Southern Delivery System: “It’s a wonderful, wonderful day to celebrate” — John Fredell

March 19, 2015

From The Colorado Springs Gazette (Jakob Rodgers):

The last 50-foot pipe of the 50-mile-long Southern Delivery System arrived at a construction site Wednesday, marking a key milestone for the project as it nears completion next year both on time and under budget.

“We put to rest a lot of doubters that we’d get this done,” said Lionel Rivera, Colorado Springs’ former mayor, who helped approve the project.

With Kool & The Gang’s “Celebration” playing in the background, a truck hauled the massive blue pipe to a site just south of Pikes Peak International Raceway. Crews will place it underground in the coming weeks, completing a system spanning from Pueblo Reservoir to a new water treatment facility in Colorado Springs, which is under construction.

More than 7,000 of the steel, 66-inch-diameter pipes were installed since in 2010. That included a mile-long stretch bored 85 feet below Interstate 25 – a tunnel that was $10 million cheaper than creating a surface trench, according to Colorado Springs Utilities.

Current and former elected officials from across southern Colorado, along with several contractors who have worked on the project, were among scores of people on hand to watch the pipe being delivered. Many signed their names on it.

“It’s great – we’ve been at this a long time,” said John Fredell, the Southern Delivery System’s program director. “It’s a wonderful, wonderful day to celebrate.”

Three pump stations and the treatment facility are expected to be completed this year, with the system up and running for customers in Colorado Springs by the first quarter of 2016, Fredell said.

The project is on track to cost $841 million, below Colorado Springs City Council’s approved budget of $880 million in 2009, which did not account for inflation or rising material costs. The council also serves as Utilities’ board. Those savings rise to about $150 million when factoring in the cost of inflation and increases in material costs, said Fredell, who credited design changes to the pipeline and water treatment facility for much of the savings.

From the Denver Business Journal (Cathy Proctor):

One of the biggest water projects in the western U.S. will hit a major milestone this month, when the last piece of 50 miles of pipe is laid for the Southern Delivery System, the $841 million project to bring new water supplies to Colorado Springs and nearby communities.

The project includes 50 miles of pipeline, three pump stations and a water treatment plant. It will deliver water from the Pueblo Reservoir to Colorado Springs, Fountain, Security and Pueblo West.

More than 7,000 sections of blue-colored, welded, steel pipe 50 feet long and most of it 66 inches in diameter were installed on the project during the last 3 1/2 years of construction.

The project spent $204 million on pipe and installation, according to the Colorado Springs Utilities.

“The pipe is the main artery for this water project and we are extremely pleased with how the pipeline construction went,” said John Fredell, the program director for the Southern Delivery System project.

The project is in the final year of construction and Fredell said the costs are expected to be nearly $150 million under the original budget…

Northwest Pipe (Nasdaq: NWPX), based in Vancouver, Washington, manufactured the SDS pipe at its Denver plant.

Three contractors installed the pipe, Garney Construction, headquartered in Kansas City with an office in Littleton; ASI/HCP Contractors of Pueblo West; and the heavy civil division of Layne, a construction firm based in The Woodlands, Texas, which has four offices in Colorado.

Construction is continuing on other elements of the Southern Delivery System project, including a $125-million water treatment plant and pump station that will have the capacity to treat and pump 50 million gallons of water per day. Three pump stations will help move water uphill, about 1,500 feet in elevation, from the Pueblo Reservoir, also are under construction.

Construction on the remaining portions of the project are expected to be finished by the end of 2015.

From KRDO (Rana Novini):

Community leaders gathered Wednesday to celebrate the completion of pipeline construction for the Southern Delivery System (SDS). The project consists of more than 7,000 50-foot sections of steel pipe that have been installed over the last three and a half years. The pipe will transport water stored in the Pueblo Reservoir north to Pueblo West, Fountain, Security and Colorado Springs.

“It’s taken many years and it’s taken many city councils and it’s taken many leaders and many workers to accomplish this,” said Colorado Springs City Councilman Merv Bennett. “Our friends to the south, the Lord gave them the Arkansas River as their delivery system. To the north, Denver has the South Platte River as their delivery system. We have Fountain Creek and we ran out of that water in 1912.”

