Pure Cycle Corporation Announces Second Fiscal Quarter 2014 Financial Results

April 14, 2014

waterfromtap

Here’s the release from Pure Cycle Water:

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

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

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

More infrastructure coverage here.


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

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

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

From the Glenwood Springs Post Independent (John Stroud):

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

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

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

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

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

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

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

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

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

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

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

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

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

From the Vail Daily (Melanie Wong):

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

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

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

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

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

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

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

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

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

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

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

More Colorado River Basin coverage here.


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

April 5, 2014
San Luis Valley Groundwater

San Luis Valley Groundwater

From The Pueblo Chieftain (Robert Boczkiewicz):

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

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

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

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

BLM said that it is reviewing the lawsuit.

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

More Rio Grande River Basin coverage here.


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

April 3, 2014

chemistryglassware

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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

April 2, 2014

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

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

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

From the Denver Business Journal (Cathy Proctor):

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

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

From the Northern Colorado Business Report (Jerd Smith):

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

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

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

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

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

From the Associated Press via The Colorado Springs Gazette:

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

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

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

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

More oil and gas coverage here and here.


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

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

Flooded well site September 2013 — Denver Post

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

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

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

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

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

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

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

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

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

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

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

From The Denver Post (Mark Jaffe):

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

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

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

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

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

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

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

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

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

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

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

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

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

More oil and gas coverage here and here.


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

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

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

From The Denver Post (Mark Jaffe):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

More oil and gas coverage here and here.


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

March 2, 2014

The hydraulic fracturing water cycle via Western Resource Advocates

The hydraulic fracturing water cycle via Western Resource Advocates


Click here to register to download the report.

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

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

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

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

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

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

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

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

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

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

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

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

More oil and gas coverage here and here.


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

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

Wattenberg Oil and Gas Field via Free Range Longmont

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

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

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

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

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

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

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

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

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

    From the Denver Business Journal (Cathy Proctor):

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

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

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

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

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

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

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

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

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

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

    From the Denver Business Journal (Cathy Proctor):

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

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

    More oil and gas coverage here and here.


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

    February 23, 2014

    From The Pueblo Chieftain (Chris Woodka):

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

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

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

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

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

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

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

    From the USDA:

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

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

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

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

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

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

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

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

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

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

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


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

    February 22, 2014

    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates


    From The Fort Morgan Times (Rachel Alexander):

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


    COGCC flood response lessons learned forum recap

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

    Flooded well site September 2013 — Denver Post

    From the Fort Collins Coloradoan (Ryan Maye Handy):

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

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

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

    ‘COMMUNICATION’ CONCERN

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

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

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

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

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

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

    LEAK THEORY INVESTIGATED

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

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

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

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

    THE BLM’S ROLE

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

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

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

    More oil and gas coverage here and here.


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

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

    The hydraulic fracturing water cycle via Western Resource Advocates

    Here’s the release from CERES via CSRWire:

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

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

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

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


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

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

    Denver Basin Aquifers confining unit sands and springs via the USGS

    From The Greeley Tribune (Eric Brown):

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

    January 7, 2014
    Wattenburg Field

    Wattenburg Field

    From The Greeley Tribune (Sharon Dunn):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here.


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

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

    Debeque phacelia via the Center for Native Ecosystems

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

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

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

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

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

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

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

    Black Hills also has been involved on the scene.

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

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

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

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

    More oil and gas coverage here and here.


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

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

    Directional drilling and hydraulic fracturing graphic via Al Granberg

    From the Northern Colorado Business Report (Steve Lynn):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

    December 19, 2013
    Colorado River near De Beque

    Colorado River near De Beque

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

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

    A containment berm around the pad was built Tuesday.

    Fracked recently

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

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

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

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

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

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

    Path to surface

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

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

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

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

    More oil and gas coverage here and here.


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

    December 17, 2013
    Colorado River near De Beque

    Colorado River near De Beque

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

    Williams Energy hydraulic fracturing operation near Rulison via The Denver Post

    Here’s the release from the University of Missouri:

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

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

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

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

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

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

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

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

    From the Epoch Times (Sarah Matheson):

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

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

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

    December 11, 2013
    Groundwater movement via the USGS

    Groundwater movement via the USGS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

    The hydraulic fracturing water cycle via Western Resource Advocates

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

    More oil and gas coverage here and here.


