— Bill McKibben (@billmckibben) January 9, 2015
From The Grand Junction Daily Sentinel (Dennis Webb):
Energy companies will face fines generally ranging from $200 to $15,000 per day of rules violation under a new penalty structure passed by the Colorado Oil and Gas Conservation Commission Monday.
The agency adopted the new fines structure after the state legislature last year raised the daily penalty limit from $1,000 to $15,000 for each violation. It also was responding to an order by Gov. John Hickenlooper to review its enforcement and penalty assessment procedures.
Monday’s action came on a 5-3 vote, with some commissioners worrying that the fines established for less-severe violations are too hefty.
“I think it’s going to create issues,” Commissioner DeAnn Craig said.
She fears the potential for higher fines could lead to some smaller companies deciding to abandon lower-producing wells, leaving the responsibility of plugging them to the state.
Commissioner Mike King, also executive director of the state Department of Natural Resources, said while abandonment of wells is a concern for the state, it’s a separate issue from fines and involves companies showing “no responsibility whatsoever.”
Commissioner Rich Alward of Grand Junction told fellow commissioners the higher fines will transfer the risks of spills from state residents to the companies.
“Operators will find ways to avoid violating our rules if there are real consequences,” he said.
The newly adopted schedule establishes standard penalties that include a $15,000 daily fine in the case of violations that create a high risk of health, safety and environmental impacts, and in which those impacts actually occur. The $200 fine is for violations of paperwork or other rules presenting no direct risk of causing harm, and in which no impacts occur. Commission staff had recommended a $500 standard fine for these violations.
The majority of commissioners stood by the staff–recommended fines for other lesser-level violations, however, despite a call by a few of them for lower fines.
With the exception of the $15,000 worst-offense fine that can go no higher under state law, the newly established fine amounts can be raised or lowered based on aggravating factors such as knowing and willful misconduct and mitigating ones such as self-reporting of a violation.
Craig argued that the high-end standard penalty should be less than $15,000, which should be reserved for egregious cases where the commission would be trying to make a point in imposing the maximum. With the commission’s action, she said, there are likely to be a number of instances where mitigating factors drive fines down from $15,000, and she worries about how that will be perceived.
“Is the public going to feel that we’re cutting too much slack to the industry? It may not be the case, but it may be an optics issue,” she said.
But Alward said he doesn’t think there would be that many instances where violations would meet the criteria for a $15,000 fine to begin with. And he said such a fine is appropriate for such worst-case violations.
“That’s exactly where we want to throw the book at somebody,” he said.
The new rules give the commission director latitude in some instances to waive fines altogether. But attorneys for environmental groups argued that fines should be required in the case of violations creating a high risk of health, safety and environmental impacts even if they don’t occur. Commissioners on Monday agreed, prohibiting the director from waiving fines in such cases.
Until last year’s legislation, the commission also had been limited to a maximum cumulative fine of $10,000 per violation, regardless of the number of days involved, except in circumstances including where a significant impact to health, safety or welfare has occurred. That cap no longer exists under the new rules. In an interview Monday, Alward said that means companies will have motivation to address violations to keep fines from continuing to go up after 10 days.
“I’m really pleased that we’re going to have a pretty rigorous penalty rule now and I really hope that it has the deterrence effect — especially that it encourages operators to address problems immediately and get things back on the right page,” he said.
The Colorado Oil and Gas Association industry group supported last year’s legislation. But in a hearing last month, some industry representatives worried that with the commission able to determine that a violation continued much longer than 10 days, companies could be hit with much higher fines that in some cases could shut them down.
Association official Doug Flanders said in a statement Monday, “Overall, we’re on the same page with the COGCC and have the same goal, which is to ensure consistency, clarity and certainty as to how the new rules will be enforced, how penalties will be calculated, and how both will (be) applied to all stakeholders.
“Colorado already has the strongest oil and gas rules in the country and continues to hold the industry to the highest standard in the nation,” Flanders continued. “We expect that the COGCC will implement the new rules in a way that protects stakeholders while providing a predictable business environment.”
COGCC director Matt Lepore said in a news release, “This is yet another step forward in our long-running and continuing work to build a regulatory approach that stands as a model across the country.”
