The other precious resource

R&D, operational initiatives target new ways to manage, recycle and reuse water

By Katie Mazerov, Contributing Editor

What happens when a world thirsty for hydrocarbons meets a world competing for water? In the unconventionals sector, that collision of commodities is playing out across a variety of environmental and usage issues. These range from the millions of gallons of water required to hydraulically fracture a well, to water reuse, waste management, transportation, recovery and concerns about seismic activity related to the injection of produced water in disposal wells.

The global population is expected to soar to nearly 10 billion by 2050, according to the United Nations Department of Economic and Social Affairs. That, combined with growing energy demand in developing countries, has heightened general awareness of water resources  – an issue that unconventional oil and gas development has thrust into the spotlight.

Research firms, E&P and service companies and nonprofit enterprises are tackling the water issue through ambitious R&D programs. Many companies also have incorporated water management systems into their operations to increase reuse. In what could be an industry game-changer, Encana is building a water treatment facility in central Wyoming that will recover 90% of produced well water and pump it to a nearby reservoir. Devon Energy also has launched a corporate water management team and is using freshwater alternatives for its operations in an area of the drought-prone Permian Basin.

“Water has always been an issue, but historically it hasn’t been on the radar screen to the degree it is now,” said Kent Perry, VP Onshore Programs for RPSEA (Research Partnership to Secure Energy for America). The nonprofit corporation, established by the US Department of Energy, is providing financial incentives for several ongoing water management research efforts and has a portfolio of collaborative projects. These include engineering of better membranes for reverse osmosis (RO) systems and a project with Colorado State University and Noble Energy to develop a water transport system, focusing on the Denver-Julesburg (DJ) Basin in eastern Colorado. Mr Perry cited a 2013 SPE survey that identified water as one of the five major technical issues that must be addressed, especially when it comes to reprocessing, transportation and injection.

“In taking the full stream of water and turning it into a product, we have a tremendous amount of work to do,” Mr Perry said. “Water varies tremendously. It can be near-fresh or salty, have naturally occurring radioactive material or other chemicals that can challenge a particular processing technology. A system that works in one type of water won’t be effective in another.

“From the perspective of managing produced water, we have programs aimed at technologies for changing water from a waste stream to a product stream, such as near-freshwater that can be used for agricultural and industrial purposes, in some cases potable water,” he continued. “On the other side of the equation, we are looking at technologies to remove chemicals from the water for reuse. Last year, 20 billion tons of salt were used on US roads for ice control, so there is definitely a market.” Other chemicals, such as barium, which are used as weighting agents in drilling fluids, can be concentrated and removed from the water stream; the resulting product can be sold at a premium, he noted.

As drilling activity increases, so does the impetus to come up with solutions. RPSEA is conducting studies looking at the entire hydraulic fracturing process, including the possibility of a connection between seismicity and the injection of produced water in deep disposal wells. Options for disposal wells vary region to region. In the Marcellus, for example, geology and local regulations require produced water be trucked to Ohio, an undertaking that is both costly and risky. However, the Ohio Department of Natural Resources has suspended drilling operations in some areas to assess the cause of earthquakes.

“About 40,000 wells are being drilled annually in North America, and most of that activity is shale gas or oil,” Mr Perry noted. “Looking out over the next 20 to 30 years, to achieve the full production potential experts believe resides in the shales, that well count will likely increase to 80,000. That’s a pretty heavy environmental footprint. Research and technology need to be developed to mitigate the impact in order for the industry to realize that potential.”

In the past five years, the industry has made significant strides in developing technologies for reuse of produced water. These technologies provide the dual benefit of reducing costs for operators and conserving water. Depending on geography, local regulations and economics, a combination of trucking, piping, impoundment ponds and storage tanks is required to handle the large quantities of water needed for hydraulic fracturing.

Reuse vs recovery

There are three options for dealing with produced water, said Dr James Silva, Senior Chemical Engineer at GE Global Research:

• Disposal, which involves transporting the water to a deep well injection site;
• Reuse, cleaning up the water and using it for subsequent hydraulic fracturing jobs;
• Recovery of clean water and potentially a salable salt product.

