industries and municipalities will trump power generation…

    Power generated at the hydro plant will be sold to two entities: Tri-State, and the City of Aspen. Tri-County WCD first started discussing a partnership with the City of Aspen in 2002. Eventually, this partnership evolved into a Power Purchase Agreement, or PPA.

    In an agreement inked in 2010, Aspen agreed to purchase the wintertime output from the hydropower project, from Oct. 1 through May 31, for 20 years, to help further its goal of powering the city with purely renewable energy. Tri-State has agreed to purchase, for 10 years, the higher summertime output.

    If projections hold up, about 10,000 MWh worth of energy will be “transferred” to the City of Aspen through the PPA annually (although it is doubtful that any of the actual electrons flowing into the grid from the new hydropower plant will travel that far). This amount is not set in concrete – Berry emphasized that there will be annual fluctuations in the amount of power that is delivered to Aspen, depending on a number of factors including whether it is a wet or a dry year, the timing of the spring runoff, and the demands of downstream water rights holders.

    Tri-County WCD has secured $15 million in financing for the project – including a $13 million loan from the Colorado Water Conservation Board, and a $2 million loan from Colorado Water Resources and Power Development Authority – and has sunk an additional $3 million of its own money into the project…

    As the new hydropower plant at Ridgway Reservoir prepares to go online, legislation has been introduced at the state capitol to help streamline development of smaller hydropower projects throughout Colorado.

    Last week, the Colorado House of Representatives overwhelmingly passed HB14-1030 by a vote of 62-3. The bipartisan legislation complements the recent streamlining of federal permitting requirements for small hydro through the Hydropower Regulatory Efficiency Act.

    HB14-1030 was introduced in the House by Reps. Mitsch, Bush and Coram. Senator sponsorship includes Senators Schwartz and Roberts as well as Hodge.

    In essence, the bill “makes it possible to simultaneously complete federal and state review at the same time,” said Kurt Johnson, the president of the Colorado Small Hydro Association. It also seeks to streamline the electrical inspection process for small hydro, using precedents set in the small wind industry decades ago.

    The Senate Agriculture, Natural Resources and Energy Committee will hold a hearing on the pending legislation on Feb. 27.

    More hydroelectric coverage here. More 2014 Colorado legislation coverage here.


    HB14-1030 passes House 63-2 #COleg

    February 23, 2014
    Barker Meadows Dam Construction

    Barker Meadows Dam Construction

    From The Denver Post (Hugh Johnson):

    House Bill 14-1030 mitigates the complexities of the permitting process for hydroelectric facilities that produce 10 megawatts of energy or less. Rep. Diane Mitsch Bush, D-Steamboat Springs, and Rep. Don Coram, R-Montrose, believe their bill will create more jobs in rural communities.

    Mitsch Bush said she knows a rancher living in Meeker who lowered his utility bill $10,000 a year by using hydroelectric systems.

    “It creates jobs, it increases renewables and it enables rural households to lower their electric bill,” Mitsch Bush said of the measure.

    Mitsch Bush believes the bill will make it easier for rural communities to harness the power of hydroelectric facilities by cutting some of the red tape that hinders their creation. She also said in a news release that the bill came about as a result of an inclusive stakeholder process between utilities, small hydroelectric producers, electric contractors and conservation groups.

    House Bill 1030, which passed 63-2, now goes to the Senate.

    More 2014 Colorado Legislation coverage here.


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

    February 22, 2014

    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates


    From The Fort Morgan Times (Rachel Alexander):

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


    ‘Colorado Supreme Court rules against holders of vested water rights inside and outside of an Indian reservation’ — Lexology

    February 20, 2014
    Non-Tributary coalbed methane SW Colorado via the Division of Water Resources

    Non-Tributary coalbed methane SW Colorado via the Division of Water Resources

    From Lexology (Daniel C. Wennogle):

    In 2010 a group of water rights holders in Colorado raised a constitutional challenge to certain rules promulgated by the Colorado State Engineer’s Office regarding the designation of certain ground water resources as “nontributary.” The particular groundwater resources were located, in part on an Indian reservation, and the State Engineer’s determination was a part of an effort to promulgate rules regarding the permitting and regulation of oil and gas wells that extract groundwater in Colorado.**