The COGCC noted in that release that since 2011 Hickenlooper’s administration also “has crafted rules to increase setbacks, reduce nuisance impacts, protect groundwater, cut emissions, disclose hydraulic fracturing chemicals and increase spill reporting.”
Jon Goldin-Dubois, resident of the Western Resource Advocates conservation group, said in a news release, “We applaud the Commission passing these stronger standards with consistent mandatory penalties for significant offenses. This is a step forward in holding the industry accountable. It is critical that Coloradans have certainty that their communities, health, clean air, and water are protected. Residents across Colorado have been looking for more oversight and these new rules are important progress.”
More oil and gas coverage here.
New rules eliminate penalty cap
FRISCO — Daily penalties for fracking leaks and spills, or other environmentally dangerous accidents associated with fossil fuel development will go up to as much as $15,000 per day in Colorado, under new rules adopted this week by the Colorado Oil and Gas Conservation Commission.The beefed-up penalty structure also does away with a $10,000 penalty cap for each violation.
View original post 287 more words
From The Greeley Tribune (Allison Dyer Bluemel):
Companies in drought areas have begun looking at liquefied petroleum gas gel for hydraulic fracturing as a way to reduce dependence on already-scarce water supplies.
Gas gel presents a potentially viable replacement to the millions of gallons of water used in the fracking process at each well site, said John McLennen, an associate professor of chemical engineering at the University of Utah.
Also referred to as dry fracking, the process does not involve water. Instead, highly pressurized gas is injected directly into a formation to crack the rock.
“Conceptually it’s a great idea. People are definitely looking for water substitutes,” he said.
While the gel reduces the use of water dramatically and can benefit both producers and operators, many companies have not incorporated the gel into their operations due to the explosive and flammable nature of propane, McLennen said.
Under the Colorado Oil and Gas Association, companies have the autonomy to make individual technology related decisions, spokesperson Dan Haley said.
“There are a number of different techniques that Colorado companies use in oil and gas development,” said Doug Flanders, COGA director of policy and external affairs. “The most important factor when deciding which technique works best is the type of formation where you’re trying to extract oil or gas.”
McLennen said that the advantages to gel use have yet to be fully researched or substantiated. However, it has the potential to drastically reduce water use in areas were the resource is expensive because of drought or high transportation costs.
On average, each well requires between 1 million and 5 million gallons of water during fracking operations.
In Colorado, hydraulic fracturing operations account for approximately .08 percent of water consumed statewide, with companies working on ways to re-use and recycle water annually, Haley said.
The gel would help to solve the challenge of recycling flow-back water from wells, said Jason Munro, president of GASFRAC based in Calgary, Alberta.
Oil and gas companies dispose of water that cannot be recycled, using Colorado Oil and Gas Conservation Commission guidelines where approximately 60 percent goes into underground injection wells, 20 percent is managed in evaporation ponds, and the remaining 20 percent goes into surface waters under permits by the Colorado Department of Public Health and Environment.
The injection of water through an underground injection control well requires certain casing and cementing, monthly reporting on materials and volumes injected and pressure tests to ensure the waste stays in the designated area.
The majority of evaporation pits sit in the Raton Basin in southern Colorado, and some water is used on roads for dust suppression if it does not meet the necessary parameters for disposal in streams or rivers that are drinking sources.
Companies reuse recycled water most if the surrounding area has high demand for it in other operations; otherwise they dispose of the production water.
In the average mixture, water and sand make up roughly 99.5 percent of the mix with the additional 0.5 percent consisting of chemicals that assist the flow of sand into the formation, according to COGA.
In addition to water and sand, COGA reports that hydraulic fracturing mixtures include gelling agents to make fluids thicker cross linkers to continue to thicken fluids, breakers to thin fluids to ensure production after time, surfactants to improve production and recovery, biocides to control bacteria, and additional additives to address other challenges.
Liquefied petroleum’s lower specific gravity decreases the volume necessary in operations by half which can reduce truck traffic by up to 90 percent and eliminates the need for post stimulation transport, Munro said.
GASFRAC’s system is primarily propane due to its presence as a natural, non-damaging hydrocarbon, he said.
The liquefied petroleum gas gel alternative involves injecting petroleum gel combined with sand under high pressure into the shale at similar ratios to hydraulic fracturing, he said.