Proponents of the SDS argue the pipeline will ensure Colorado Springs and surrounding areas can continue to grow, especially toward eastern El Paso County. The region will have to worry less about drought and watering restrictions.

“Water is important. It’s the lifeline of a community,” said Lionel Rivera, former mayor of Colorado Springs. “It’s the way you grow and I think we’ve ensured the water supply for at least the next 50 years.”

Rivera was mayor from 2003 until 2011 and helped get the project rolling. He said Tuesday that it was one of the most rewarding things he did as mayor.

“It’s very exciting, a little bit emotional to see that pipe,” Rivera said. “It just made me think of all the stuff we had to go through to get this approved. We were told back when we started it that it couldn’t get done from a political standpoint, but we proved the doubters wrong.”

The project has had opponents over the years, many from Pueblo who are concerned over stormwater issues.

Though pipeline construction is complete, workers still need to build water treatment plants and pump stations. The first drop of water is expected to be delivered in spring 2016.

From The Denver Post (Bruce Finley):

Construction crews are poised to lay the final pipeline link for Colorado’s biggest water project in decades — an $841 million uphill diversion from the Arkansas River to enable population growth in Colorado Springs and other semi-arid Front Range cities.

Eleven 2,000-plus horsepower pumps driven by coal-fired power plants will propel the water from a reservoir near Pueblo through a 50-mile pipeline with an elevation gain of 1,500 feet.

This is the first phase, moving up to 50 million gallons a day, for a Southern Delivery System that utility officials estimated will eventually cost $1.5 billion.

“It means we will have greater water security,” Colorado Springs utilities spokeswoman Janet Rummel said. “Businesses need water. Our communities need water to survive. It means we can continue to serve our population as it grows.”

Water challenges loom across Colorado, with state officials projecting a 163 billion-gallon shortfall. A few years ago, drought forced Colorado Springs to stop watering municipal parkways and gardens.

The diverted water can be used only within the Arkansas River Basin, officials said, ruling out sales to south Denver suburbs. And the river water, after treatment, must be returned to downstream farmers.

Colorado Springs residents have been paying for the project through water bills, which increased by 52 percent over four years. Utility officials spent $475 million from bonds.

The water will flow by next March, officials said. At full buildout, the system will store water in two new reservoirs east of Colorado Springs.

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

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

From The Pueblo Chieftain (Chris Woodka):

The Southern Delivery System pipeline’s completion was marked by a contingent of El Paso County officials and a smattering of Pueblo County folks as well.

For John Bowen, president of ASI Constructors of Pueblo West, the SDS project has meant bread on the table as well as water in the pipes.

“It’s generated $50 million in contract values for our company,” Bowen said during a ceremony to mark completion of the SDS pipeline from Pueblo Dam to Colorado Springs. “We were able to grow as a business during a time when a lot of contractors were laying people off.”

ASI was the primary contractor for the connection at Pueblo Dam, as well as 12 miles of the 50-mile SDS pipeline route, and relied on 70 local businesses for support services. The SDS project generated $800,000 in wages for ASI workers.

More Southern Delivery System coverage here and here.


Putting the electric harness on old dams — the Mountain Town News

March 10, 2015

From the Mountain Town News (Allen Best):

 

Pueblo dam releases

Pueblo dam releases

State and federal incentives together producing new power from old dams

As with most smaller dams from that era, no hydroelectric turbines were installed in Pueblo Dam when it was constructed during the early 1970s. It’s located in central Colorado, the silvery summit of Pikes Peak in the distance, impounding the Arkansas River as it meanders onto the Great Plains.

The dam’s 191 feet height provides what hydrologists call head, a prerequisite for making large amounts of electricity. Absent, though, are large volumes of water.

Now, with strong financial and other incentives from both the state and federal governments, dam operator Southeastern Colorado Water Conservancy District seeks to install turbines sufficient to allow production of 7 megawatts.

Five such retrofits in the West have occurred since 2008. Pueblo and 18 others are in the pipeline. Many are in Colorado, which has emerged as a model for how to encourage the retrofitting of smaller, older dams.