Dr Silva’s company has completed several water recovery R&D efforts with RPSEA. “Depending on the geography, produced water reuse is driven by different factors,” he said. “In some shale plays, such as the Barnett in Texas, there are numerous deep well injection sites for disposal of produced water. There, the scarcity of source water is an incentive for reuse. In other plays, such as the Marcellus in western Pennsylvania, source water is abundant, but there are essentially no local injection wells for disposal. In the Marcellus, reuse is much more economical and environmentally responsible than hauling produced water into Ohio and West Virginia for deep well injection.

“Reuse versus recovery is also a matter of supply and demand,” he continued. “For a given development area, reuse makes perfect sense as long as there is a need for produced water. When a field is growing, there is a continued need for produced water as blend stock to hydraulically fracture the next well. But as a field ages and fewer new wells are hydraulically fractured, the volume of produced water exceeds the need for blend stock for well completion.”

GE Global Research is developing pre-treatment technologies to enable recovery of produced water. “We’re developing the next generation of water recovery technology in anticipation of growing demand for water recovery, whether it is mandated by regulation or because it is more economical than disposal,” Dr Silva said.

R&D efforts include developing advanced filters used to separate oily particles, which often accompany produced water and can rapidly plug conventional filters. Whether water is recovered by RO or by thermal evaporation, it must be filtered prior to recovery. RO systems are effective for purifying water in formations with relatively low total dissolved solids (TDS), up to about 35,000 parts per million (ppm) TDS, which is the salinity of seawater. RO systems force pure water through the membrane, leaving a concentrate of leftover water and salt, which can be disposed of either by deep well injection or by thermal evaporation. The recovered clean water can be used in agricultural or industrial applications, or it can be discharged.

For formations such as the Marcellus, where the TDS content is often six times or more saltier than seawater, GE is leveraging its experience from power plant cooling tower water treatment and recovery to develop technology that prepares water for thermal evaporation, evaporates the water itself and crystallizes the resulting salt for industrial reuse, Dr Silva explained. “This is an evolving field, but there are similarities in evaporating water from cooling tower blowdown at a power plant and recovering produced water from hydraulic fracturing.”

GE has tested the pre-treatment and water recovery processes in the lab and in pilot projects, yielding distilled water and very clean salt, according to the company. The recovered distilled water can be discharged into surface water or used for high-tech manufacturing. “We can actually recover water and salt more cost effectively than transporting it long distances for disposal,” he noted.

Water as a resource

In collaboration with GE Water & Process Technologies, GE Global Research provided technical support for a high-efficiency RO water treatment and recovery facility in Wyoming for Encana. At this facility, nearly 90% of the produced water will be cleaned to standards that allow it to be discharged in the vicinity of a tributary that feeds the Boysen Reservoir on the Wind River. Scheduled for completion in early 2015, the facility is located in the Moneta Divide gas field in central Wyoming between Riverton and Casper, a formation with typically 7,000 ppm TDS produced water. “This formation provides an ideal combination of conditions for a water recovery facility – a lot of low-TDS water is produced with the gas,” Dr Silva said.

Water will be transported to the Neptune Water Treatment Facility through a network of pipelines from the oil and gas field, which produces more water than is used for operations. The field currently has a capacity of approximately 50,000 bbl/day of water. At peak production, the field is expected to produce as much as 1 million gallons of produced water per day. Water for completions can be treated on individual well sites to remove heavy solids and hydrocarbons, with the excess going into the pipeline system.

At the treatment facility, the water will be pre-treated, using numerous technologies to remove contaminants that could plug the RO membranes, explained Encana spokesman Doug Hock. “Any hydrocarbons removed in this process will be stored and sold on-site. The water then will enter RO membranes, where the dissolved solids will be removed, and exit the plant at Class 1 standards, or similar to the purity of mountain spring water,” he said.

Other companies are also treating produced water, but GE believes that this is the first project where produced water is actually being put into a reservoir for indirect potable usage, said Paul Schuler, Regional Executive for the Americas for GE Water & Process Technologies, which designed the RO equipment. The company is developing similar projects elsewhere in the US. “Each shale play has varying produced water characteristics, which can change over time for a given well, so we treat different ranges of water quality by designing different RO solutions,” he said. “Encana has the foresight to realize that water is an issue and is managing their produced water as a resource instead of a waste.”