    The rule in dispute, referred to as the “Fruitland Rule,” was part of a set of “Final Rules” promulgated by the State Engineer under its authority granted by HB 09-1303, codified at C.R.S. § § 37-90137, 37-90-138(2), and 37-92- 308(11) (C.R.S. 2009). The Fruitland Rule related to underground water in a geologic formation called the Fruitland Formation, which extends into the Southern Ute Indian Reservation. The Final Rules, which included the Fruitland Rule, contained a provision stating:

    These rules and regulations shall not be construed to establish the jurisdiction of either the State of Colorado or the Southern Ute Indian Tribe over nontributary ground water within the boundaries of the Southern Ute Indian Reservation as recognized in Pub. L. No 98-290, § 3, 98 Stat. 201 (1984).

    The Plaintiffs argued that the above-quoted provision in the Final Rules effectively divested the State Engineer from having jurisdiction to, among other things, designate water as nontributary in its rulemaking process. The trial court had agreed with this position, and stated that the State Engineer did not prove its authority. The Court of Appeals, however, reversed and held that the State Engineer’s authority came from HB 09-1303, which “authorized the State Engineer to promulgate the Final Rules to delineate nontributory groundwater extracted in oil and gas production throughout the state” of Colorado.

    The Court of Appeals held that nothing about the above- quoted statement in the Final Rules did or could divest the State Engineer of this authority.

    The Court of Appeals noted that its decision would not prevent a constitutional challenge to the Fruitland Rule based upon discriminatory application, if facts warranted.

    More coalbed methane coverage here and here.


    COGCC flood response lessons learned forum recap

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

    Flooded well site September 2013 — Denver Post

    From the Fort Collins Coloradoan (Ryan Maye Handy):

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

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

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

    ‘COMMUNICATION’ CONCERN

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

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

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

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

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

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

    LEAK THEORY INVESTIGATED

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

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

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

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

    THE BLM’S ROLE

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

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

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

    More oil and gas coverage here and here.


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

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

    The hydraulic fracturing water cycle via Western Resource Advocates

    Here’s the release from CERES via CSRWire:

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

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

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

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


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

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

    Denver Basin Aquifers confining unit sands and springs via the USGS

    From The Greeley Tribune (Eric Brown):

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


    Oil shale: An alliance of conservationists are asking Utah to reconsider recent permits for groundwater disposal

    January 25, 2014
    Deep injection well

    Deep injection well

    From The Grand Junction Daily Sentinel (Dennis Webb):

    Conservation groups are asking the state of Utah to reconsider its December approval of a groundwater discharge permit for Red Leaf Resources’ oil shale project.

    The request comes as the company hopes to begin mining shale this spring for a commercial demonstration project in the Bookcliffs about 55 miles south of Vernal.

    The groups on Tuesday filed what’s called a “request for agency action” with the Utah Department of Environmental Quality and the department’s Division of Water Quality. It seeks review and remand of the division’s December decision and an order revoking the permit.

    Attorney Rob Dubuc of Western Resource Advocates filed the action on behalf of Living Rivers, the Grand Canyon Trust, the Southern Utah Wilderness Alliance, Great Old Broads for Wilderness and the Sierra Club.

    In a news release, the groups said the permit “lacks measures to prevent or detect surface or groundwater pollution, in violation of state law.”

    Shelley Silbert, executive director with Great Old Broads for Wilderness, said in the release, “Amazingly, they are not even requiring monitoring of springs, seeps, or groundwater on site.”

    Spokespersons for the Department of Environmental Quality and Red Leaf Resources could not be reached for comment Wednesday. In a December news release, the department said that “leachate produced from mining operations appears to have levels of dissolved contaminants that are comparable to, or less than, the levels in existing groundwater in underlying rocks.”

    It also said rock just below the project area “is of very low permeability and protects underlying aquifers from any contaminants that could possibly be released from the capsule.”

    Red Leaf Resources plans to try out what it calls a capsule approach in which it will excavate shale from a pit, install heaters and collection pipes, replace the shale and heat it to produce oil. The groundwater permit applies to a test capsule, and if the company wants to build additional ones for commercial production it would have to seek a major modification to the permit.