Retrofitting Colorado dams and canals

  • Ridgway Reservoir (8 MW): completed 2014
  • Carter Lake (2.6 MW): completed 2013
  • South Canal Drops 1 and 3 (7.5 MW): completed 2013
  • Lake Granby (1.2 MW): underway
  • Pueblo Reservoir (7 MW): underway
  • Shavano Falls (2.8 MW): underway
  • South Canal Drop 2 (1 MW): underway

Michael Pulskamp, who oversees the U.S. Bureau of Reclamation’s lease-of-power-privileges program from an office in suburban Denver, says the 2005 Energy Bill required resource assessments of federal water infrastructure but the Obama administration delivered the push.

Those studies found great cumulative potential. A 2011 study concluded that one million megawatts of annual production of electricity could be delivered if just the 70 most promising dams, diversion structures, and tunnels were developed. The study had screened 530 federal sites.

Colorado, Utah, Montana, Texas, and Arizona have the most sites with hydropower potential.

“That study really laid out that we weren’t tapped out in terms of hydropower potential,” says Pulskamp.

Another federal assessment of 373 irrigation canals, tunnels, and other conduits in 13 Western states found another potential 103.6 megawatts of generating capacity.

Even if all the 1.1 million potential megawatts identified in the two studies get built, the capacity will be dwarfed by existing dams in the West. Grand Coulee Dam, completed on the Columbia River in 1941, produces 21.5 million megawatts annually, tops in the West. Glen Canyon Dam, on the Colorado River, can produce 3.8 million megawatts, followed closely by Hoover Dam with 3.7 million.

Shasta Dam, in California, can produce 1.9 million megawatts and Davis Dam, on the Colorado River in Arizona, produces 1.1 million megawatts.

Ridgway Dam

Ridgway Dam

Colorado’s largest hydroelectric production comes from the three dams on the Gunnison River in what is called the Aspinall Unit. Together, they can produce 826,000 megawatts annually. Hydroelectric capacity installed in several components of the Colorado Big-Thompson diversion project can collectively produce 413,000 megawatts.

In comparison, new turbines on Utah’s Jordanelle Dam can produce 39,000 megawatts annually while Colorado’s Ridgway Dam, which went on line last May, can produce 22,000 megawatts annually.

Pueblo will produce even less, 19,700 megawatts annually. Southeastern Water was prodded into taking on the project only after the Bureau of Reclamation specifically solicited proposals.

“We were afraid if we didn’t pursue it, a private entity might come and develop the project,” says Kevin Meador, project manager for Southeastern Colorado Water. The Pueblo-based agency administers water diverted to the Arkansas from the Aspen area under federal sponsorship in the Fryingpan-Arkansas Project.

Colorado’s state government has provided both financial incentives and a market for sale of renewable energy. One of the incentives is a 2 percent loan at 30 percent from the Colorado Water Conservation Board. “That is a huge factor in making this project feasible,” says Meador.

The Colorado Water Resources and Power Development Authority also provides 20-year loans of 2 percent.

In setting a 30 percent renewable portfolio standard for investor-owned utilities and now a 20 percent standard for Tri-State Generating & Transmission, Colorado has created a market for power from smaller dams. No buyers for the electricity from Pueblo have been lined up, but Meador says his agency needs to get 3.5 to 4 cents per kilowatt hour to make the numbers work.

If this were Massachusetts or Hawaii, where electricity prices to consumers run up to 25 cents per kilowatt hour, that would be an easy sell. But in the Rocky Mountains, energy has historically been relatively cheap, observes Meador, “and these hydro projects are capital intensive. They are very expensive up front.”

Seven percent of all U.S. electricity comes from hydropower. In Colorado, it’s 4 percent. Pulskamp says that the greatest hydroelectric potential lies in further harnessing the slow-moving but vast quantities of water in the Mississippi River and its tributaries. His agency, however, has little oversight there.

Kurt Johnson, president of the Colorado Small Hydro Association, says Colorado could serve as a model for other states. He points to efforts begun in the administration of former Gov. Bill Ritter to surmount an often clunky, discouraging federal permitting process. Even more important, Colorado has sweetened incentives with low-cost, long-term loans. Finally, last year it lowered regulatory hurdles.

Two key federal laws passed by Congress in 2013 simplified the federal regulatory process. One law specifically targeted Bureau of Reclamation facilities. Johnson’s organization now seeks to lower the hurdle for other existing but non-federal facilities that must get approval from the Federal Energy Regulatory Commission.