GASFRAC has worked with liquefied petroleum gas technologies since the company became operational in 2008 and provides consultation to companies in Canada and rural Texas.
The company lauds liquefied petroleum gas gel as a “rare technology breakthrough in the oil and gas industry that can deliver both economic and environmental benefits for its producers.”
GASFRAC utilizes three major components in the use of the gel: storage tanks, a sand blender and specialized high pressure pumping units.
The company’s storage tanks involve a boost pump and nitrogen pressurization which feed the gel into the sand blender. Tanks are coated with a pressurized nitrogen blanket as a safety measure, Munro said.
Proppant, such as sand, is preloaded, purged and pressurized with the nitrogen to create a sand laden mix that stimulates the reservoir.
The process ensures the even distribution of sand in the mixture, which prevents it from settling in formations.
Munro said that the gel offers fewer restrictions than water in that more sand can be added to the mix to increase down-hole pressure and that the mixture can be altered to each well more efficiently.
As a formation friendly substance, the gel reduces the damage to surrounding environment as it occurs naturally down hole and is within a closed pressurized system. On average, more than 75 percent of the propane can be recovered and sold again compared to water operations, were recycling and reusing water can present a challenge, Munro said.
Additionally, he said the presence of hydrocarbons already in production eliminates the presence of biocides found in conventional fracking operations.
“It’s way more environmentally friendly and less likely to cause seismic events such as earthquakes,” he said.
Compared to the price of water recovery, he said the gel has a minimal cost after companies resell or repurpose recovered propane.
Additionally, the lower surface tension of liquefied petroleum gas gel can also produce a higher yield from wells when used properly, Munro said.
Due to the substance acting as an energized gel, petroleum gel helps to push fracking fluid in the well which has the potential to increase the natural gas yield in the wells, McLennen said.
“There is a pretty dramatic curve,” Munro said. “If used properly there can be a dramatic uplift in production.”
Munro said that they have seen the most dramatic increase in production at their Texas sites.
Additionally, McLennen said the higher availability of propane on site allows to easier access for oil and gas companies.
Another benefit of the gel comes through the use of butane which helps performance under high-temperature surface conditions, he said.
However, McLennen said the use of gel petroleum presents safety considerations which would require new expenditures and precautions to avoid injury.
“They are very expensive and because of the explosive properties of the substances used, they can be very dangerous,” said Encana’s Media Relations Manager Doug Hock.
Hock said that due to the gel’s relatively recent appearance in the oil and gas world, very few companies know about its definite benefits and disadvantages or have done research into its applications on individual formations.
“In speaking with our chief of completions, he tells me that completely waterless fracs are seldom done,” Hock said.
Alternatively, Hock said Encana has utilized nitrogen gas in its San Juan Basin operations in New Mexico which reduces, but does not fully eliminate, water use.
“The reason for using a nitrogen (fracture) is low reservoir pressure,” he said. “While it does reduce the amount of freshwater used, that’s not why it’s used.” Nitrogen, which makes up between 30 and 70 percent of the mixture with water, is added at the wellhead in a mixture with the water and pumped down hole. The nitrogen additive appears as foam similar to shaving cream, Hock said.
Both nitrogen and CO2 do not have the same volatile properties and risk of explosion, he said.
“The main problem with propane is that it is explosive, that’s been the big challenge with it,” he said. “Of course, we’re always looking for new ways to be efficient.”
Other options, such as non-flammable hexaflouropropane used in inhalers, stand as viable options to decrease water use in hydraulic fracturing operations. Hexaflouropropane solutions virtually eliminates the flammability risk at the surface and replaces water in the fracking process, McLennen said.
In order to ensure the safety of on-site employees, GASFRAC implemented remote control shut-offs, automatic shutdowns if propane leaks are detected and thermal monitors. In addition to these precautions, no physical workers are present on site, Munro said.
Thermal cameras are used to monitor all high-pressure lines while crews monitor pressure transducers throughout the system remotely from vans offsite, according to the company’s safety statement.
“We’re the safest operations in the world,” he said. “These are the safest operations I’ve ever observed during my time in the industry.”
However, the necessary safety precautions to monitor the highly explosive propane can provide high overhead costs that can deter companies from implementing the use of gel to replace water.