    The conservation groups’ challenge of the permit says a planned 3-foot-thick liner made of up shale mixed with clay is inadequate. It says the Division of Water Quality determined groundwater just beneath the mine site doesn’t quality for protection because it is not usable, but in fact the division is required to protect all groundwater from contamination.

    Meanwhile, a British Company, The Oil Mining Co (TOMCO), is moving ahead with plans to implement Red Leaf’s kerogen recovery process just west of the Colorado Border. Here’s a report from Gary Harmon writing for The Grand Junction Daily Sentinel:

    A British company filed papers in Utah to begin mining oil shale on land just west of the Colorado state line. TomCo submitted a notice of intent to begin mining on 2,919 acres in Uintah County for shale, which it plans to roast in large earthen capsules to release oil.

    Red Leaf Resources, which owns the technology that TomCo plans to use, last month received a groundwater discharge permit for its operation, and TomCo said it is working to obtain a similar permit for its leases, which are on state property.

    TomCo, which is an acronym for The Oil Mining Co., anticipates tapping the leases for 126 million barrels of oil on what is known as the Holliday Block lease. TomCo licensed the Red Leaf technology, in which oil shale is excavated and the pit is lined with a network of pipes. The crushed shale is then replaced into the pit and covered over, then heated by the network of pipes beneath, to the point at which the oil breaks free of the surrounding rock and is collected with another network of pipes. Once the oil has been recovered, the material is left in place beneath its covering.

    The EcoShale In-Capsule Process is expected to produce up to 9,800 barrels of oil per day on TomCo’s leases.

    TomCo said it hoped the Utah Division of Oil Gas and Mining would approve the permit for mining in the middle of this year, and then open the matter for a 30-day comment period.

    Red Leaf, meanwhile, expects to begin mining shale this spring for a commercial demonstration project the company hopes will allow it to tap as many as 600 million barrels of oil at the rate of 9,800 barrels per day.

    Red Leaf Resources expects it to take a year to construct its first test capsule and that it will take into next year before oil will be recovered.

    Red Leaf’s site is on Seep Ridge, about 15 miles southwest of the TomCo holdings.

    More oil shale coverage here and here.


    Loveland: Senior center utilizes geothermal for heating and cooling

    January 23, 2014
    Geothermal exchange via Top Alternative Energy Sources

    Geothermal exchange via Top Alternative Energy Sources

    From the Loveland Reporter-Herald (Jessica Maher):

    In most buildings, the center of heating operations is called the boiler room, but the three-story Mirasol Phase II building is unlike most buildings, and is the first of its kind in Loveland. There are no water boilers, no air conditioning units. Instead, the 60 units in the building are heated and cooled by a geothermal exchange system and hot water to faucets comes from a solar collector system on the roof…

    So how does it work? Temperatures below the earth’s surface remain unchanged throughout the year. By capturing that water and pumping it through a buried loop system, a heat exchange either cools the water down or heats it up. There are five closed loop heat exchange systems located in the basement of the Mirasol Phase II building, and the thermostat inside each unit dictates the action of the heat exchange…

    Geothermal exchange systems can also be used to heat and cool homes but carry a hefty price tag, largely because of the need for wells to access the underground water. At Mirasol, 36 holes 500 feet deep were drilled where the parking lot is currently located, according to Joe Boeckenstedt of Pinkard Construction Co., which was the general contractor for the Phase II project.

    Of the $13.4 million to build Mirasol Phase II, the solar panels and the geothermal exchange cost about $460,000, according to Loveland Housing Authority maintenance supervisor Bill Rumley, who said the agency expects to see a return on investment for the alternative energies within a decade.

    More geothermal coverage here.


    5.8 MW hydroelectric generation station under design for the North Outlet Works at Pueblo Dam

    January 19, 2014
    The new north outlet works at Pueblo Dam -- Photo/MWH Global

    The new north outlet works at Pueblo Dam — Photo/MWH Global

    From The Pueblo Chieftain (Chris Woodka):

    A small hydroelectric generation project at Pueblo Dam is moving into a preliminary design phase. The proposal would create a 5.8 megawatt hydroelectric generator at the recently completed North Outlet Works, which was constructed as part of the Southern Delivery System. It would generate about 21 million kilowatt-hours annually, said Kevin Meador, an engineer with the Southeastern Colorado Water Conservancy District at the board’s meeting Thursday.