Despite the recent growth, however, hydroelectric remains just a small part of new electrical generating capacity, both in the West and nationally. In 2015, gas was responsible for the most new generating capacity, followed by wind and solar. Hydro was just 1 percent of total national production.

Granby Dam via Reclamation

Granby Dam via Reclamation

Yet even with just trickles of water, hydro power now makes sense financially. Consider Granby Dam, which plugs the Colorado River a few dozen miles from the river’s origins in Rocky Mountain National Park. The dam is 298 feet tall, providing plenty of head. Like Pueblo, it lacks water: just 20 cubic feet per second of water gets released during winter months, as required for environmental purposes, and 75 cfs during summer, except in the biggest of runoff years. The rest gets diverted to cities and farms east of the Continental Divide.

With so little water, Granby can generate just 1/800th of the total production of Hoover Dam. That small production, along with competition from cheap power, is why turbines were never installed when the dam was built from 1941 to 1950.

“Probably power sale rates were next to nothing,” says Carl Brouwer, a project manager for Northern Water, the water agency that distributes Colorado-Big Thompson water to the Boulder-Greeley-Fort Collins area.

As with Pueblo, Northern Water had first shot at obtaining the lease to produce power and did so to preclude shared operations. Northern was aware of at least one other bidder, says Brouwer.

Granby also needed the state’s $5.1 million loan at 2 percent interest is crucial in moving the $5.8 million project forward. “That low-interest loan is what makes this project feasible,” says Brouwer.

A smaller revenue stream comes from sale of the environmental attributes of the energy through a financial device called renewable energy certificates, or RECs. Purchaser was Tri-State Generation & Transmission.

Annual revenues, projected to be $375,000, will pay off debt and operations during the first 30 years. But unlike coal-fired power plants, the supply of fuel will always be free.

More hydroelectric/hydropower coverage here.


COGCC approves new rules for operations within floodplains

March 5, 2015

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

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


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

The Colorado Oil and Gas Conservation Commission today [March 2] unanimously approved new rules that outline requirements for operators with facilities located within floodplains.

The new rules implement several of the recommendations contained in the Commission’s “Lessons Learned” report published in March 2014 following the Front Range floods of September 2013.

The nine-member Commission approved regulations designed to better protect oil and gas facilities that may be subject to flooding and that require more preparations from operators to reduce potential impacts. The new rules formalize “best management practices” when operating within a floodplain and require:

  • All tanks, new and existing, be surrounded with hardened berms made of steel instead of earthen barriers.
  • Critical equipment be anchored according to an engineered anchoring plan.
  • The removal of existing pits used for exploration and product waste.
  • All new wells to be configured so operators can shut the well in remotely.
  • “We learned a great deal from our experiences in September of 2013, including what existing practices were successful in reducing damages,” said Matt Lepore, director of the Commission. “Requiring these practices for oil and gas operations within a floodplain makes sense and will ensure environmental impacts are reduced and equipment is further protected should we see another flood event.”

    In addition, the new rules require operators, by April 1, 2016, to establish an inventory of wells and critical equipment located within a floodplain and to register all such wells and equipment with the COGCC. Operators are also required to create a formal plan on how they will respond to a potential flood.

    “These new rules requiring operators to establish an inventory and a formal response plan will help ensure both operators and the COGCC can react more quickly when a flood threatens or strikes,” Lepore said.

    These new rules are effective June 1, 2015 for new wells and equipment and April 1, 2016 for retrofitting of existing equipment.

    The new floodplain rules is the latest of numerous steps undertaken by the COGCC to improve regulation of oil and gas development in Colorado and part of Governor Hickenlooper’s commitment to long-term recovery and resiliency after the 2013 floods.

    Since 2011, the Hickenlooper administration has crafted rules to increase setbacks, reduce nuisance impacts, protect groundwater, cut emissions, disclose hydraulic fracturing chemicals, increase spill reporting and significantly elevate penalties for operators violating Commission rules.

    The Commission has also significantly expanded oversight staff, intensified collaboration with local governments, sponsored ongoing studies to increase understanding of impacts to air and water, streamlined its process for public complaints, increased public access to COGCC data and adopted several formal policies to address health and safety issues brought about by new technologies and increased energy development in Colorado.

    More oil and gas coverage here.