“It’s not something we are exploring here for several operational and effectiveness issues,” Noble Energy Corporate Communications Manager Steve Silvers said.
While many companies, such as Noble Energy and Halliburton, do not currently use liquefied petroleum gel technology, Munro said that the growing popularity of hydrocarbon technology will lead to more widespread use of the substance in the future.
“For us it’s a game-changing technology,” he said. “It allows us to recapture and reuse (the gas) effectively.”
More oil and gas coverage here.
From the Fort Collins Colordoan (Sarah Jane Kyle):
Ken Carlson wants to be an “honest broker” in a controversial world.
The CSU professor of civil and environmental engineering studies the water used, produced and extracted from oil and gas sites in Colorado. His main goal is to give people information — not opinions.
“For every study that says the world’s coming to an end, there’s a study someone can produce that says everything’s great,” Carlson, 54, said. “We try hard to operate in the middle.”
Carlson, who has been with Colorado State University for 16 years, runs the school’s Center for Energy Water Sustainability. CEWS recently launched Colorado Water Watch, a real-time monitoring system for water quality at oil and gas wells.
The free and public website uses anomaly detection software to monitor five wells, including one control site at the Agricultural Research Development & Education Center, which is just across Interstate 25 from the Anheuser-Busch brewery and at least three miles away from oil and gas activity. The remaining wells are by active Noble Energy oil and gas sites in Weld County.
More oil and gas coverage here.
From The Greeley Tribune (Tracy Hume):
Most of the produced water coming out of exploration and production operations in Weld County ends up being disposed of in one of 39 injection wells in the county. The produced water is injected back into the earth, thousands of feet deep, never to be used again.
Water quality expert Gary Beers thinks that’s a waste, and he is on the front lines of a growing movement to examine the economic and environmental benefits of treating and re-using produced water from oil and gas operations. Beers’ company, Industrial Water Permitting and Recycling Consultants, LLC, helps operators navigate Colorado’s complex regulatory environment and permitting processes to find better uses for produced water than just throwing it away.
“I was born and raised in southern Arizona, where water is very scarce,” Beers said, “I guess that planted the seed of being very concerned about not wasting water.”
Beers’ interest in water led him to pursue several degrees in the field, including a master’s degree in fisheries management from the University of Arizona and a doctorate in aquatic ecology from Utah State University. He established his consulting firm after a long career in the water quality field, including stints with the Environmental Protection Agency office in Denver and nearly 10 years in the Water Quality Control Division of the Colorado Department of Public Health and the Environment. His extensive experience on the regulatory side helps him to help operators identify and navigate the obstacles that impede beneficial use of produced water.
One of those obstacles is the public perception of produced water as “contaminated.” According to Beers, a lot of people “don’t understand that E&P (exploration and production) waste is just a category that’s used to identify any type of waste material generated while they’re drilling and producing oil and gas.
“But just because it is labeled ‘E&P waste’ doesn’t mean the water is polluted or anything; it just says that’s where it came from,” Beers said, “You can have E&P waste that’s very clean, or you can have E&P waste that’s contaminated. There is a lot of variability.”
Produced water comes in two main types, each with distinctive characteristics that have implications for beneficial use. The first type of water to return from a well, called “flowback,” is the water used to facilitate the initial drilling process, and may include traces of the chemicals used for hydraulic fracturing. The second type, “formation water,” is the water that is part of the original geological formation and is brought to the surface in the course of oil and gas production.
“Most of the produced water people talk about is the long-term formation water that’s brought up as the well is producing oil and gas,” Beers said. “The quality of the initial flowback water can change, because of the different chemicals used in drilling and other factors, but the quality of the formation water is pretty consistent, depending upon the original geological formation.”
Some operators in the DJ Basin have taken steps to treat and re-use produced water, including flowback water, for hydraulic fracturing. Flowback water may include chemical additives and total dissolved solids, but it typically includes fewer salts than formation water, making it easier to treat for industry re-use.
Concord Produced Water Services is a produced water treatment provider that Beers has worked with in the DJ Basin. Among the services Concord offers is mobile recycling units, which can be taken out into the field to treat flowback and produced water for re-use.
Re-use of produced water within industry operations is, in some ways, the most straightforward beneficial use to implement. When operators re-use produced water within their own organizations, it minimizes the number of regulatory hoops that have to be negotiated. Furthermore, the public typically supports industry re-use of produced water because it reduces the industry’s impact on public water supplies.