    “We started this process in February 2012, and we have to finish the application by August,” Meador said. “We’ve got the pedal to the metal and we’re pushing to get these tasks done.”

    The Southeastern district has partnered with Colorado Springs Utilities and the Pueblo Board of Water Works in an agreement with the Bureau of Reclamation to build the hydro plant.

    Power likely would be sold to Black Hills Energy and then to other users. Details are being negotiated.

    Right now, the district is working through planning, permitting and technical issues, Meador said.

    More hydroelectric coverage here and here.


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

    January 7, 2014
    Wattenburg Field

    Wattenburg Field

    From The Greeley Tribune (Sharon Dunn):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here.


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

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

    Debeque phacelia via the Center for Native Ecosystems

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

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

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

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

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

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

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

    Black Hills also has been involved on the scene.

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

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

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

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

    More oil and gas coverage here and here.


    Pagosa Springs hopes to tap geothermal for electrical generation

    December 31, 2013
    Geothermal Electrical Generation concept -- via the British Geological Survey

    Geothermal Electrical Generation concept — via the British Geological Survey

    From the Pagosa Sun (Randi Pierce):

    The Town of Pagosa Springs council met in executive session with town attorney Bob Cole last Thursday, Dec. 19, with the topic of conversation centering on matters involving funding for a possible geothermal electric utility. According to town manager David Mitchem, council gave Cole instruction during the executive session. Mitchem said that the executive session did, “move the process forward,” but that no decisions were made at the meeting. A decision, Mitchem indicated, is expected in the next three weeks to a month…

    Mayor Ross Aragon said the geothermal utility discussed Dec. 19 was the same contract the county [Archuletta] earmarked money for, and said the town and county have been and are expected to continue to be on par with each other in contributing to the project.

    In 2013, both the town and the county pledged $65,000 toward research on geothermal resources and the possibility of using a geothermal resource to create power. That exploration work is being done by Pagosa Verde, LLC, headed by Jerry Smith.

    More geothermal coverage here and here.


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

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

    Directional drilling and hydraulic fracturing graphic via Al Granberg

    From the Northern Colorado Business Report (Steve Lynn):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

    December 19, 2013
    Colorado River near De Beque

    Colorado River near De Beque

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

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

    A containment berm around the pad was built Tuesday.

    Fracked recently

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

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

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

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

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

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

    Path to surface

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

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

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

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

    More oil and gas coverage here and here.


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

    December 17, 2013
    Colorado River near De Beque

    Colorado River near De Beque

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

    Williams Energy hydraulic fracturing operation near Rulison via The Denver Post

    Here’s the release from the University of Missouri:

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

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

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

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

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

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

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

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

    From the Epoch Times (Sarah Matheson):

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


    The State of Colorado Coal

    December 15, 2013

    Originally posted on Your Water Colorado Blog:

    The State of Colorado Coal

    CFWE’s most recent Headwaters magazine on energy took a look at coal in Colorado.  Writer Josh Zaffos interviewed Jack Ihle, Xcel Energy’s director of environmental policy about the switch from coal to natural gas…

    HW 32 coversmallEven with the rush toward natural gas, the push for renewables, and potential carbon emissions regulations, Ihle says Xcel—and Colorado—aren’t likely to fully divest from coal. Xcel is upgrading pollution controls at several coal plants to further limit smog and air pollution and keep the plants running and in compliance with Clean Air Act regulations. “We see value in balance even as certain drivers like emissions regulations will cause us to look harder at cleaner resources,” Ihle says. “Coal has been a very cost-effective resource and price-stable for a long time, and we’ll look for ways to make it as clean as we can.”

    And the use of coal in…

    View original 200 more words


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

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

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

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

    December 11, 2013
    Groundwater movement via the USGS

    Groundwater movement via the USGS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

    The hydraulic fracturing water cycle via Western Resource Advocates

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

    More oil and gas coverage here and here.