Encana’s implementation of different water management initiatives for its operations in Colorado and Wyoming reflects a shift in the company’s view of water, Mr Hock acknowledged. “Historically, we thought of water as something that was produced along with hydrocarbons, but our water team has pushed us to think about it as a commodity. We try to recycle whenever feasible, and we are looking at technologies that allow us to put water back, depending on how much we’re producing. In terms of the amount of water we get back, the geology is different in every area, so the rules for managing the water have to be flexible.”

In the DJ Basin, for example, the geology is such that much of the water is absorbed, with a return of only about 30%. “Any water we get back is needed for reuse,” he said. The company plans to start construction this year on a centralized facility outside Erie, Colo., that will collect oil, gas and produced water. The gas will be diverted to a sales line, and most of the water will be processed for reuse.

“As water is produced from one well, we will divert, via piping, as much of it as possible to another well for hydraulic fracturing,” Mr Hock said. While some water will have to be transported to disposal wells, truck traffic to disposal sites is anticipated to decline, along with the need for fresh water and costs related to solids control.

In the Piceance Basin in Western Colorado, Encana is using wells that have been plugged and abandoned for water disposal. Still, it recycles more than 95% of the produced water through 300 miles of pipeline to four water treatment facilities throughout the basin, he said. “Over the life of the well, we get back more water than we put in. Last year, Encana recycled almost 1.4 billion gallons of water, and from 2012 to 2013, we reduced fresh water usage by 70%.”

Sour gas removal enables water reuse for unconventionals well servicing

By Katie Mazerov, Contributing Editor

Sour water is traditionally disposed of due to safety and process concerns. Now, it is being treated for reuse in unconventional well servicing operations using a chemical-free sweetening process that physically removes the hydrogen sulfide (H₂S). AMGAS introduced the CLEAR process earlier this year. It has been used in approximately a dozen unconventional wells in the US and Australia, where access to freshwater is becoming more difficult.

“AMGAS developed the CLEAR process to provide a chemical-free way to treat sour oil in certain applications. However, the technology has really taken hold in areas where treating sour water is just as important,” said Sheldon McKee, Director of Business & Product Development for AMGAS. “CLEAR has shown it can reduce disposal and operational costs significantly in places like the Eagle Ford in South Texas, where water disposal and freshwater restrictions and access present logistical challenges for operators.”

Conventional methods of removing sour gas from fluids to make them safe for workers and the environment require the addition of chemicals to the fluids. These chemicals often include oil, condensates and water, Mr McKee explained. “By externally removing the H₂S, operators can recycle or dispose of the water much more easily because it doesn’t contain any chemical by-products.” It is especially important that water introduced to “sweet” formations be free of any H₂S by-products to avoid cross-contamination, he added.

H₂S occurs naturally in formation fluids but can also occur as a result of the introduction of water into the formation. AMGAS delivers treatment by way of temporary mobile units on site and on permanent installations.

The external removal process gives the system the capability to handle high and low concentrations of H₂S. It also eliminates the risk of over-treatment or under-treatment that can occur with chemical treatments, according to the company. After the H₂S is removed, the water is transported to storage tanks or put back online, depending on the operation. “We believe this is a more efficient, cost-effective and environmentally friendly way to remove H₂S, providing more flexibility for operators and well servicing operations,” Mr McKee added.

A freshwater alternative

Freshwater availability is a challenge in the Texas and Oklahoma basins, even in non-drought cycles. As an alternative to freshwater, Devon Energy is using brackish, or non-potable subsurface water, for operations in the drought-prone eastern shelf of the Midland Basin near San Angelo, said Dean Reynolds, Senior Engineering Advisor, Exploration and Strategic Services, for Devon. Most of the brackish water is pumped from wells into lined pits with covers, installed last year, which are saving more than 110,000 gallons of water per day from evaporation. “Using the brackish water makes economic and environmental sense. We’re eliminating freshwater demand, reducing truck traffic on roadways and improving safety,” he said.

“In the San Angelo area, we don’t have a lot of produced water, but we reuse as much as we can, about 70 to 75% with minimal treatment, and then blend it with the brackish water to meet our hydraulic fracturing needs. We don’t use any freshwater at all in that area,” Mr Reynolds added. “Ninety-five percent of our fracturing operations in the Permian are done with slickwater, with friction reducers that are compatible with higher TDS produced water and blended brackish water.”