    The City of Aspen filed a microhydro app yesterday with FERC on Maroon Creek

    March 5, 2015


    @USGS: Map of Assessed Continuous (Unconventional) Oil Resources in the U.S., 2014

    March 2, 2015


    What Is Oil And Gas Wastewater And What Do We Do With It? — KUNC

    March 2, 2015

    From KUNC (Stephanie Paige Ogburn):

    When a typical oil well starts producing, there are three main products pumped out: gas, oil, and water. The amount of water is significant. In Colorado, for every barrel of oil produced in 2013, there were 6 barrels of wastewater pumped from the ground.

    How that water — sometimes referred to as produced water — is treated and disposed of has become a growing issue as oil and gas production has increased in Colorado and across the United States.

    Mark Engle, a U.S. Geological Survey scientist, is working to pin down just how much of the wastewater is being produced nationwide.

    “Since the big explosion in shale gas and tight oil production in the last four or five years, [there is almost no data on] how much the amount of produced water has changed in the U.S,” Engle said.

    Quantities of wastewater, which can be 10 times saltier than seawater and is often laced with hydrocarbons, have grown because of the shale boom, which requires continual drilling of new wells to be profitable.

    “And so just to have stable production, you have to keep putting more and more and more wells in, and they are all producing water,” said Engle.

    Most of these wells, drilled in shale formations like the Niobrara in Northern Colorado, or the Bakken in North Dakota, are horizontal wells that are hydraulically fractured. To do this, millions of gallons of water, chemicals, and proppants, like sand, are pumped into the ground at high pressure, opening up tiny cracks in the shale.

    The goal of this process is to free up trapped oil and gas. But trapped water flows back as well. Some of that water is what was used in the fracking process, but a lot of it is also ancient water from deep within the Earth.

    That wastewater picks up a lot of chemicals because of where it comes from, said Ken Carlson, an engineering professor at Colorado State University who studies energy and water issues.

    While many folks worry about what’s in fracking fluid, Carlson is more concerned with the naturally occurring pollutants from deep below.

    “Sometimes people think it is hazardous because of what we put down there,” said Carlson. “And the truth is, the water that comes back has been in contact with oil and gas compounds for maybe millions of years.”

    Wastewater is almost always incredibly salty. It also often contains dissolved metals and compounds like benzene, a known carcinogen, said Carlson. In some places, like Pennsylvania’s Marcellus Shale, that wastewater can also be radioactive, as it picks up naturally occurring elements like radium from deep inside the earth. (Waste from Northern Colorado has not been shown to be more radioactive than natural background levels.)

    Because of this, such water is usually disposed of, said Greg Duronlow, the environmental manager of the Colorado Oil and Gas Conservation Commission.

    “It is a waste product with some negative characteristics. So it does have to be handled carefully,” said Duronlow.

    When a well is producing, companies separate the products that make them money — oil and gas — from the water. In Colorado, that water is usually stored in on-site tanks or pits that fill up. Later, it gets trucked away.

    There are a few main things that happen to the wastewater after that.

    By far the most common way of dealing with wastewater is disposing of it deep underground, in injection wells. While some energy companies have their own wastewater disposal wells, an injection well industry has also cropped up to meet this need. In the U.S., there are around 30,000 injection wells used to dispose of fluids from oil and gas production.

    Even though wastewater is disposed of deep underground, there are still risks. Recently, some injection wells have been linked to earthquakes. Spills are also an issue. Pipelines carrying wastewater can leak, as can holding pits, and trucks transporting waste can spill it.

    In Colorado, the spill rate for wastewater is very low — over the last 15 years, just 0.009 percent of all wastewater produced was spilled, according to COGCC data. The agency’s oversight over spills has grown in recent years, and it recently made its spill reporting requirements more stringent, requiring spill reports for even one barrel, rather than five.

    “All spills, regardless of their size, are required to be cleaned up by an operator,” said Duronlow. The agency also has tighter restrictions around oil and gas operations that are near public water supply areas, he added.

    “I would say an industry with a spill rate of a thousandth of a percent, they are working pretty hard to keep those numbers low,” Duronlow added.

    While overall, the state does have a very low spill rate, simply because so much wastewater is produced, the total spill quantities can still be high. From 2005 to 2013, spill amounts ranged from 10,000 to 72,000 barrels (420,000 to 3,024,000 gallons) per year.