    Funding Opportunity Available to Increase Water Conservation or Improve Water Supply Sustainability

    December 9, 2013
    Upper Colorado River Endangered Fish Recovery Program

    Upper Colorado River Endangered Fish Recovery Program

    Here’s the release from the Bureau of Reclamation (Peter Soeth):

    The Bureau of Reclamation is making funding available through its WaterSMART program to support new Water and Energy Efficiency Grant projects. Proposals are being sought from states, Indian tribes, irrigation districts, water districts and other organizations with water or power delivery authority to partner with Reclamation on projects that increase water conservation or result in other improvements that address water supply sustainability in the West.

    The funding opportunity announcement is available at http://www.grants.gov using funding opportunity number R14AS00001.

    Applications may be submitted to one of two funding groups:

  • Funding Group I: Up to $300,000 will be available for smaller projects that may take up to two years to complete. It is expected that a majority of awards will be made in this funding group.
  • Funding Group II: Up to $1,000,000 will be available for larger, phased projects that will take up to three years to complete. No more than $500,000 in federal funds will be provided within a given fiscal year to complete each phase. This will provide an opportunity for larger, multiple-year projects to receive some funding in the first year without having to compete for funding in the second and third years.
  • Proposals must seek to conserve and use water more efficiently, increase the use of renewable energy, improve energy efficiency, benefit endangered and threatened species, facilitate water markets, carry out activities to address climate-related impacts on water or prevent any water-related crisis or conflict. To view examples of previous successful applications, including projects with a wide-range of eligible activities, please visit http://www.usbr.gov/watersmart/weeg.

    In 2013, Reclamation awarded more than $20 million for 44 Water and Energy Efficiency Grants. These projects were estimated to save about 100,000 acre-feet of water per year — enough water to serve a population of about 400,000 people.

    The WaterSMART Program focuses on improving water conservation, sustainability and helping water resource managers make sound decisions about water use. It identifies strategies to ensure that this and future generations will have sufficient supplies of clean water for drinking, economic activities, recreation and ecosystem health. The program also identifies adaptive measures to address climate change and its impact on future water demands.

    Proposals must be submitted as indicated on http://www.grants.gov by 4 p.m., Mountain Standard Time, Jan. 23, 2014. It is anticipated that awards will be made this spring.

    To learn more about WaterSMART please visit http://www.usbr.gov/WaterSMART.

    More Bureau of Reclamation coverage here.


    ‘I firmly believe we will some day see oil shale become a reality’ — Glenn Vawter

    December 9, 2013
    Oil shale deposits Colorado, Wyoming and Utah

    Oil shale deposits Colorado, Wyoming and Utah

    Here’s a recap of a presentation about the future of oil shale at Rifle Community College on November 19, written by Mike McKibbin for the Rifle Citizen-Telegram. Here’s an excerpt:

    The long sought-after petroleum product is infamous for its long-held promise of economic benefits, high-paying jobs and what sounds like an almost non-ending supply to meet America’s growing energy needs.

    But while that reality has proved elusive for centuries, some, such as Glenn Vawter, executive director of the National Oil Shale Association, are ever optimistic. The nonprofit group promotes factual information about oil shale…

    “I firmly believe we will some day see oil shale become a reality, and 75 percent of the world’s oil shale is in the U.S.,” Vawter said. “It’s already been produced commercially for decades in Brazil, Estonia and China.”[...]

    The underground mining processes used by companies such as Unocal, which produced 10,000 barrels of shale oil a day during its limited operation, totaled five-million barrels and was proven feasible, Vawter said.

    The in-situ process that companies are now developing has the advantage of no mining, Vawter said.

    Currently, research, design and development projects on Bureau of Land Management leases are underway by American Shale Oil, ExxonMobil and Natural Soda in western Garfield and Rio Blanco counties, along with Red Leaf Resources and Enefit American Oil in Utah.

    “It was discouraging that Shell recently announced they were pulling out,” Vawter said. “But Red Leaf plans to start commercial production of up to 10,000 barrels a day in Utah next year. There’s a lot going on over there in Utah. They have policies that are more welcoming to energy and oil shale industries.”

    Enefit has operated shale oil projects in Estonia for decades, Vawter pointed out, with a proven technology.