Produced and flowback water is treated at central treating facilities in the field to remove residual hydrocarbons, kill bacteria and filter out suspended solids.

Devon’s use of freshwater alternatives is in keeping with the company’s sustainability principles to practice “efficient and environmentally sound use of water in our operations throughout the US, a philosophy that has evolved since we began recycling water in the Barnett back in 2005,” Mr Reynolds said. Devon has established a corporate water management team whose sole function is to expand that mission. The team incorporates water management into the company’s best practices and guidelines designed to address drought conditions and meet regulatory requirements that vary among regions. All of Devon’s asset development plans now include provisions for water management.

“We have to think about water to meet the needs of our hydraulic fracturing operations and production, but we also need to start thinking about the entire water lifecycle – from sourcing to use to disposal or reuse,” Mr Reynolds said. “We’ve developed a water lifecycle to show what takes place with one drop of water from the time we source that water, through the drilling operation, hydraulic fracturing, production and produced water.”

Three years ago, Devon constructed a 500,000-bbl impoundment in the Cana field of the Anadarko Basin in Oklahoma. It allows produced water to be carried via pipelines to a central treatment facility and then transported to wells for reuse in hydraulic fracturing operations.

The company also is active in academic consortiums and works with service company R&D divisions to study new technologies that would be more efficient and cost-effective than current reuse/recycling efforts. In the Rockies, near Gillette, Wyo., where the produced water is fresher and has lower TDS levels, Devon is looking at alternatives to disposing of excess produced water in injection wells, Mr Reynolds said. The effort simultaneously aims to reduce water usage through reuse of produced water and using crosslinked gel systems for hydraulic fracturing jobs, he added.

Competition for water

Looking at the bigger picture, competition for water among drinking, agricultural and industrial purposes could impact shale development as it expands globally, according to a report issued in September by the World Resources Institute (WRI). It is a global research organization focusing on a variety of issues, including water and energy. The report assesses 11 countries, including the US, Canada, Australia, Saudi Arabia, Argentina, the UK and China.

“The big challenge is the variability in supply and demand for water,” said Paul Reig, WRI Associate and lead author of the report. “There is a high level of uncertainty due to the tremendous variation of hydrological conditions and water stress, a measure of the rate of water withdrawal to the available supply.” Among the report’s key findings are:

• 38% of shale resources worldwide are in areas that are either arid or that are under high to extremely high levels of water stress;
• 19% are in areas of high or extremely high seasonal variability; and
• 15% are in locations exposed to high or extremely high drought severity.

The report has significant implications for global shale development. In the US, 35% of the area where shale is located is under high water stress or arid conditions, whereas in China, which holds the world’s largest technically recoverable shale gas resources, the figure is almost double that, Mr Reig noted. “More than 60% of China’s shale resources are located in areas of high to extremely high baseline water stress or arid conditions.”

In Argentina, South America’s largest natural gas producer and consumer, 72% of the country’s shale gas resources are in areas with low to medium stress, signaling less competition for water. “However, 28% of the resources are in arid areas, so the country will not entirely escape water-related constraints if shale development moves forward,” he said.

The report also notes that in the UK, industrial water usage accounts for more than 30% of the nation’s total water demand, but those withdrawals have been shrinking for the past decade as natural gas and oil production have declined. Government tax incentives to boost shale development could require greater water management, as high industrial and domestic demands for water push 34% of UK’s shale resources into high to extremely high water stress.

The WRI report was designed to raise awareness of the issue. It also offers recommendations aimed at collaboration for managing water in regions of unconventional resource development:

• Conduct water-risk assessments with tools like the Aqueduct Water Risk Atlas to understand local-level water availability and reduce business risk;
• Engage with local regulators, communities and industry to learn as much as possible about existing water demands and hydrological and regulatory conditions in river basins, while increasing transparency around shale development;
• Ensure adequate water regulations and participatory legislative processes to guarantee water security and reduce regulatory and reputational risk;
• Minimize freshwater use and practice corporate water stewardship to reduce impacts on water availability.

“We aren’t running out of water,” Mr Reig said. “The issue is more around how we manage it. There are tremendous opportunities for investment in solutions to help manage water and for increased collaboration between industry and government to protect water security while promoting energy security.”