“There’s a lot of controversy around the issue of using fresh water supplies, such as surface water or shallow ground water, for hydraulic fracturing,” Beers said. “The use of public water to supply the oil and gas industry is a continuing issue in Weld County.”
The possibilities of treatment and re-use could make it possible for the industry to decrease its reliance on municipal water sources.
“There have been significant efforts to ramp up re-use practices in Weld County,” Beers said, pointing out that “in theory, the demand for water for hydraulic fracturing in Weld County could be met by recycling all the produced water five times over.”
Another possibility for beneficial use of produced water is dust suppression. Many rural communities with high numbers of dirt roads use significant amounts of water to mitigate dust and maintain roads. Some communities have begun exploring the idea of using produced water, particularly formation water, for this purpose.
“The deeper formations were laid down when the land was almost totally dominated by oceans,” Beers explained, “so produced water from these marine sediments typically has a high concentration of salts.” Interestingly, the composition of these briny produced waters is similar to the composition of common commercial magnesium chloride solutions municipalities use for dust control on unpaved roads. Beers sees an opportunity there.
“Many counties in Colorado spend hundreds of thousands of dollars a year for commercial magnesium chloride solutions,” Beers said, despite the fact that the produced water coming out of the oil fields might serve the same purpose.
However, this particular beneficial use is quite a bit trickier to implement. The beneficial use of produced water is overseen by a complex network of regulatory agencies including the Colorado Oil and Gas Conservation Commission, the Water Quality Control Division of the Colorado Department of Public Health and the Environment, and county permitting processes. Which regulations and permitting processes apply is contingent upon variables such as the produced water source; the composition of the water; whether the water has been treated, how it has been treated, and by whom; and the proposed use.
Beers finds irony in the fact that despite the similarities in composition between commercial magnesium chloride products and produced water (brine), there are virtually no regulatory hurdles to using a commercial magnesium chloride solution for dust suppression, but there are numerous regulatory hurdles to using produced water for the same purpose, because it is classified as industrial waste.
“Let’s say you’re going to buy ‘Compound X’ for dust suppression,” Beers said. “The company is required to disclose what chemicals they put in their solution. If you look at that, they’ll say so much magnesium chloride, etc. Then they’ll say ‘confidential’ or ‘proprietary’ ingredients and they won’t disclose what they are. So you don’t know.
“But if you were going to use produced water,” Beers said, “you would have to get state approval to do that. You would have to analyze hundreds of compounds and disclose what each of those were. So if you were going to buy the magnesium chloride solution from a commercial guy, he would say, ‘Well, it only has salt in it and a bunch of stuff which I can’t tell you.’ And then you look at the produced water and say, ‘Look at all of the things they found in it!’ Whether those components are harmful or not.
“Nine times out of ten the buyer will say, ‘I’m not going to get that produced water because it’s got all these weird things in it.’ But I’ve done some side-by-side testing and there are a lot of materials in the commercial products that they should tell you about, but they don’t, because they don’t have to,” Beers said.
The bottom line is, “it’s an uneven playing field, because recycled products, like produced water, have regulatory baggage and they have to disclose everything, unlike commercial products,” he said.
Beers sees the possibility of change on the horizon.
The industry is starting to acknowledge the economic benefits of water re-use. Treating and re-using water in the field cuts down on the cost of purchasing water and transporting it to the site. Treating produced water and using it for dust suppression, or similar beneficial uses, even holds the potential of turning an industry expense, such as disposal of produced water, into a revenue stream, such as selling treated produced water to municipalities.
Stakeholders, such as regulatory agencies, are also beginning to discuss streamlining permitting processes to make it easier to recycle produced water and use it for beneficial purposes. In January of this year, the Colorado Energy Office and the Water Center at Colorado Mesa University convened 65 stakeholders from the Grand Junction community to talk about re-use projects on Colorado’s Western Slope.
Beers said he believes that with enough education, the public, too, will begin to see the benefits of treating and using produced water.
“A lot of people are looking at beneficial uses for produced water,” Beers said, “it’s just a matter of having a few on-the-ground projects to show people that it does work and that it can be done.”
More oil and gas coverage here.