    And Vawter pointed to a recent U.S. Geological Survey estimate of 4.3 trillion barrels of shale oil in Colorado, Wyoming and Utah. Of that, Vawter said up to 1.14 billion barrels are now considered recoverable. That is up to six times more than the total oil reserves in Saudi Arabia and significantly more than known U.S. conventional oil resources.

    “There are places in the Piceance Basin that are estimated to have one million barrels in just one acre,” Vawter said. “The Piceance Basin could have up to 152 trillion barrels.”

    Water used in the oil shale process has often been cited by opponents as a large hurdle, Vawter said, but current processes for a 1.5 million barrel per day project would require just 2 to 3 percent of an estimated 8 million acre feet per year of water in the Colorado River.

    “That’s not an insignificant amount, but it’s far less than some still believe,” he said…

    More oil shale coverage here and here.


    Allen Best: The risk is that water may not be there some years. Or a lot of years. #ColoradoRiver #COWaterPlan

    December 8, 2013
    Colorado River Basin including out of basin demands -- Graphic/USBR

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

    Here’s a guest column about the possible effects of low flow into Lake Powell, written by Allen Best that is running in The Denver Post:

    Skimpy-clothed people splashing amid the red sandstone canyons of Utah define our images of Lake Powell. But six months ago, engineers and water officials from the seven states of the Colorado River Basin quietly met in Santa Fe to consider a more serious possibility: Continued drought could leave too little water in the reservoir for the eight giant turbines in Glen Canyon Dam to produce electricity.

    The turbines can produce great amounts of electricity, 1,320 megawatts at full throttle, or roughly twice as much as the Cherokee power plants north of downtown Denver. In practice, the volume runs half that. Most rural electrical cooperatives in the Rocky Mountains states buy power from Glen Canyon through their wholesale supplier, Tri-State Generation and Transmission, as does Xcel Energy.

    The average $150 million in revenues from this power generation are a federal cash cow. The money paid for construction of Glen Canyon and other dams authorized by Congress in 1958, but also funds salinity control such as in the Paradox Valley west of Telluride and the endangered fish recovery program, including the 15-mile segment of the Colorado River from Palisade into Grand Junction.

    What if the Colorado River Basin has another bum year for snow? Inflows into Lake Powell during the last two years were 25 percent and then 47 percent as compared to the rolling 30-year average. If the years 2001-2003 were about as bad, here’s the difference: in 1999, Lake Powell was full. In recent years, despite a few big snow years, the reservoir has often displayed big “bathtub rings.” Right now, it’s 43 percent of capacity. Drought has been our more steady companion of the 21st century. This extended drought, in duration and depth, surpasses any since gauges were installed in the Colorado River Basin in 1906. However, extensive study of tree rings in the basin suggest worse and even longer drought sequences have occurred in the Southwest, especially 900 years ago. Whether this drought will also continue is anybody’s guess, but Colorado and other states decided it best to plan in case it does. On Thursday, at a meeting in Golden, officials for the first time shared some of their pending strategies.

    John McClow of Gunnison, who is Colorado’s representative on the Upper Basin Compact Commission, said if snow lags again this winter, reservoirs on two tributary rivers — Flaming Gorge Reservoir on the Green and Navajo on the San Juan — can be tapped to allow the Glen Canyon generators to produce electricity. The trio of reservoirs near Gunnison — Blue Mesa, Curecanti and Morrow Point — are already too low to be of much value, he said. Other federal reservoirs — Ruedi near Basalt, Green Mountain near Kremmling, and Granby — are not part of the same system.

    If the drought deepens, other small-gain strategies can be deployed: stepped-up cloud seeding and more aggressive efforts to remove water-gobbling salt cedar, i.e., tamarisk, an invasive species, from river banks. Still other strategies being weighed include idling of agriculture land —even crimping of some transmountain diversions, which normally divert 450,000 to 600,000 acre-feet of water each year in Colorado from the Colorado River Basin to the Front Range and eastern plains. But whatever strategies are adopted, McClow stressed, Colorado alone wouldn’t bear the burden.

    Why not just forego the electricity? That remains an option, but it would invite the federal government to become a decision-maker in water matters. Almost fiercely, the states prefer to chart their own course.