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

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

    Directional drilling and hydraulic fracturing graphic via Al Granberg

    Click here to read the announcement.

    More oil and gas coverage here and here.


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

    December 6, 2013
    Groundwater monitoring well

    Groundwater monitoring well

    From The Greeley Tribune (Sharon Dunn):

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

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


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

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

    Colorado Water Plan website screen shot November 1, 2013

    From The Pueblo Chieftain (Chris Woodka):

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

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

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

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

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

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

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

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

    More Colorado Water Plan coverage here.


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

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

    New supply development concepts via the Front Range roundtables

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

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

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

    Read the rest of this entry »


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

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

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

    From The Colorado Statesman (Peter Marcus):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

    Directional drilling and hydraulic fracturing graphic via Al Granberg

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

    November 20, 2013

    From The Denver Post (Allison Sherry):

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

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

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

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

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

    More oil and gas coverage here and here.


    Hydraulic fracturing, water and Colorado

    November 19, 2013

    Originally posted on Your Water Colorado Blog:

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

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

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

    View original 1,967 more words


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    From The Denver Post (Bruce Finley):

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

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

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

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

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

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

    Under the rules, companies would have to:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    From the Denver Business Journal (Cathy Proctor):

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

    Directional drilling from one well site via the National Forest Service

    From email from Governor Hickenlooper’s office:

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

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

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

    More oil and gas coverage here and here.


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

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

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

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

    Wattenberg Oil and Gas Field via Free Range Longmont

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

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

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

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

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

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

    More oil and gas coverage here and here.


    A look at oil and gas water recycling and deep disposal

    November 15, 2013
    Deep injection well

    Deep injection well

    From the Northern Colorado Business Report (Steve Lynn):

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


    Broomfield fracking ban approved after outstanding ballots counted

    November 15, 2013

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


    2013 Yampa Basin Water Forum recap

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

    Yampa River Basin via the Colorado Geological Survey

    From Steamboat Today (Michael Schrantz):

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

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

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

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

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

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

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

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

    More Yampa River Basin coverage here and here.


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

    November 11, 2013
    Durango

    Durango

    From The Durango Herald (Brandon Mathis):

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

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

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

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

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

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

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

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

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

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

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

    More 2014 Colorado Election coverage here.


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

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

    Dilbert’s company embraces hydraulic fracturing for competitive advantage

    From the Denver Business Journal (Cathy Proctor):

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

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

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

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

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

    The four initiatives:

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

    More oil and gas coverage here and here.


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

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

    Spill via Princess Sparkle Pony’s Photo Blog

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


    DBJ Special Report: The fracking debate

    November 4, 2013
    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates

    Click here to go to the Denver Business Journal’s special report page for hydraulic fracturing. Here’s the introduction:

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

    DJ Basin Exploration via the Oil and Gas Journal

    From The Greeley Tribune (Sharon Dunn):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

    October 20, 2013

    Flooded well site September 2013 -- Denver Post

    Flooded well site September 2013 — Denver Post

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

    INITIAL ALARM

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

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

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

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

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

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

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

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

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

    UNFINISHED BUSINESS

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

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

    Pete Maysmith, executive director of Conservation Colorado, agrees.

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

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

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

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

    WELL DAMAGE SLIGHT

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

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

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

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

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

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

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

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

    WITHHOLDING JUDGMENT

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

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

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

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

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

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

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

    From The Grand Junction Daily Sentinel (Dennis Webb):

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

    The hydraulic fracturing water cycle via Western Resource Advocates

    From the Northern Colorado Business Report (Steve Lynn):

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

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

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

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

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

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

    More oil and gas coverage here and here.


    Colorado Foundation for Water Education Energy Tour November 8

    October 20, 2013

    Directional drilling from one well site via the National Forest Service

    Directional drilling from one well site via the National Forest Service


    Click here for the pitch.


    Water used for hydraulic fracturing poses treatment and disposal problems

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

    The hydraulic fracturing water cycle via Western Resource Advocates

    From The National Geographic (Bill Chameides):

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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

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

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

    From The Denver Post (Mark Jaffe):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    More oil and gas coverage here and here.


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