    In 2008, in Garfield County, a rancher took a drink of water from a tap in his cabin, and swallowed a toxic mix of oil and gas related compounds, landing him in the hospital. The polluted drinking water was contaminated from a produced water holding pit that leaked; the COGCC fined the energy company Williams $432,000.

    Other pits containing produced water have also leaked; Oxy USA also received a COGCC fine for contaminating two springs with produced water from leaking pits.

    Some companies have tried recycling wastewater, re-using it for hydraulic fracturing future wells. In states like Pennsylvania, where disposing of wastewater is expensive, and Texas, where water is scarce, recycling has grown in popularity. Some Colorado companies are also recycling wastewater.

    There are some concerns about this approach. For one, treating the wastewater creates yet another waste stream — the chemicals that were taken out of the water, and are now concentrated. Moving more water around can cause other problems, like increasing the potential for spills as the water is transported and handled.

    Sometimes, wastewater is so dirty that cleaning it up to the standards they need for hydraulic fracturing just isn’t worth the cost. The COGCC is working with some companies on recycling produced water to reuse, but “it takes a lot of work to clean up the water to a point even that they want to use it,” said Duronlow.

    For every new well drilled and the oil it produces, though, there will be wastewater to be dealt with. Getting a handle on that water — whether it is injected or recycled, piped or trucked — will continue to be a significant task.


    Oil And Gas Wastewater Presents A Business Opportunity For One Colorado Company — KUNC

    February 27, 2015

    Deep injection well

    Deep injection well


    From KUNC (Leigh Paterson & Inside Energy):

    In 2013, Colorado and Wyoming produced around 128 million barrels of oil and a little more than 2.4 billion barrels of wastewater combined. North Dakota produced 300 million barrels of oil and nearly 360 million barrels of wastewater in 2013.

    Wastewater disposal is a massive but little-known part of the oil and gas business. According to Boston-based water consulting firm Bluefield Research, the U.S. hydraulic fracturing industry spent over $6 billion in 2014 on water management. For those reasons, Colorado-based T-Rex Oil believes now is the perfect time to get into the business of wastewater disposal.

    T-Rex Oil is looking to operate a wastewater disposal well in Western Nebraska, but may face an uphill battle to get the required permit. NET News Nebraska has reported that the company is facing strong opposition from residents. T-Rex’s application [.pdf] says the proposed project would be the largest operation of its type in the state, accepting upward of 80 truckloads a day of wastewater from Colorado, Wyoming and possibly Nebraska. The brine – a super salty, sometimes chemical-laden fluid – would then be processed on site before being pumped underground.

    According to the Environmental Protection Agency, there are around 144,000 class II wells spread across the country. Most are actually aging oil wells that companies inject with carbon dioxide or other substances to get them to produce more oil, a process known as enhanced oil recovery. Other wells are used to store fossil fuels and about 20 percent are used to dispose of wastewater.

    The wells used for brine disposal is what worries residents of Nebraska’s panhandle, who have concerns about spills, groundwater contamination, and an increased risk of earthquakes.

    “I just have reasonable doubts about the safety,” Jane Grove told NET Nebraska. Her ranch sits near the T-Rex’s well site.

    Spills have been a concern in North Dakota, where on average, more than 2 gallons of wastewater spills per minute. Most spills occur during transportation – the wastewater has to get to the well either by truck or pipeline – or storage tanks can leak.

    Earthquakes are another concern of the residents. Injection wells and oil and gas exploration have been linked to human-caused quakes, also known as “induced seismicity.” In 2014, Oklahoma was found to have had more magnitude 3 or greater quakes than California. Greeley, Colorado had a brush with a human-caused temblor in 2014 as well, where activities at an injection were linked to a magnitude 3.2 shake. Geological activity in the area later tapered off when the well was shut for evaluation and later allowed to start operating again, albeit at lower pressures and volumes.

    To many they are invisible, but injection wells, for now, are vital to the industry because they are the cheapest and most available way to dispose of oil and gas wastewater. As Justin Haigler, president of Black Bison — Wyoming’s largest water services company — notes, “without this water management, oil and gas doesn’t happen.”

    More oil and gas coverage here.


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