    This newest twist at Lake Powell is different from a curtailment under the 1922 Colorado River Water Compact. Colorado and other upper-basin states are in no imminent danger of failing to deliver the water specified for delivery at Lee’s Ferry, at the head of the Grand Canyon, as required by the compact, said McClow, nor is that likely to occur at any time soon. For that matter, the prospect of a Lake Powell “dead pool”- too little water to generate power – isn’t high probability next summer. Computer modeling suggets a 5 to 7 percent chance.

    Yet this sharpening razor’s edge at between water supply and demand may be instructive. At one level it represents the intersection of water and energy. In California, one-fifth of all energy is devoted to moving around water. In Colorado, it’s lower. But everywhere, particularly the West, water is dependent on energy, and producing energy is dependent on water.

    More immediately, this reminds us of risk. Some people think that Colorado’s growing urban areas need to develop the state’s remaining raw water supplies from the Colorado River Basin. The risk is that water may not be there some years. Or a lot of years. We just don’t know.

    Allen Best of Arvada publishes Mountain Town News (http://http://mountaintownnews.net/).

    More Colorado River Basin coverage here and here.


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

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

    Directional drilling and hydraulic fracturing graphic via Al Granberg

    Click here to read the announcement.

    More oil and gas coverage here and here.


    Many eyes are on the 1,250 cfs Shoshone right #ColoradoRiver

    December 7, 2013
    Shoshone Falls hydroelectric generation station via USGenWeb

    Shoshone Falls hydroelectric generation station via USGenWeb

    From KUNC (Maeve Conran):

    There’s popular launch site for rafters a few miles east of Glenwood Springs. It’s right beneath Interstate 70, and is in front of an old tan brick building, set back into the canyon wall. Chances are, highway drivers might not even see this place. But it’s the reason the rafting is so good here all the time.

    The Shoshone Hydro Plant, built to harness Colorado River water and turn it into 15 megawatts of electricity has two nine-foot tall turbines, which were manufactured and installed in 1906 and are still humming along today. It’s the linchpin of the river, according to Jim Pokrandt, Education and Outreach Specialist with the Colorado River District.

    “Not because of producing electricity,” said Pokrandt. “But because it takes water to produce that electricity, and that water is supplied via a 1902 water right for 1250 CFS. That’s the biggest, oldest water right on the river.”

    1250 CFS, or cubic feet per second, is a lot of water. It’s labeled “non-consumptive use,” which means the water is not taken out of the river to grow food or flush toilets. It flows onto the turbines and right back out—sustaining an important part of the local economy: rafting, kayaking and fishing.

    Maintaining that primary water right is critical to keeping flow levels adequate for the turbines, and to help create rapids.

    Pokrandt says Shoshone also helps towns that draw water from the river, because the high flows the plant requires helps keep the water cleaner.

    “Silt, Rifle, Parachute and Clifton are all taking drinking water out of the Colorado River,” said Pokrandt. “The greater the flow, the less intensive you have to treat the water.”

    Agriculture in the Grand Valley also benefits from Shoshone’s water right.

    Mel Rettig is a vegetable and fruit farmer in Palisade, about 80 miles southwest of the Shoshone plant. Rettig says the higher flows due to Shoshone help keep salinity levels low…

    Some West Slope water irrigators who depend on Shoshone would love to buy the plant and its water right to protect the interests of the Grand Valley. A 15-megawatt output is small by today’s standards — modern power plants produce hundreds of megawatts. But Xcel continues to invest millions in maintenance at the plant and the utility says they have no plans to sell Shoshone or its water rights…

    “This little, old, two turbine, 15-megawatt 1905 vintage power plant in Glenwood Canyon,” said Pokrandt. “It doesn’t look like much but it’s a big dog on the river.”

    More Colorado River Basin coverage here and here.


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

    December 6, 2013
    Groundwater monitoring well

    Groundwater monitoring well

    From The Greeley Tribune (Sharon Dunn):

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

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


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

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

    Colorado Water Plan website screen shot November 1, 2013

    From The Pueblo Chieftain (Chris Woodka):

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

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

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

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

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

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

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

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

    More Colorado Water Plan coverage here.


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

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

    New supply development concepts via the Front Range roundtables

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

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

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

    Read the rest of this entry »


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