From Fire to Water


Even with the recent crash in prices, oil production from unconventional formations, such as shale or tight sandstone, has transformed the industry.

Since 2008, when U.S. crude oil production was 1,830 million barrels (lower than any year since 1947), the country has become the largest petroleum producer in the world, with production in the 12 months through October 2015 at an amazing 3,412 million barrels.

The combination of horizontal drilling and hydraulic fracturing gets the credit for most of that increase.

But the so-called fracking revolution has had a downside, which is not well known to the general public: the increasing cost of water for oilfield operations. According to data from the Interstate Oil and Gas Compact Commission and the Ground Water Protection Council, while the drilling of an average well requires about 250,000 gallons of fresh water, the hydraulic fracturing of a well is much more water-intensive, averaging about 2.5 million gallons water per well.

Much of this hydraulic fracturing activity happens in regions with acute water shortages. Some 48 percent of U.S. wells are located in extreme water stress areas, where more than 80 percent available ground and surface water is already allocated for such uses as agriculture, power generation, and human consumption. Several oil-producing states expect added stress on limited water supplies from future population increase.

The Eagle Ford formation in south Texas is considered ground zero for fracking-related water issues. There are thousands of wells in the Eagle Ford region, and they consume water at a rate about double the national average. Compounding the problem is that 98 percent of the wells there are in areas with at least medium water stress, and 28 percent are in extreme stress areas.

It makes sense that there would be a scramble for water in south Texas, but surprisingly, water is also a bottleneck in the Bakken, despite its location in the wet and cold climate of North Dakota.

There, the challenges are attributed to a lack of access points, limited storage depots, and permitting restrictions. In oil and gas production regions as diverse as the Marcellus in Pennsylvania and the Monterey in California, water issues are a big concern.

These water challenges are starting to significantly affect the bottom lines of oil producers, particularly in the current low-price environment. Treatment and reuse of flowback and produced water is a promising option, but is associated with high water treatment costs. Freshwater supply for fracking has rapidly become a multibillion dollar business with several leading oilfield services companies getting in the game. Freshwater procurement can cost up to 3 cents per gallon in some areas. The real wallet drainer, however, is transportation which can cost as much as 12 cents per gallon. Total water costs can therefore reach as much as 15 cents per gallon, which works out to $6 per barrel of water or as much as $2 per barrel of oil produced.

It isn’t just the direct cost to oil producers. Trucks are the workhorse of water transportation and trucking distances can be huge. Trucks bring along the expected problems of traffic, road damage, noise, and accidents, which make for unhappy communities.

While obtaining water is a headache for drillers, they also have at their disposal the means for providing their own water. A technology known as atmospheric water harvesting can wring moisture from humid air at a surprisingly rapid rate. And though the technology has a reputation for being energy-intensive, oil production sites often have on hand fuel that they can’t use—and indeed, simply burn (flare) off.

By harnessing natural gas that is now often just flared off, oil producers could eliminate a large fraction of their water needs.


Flaring is a big problem in its own right. While oil spills and refinery explosions get widespread media coverage, flaring often manages to stay below the media radar, despite having severe negative consequences in terms of pollution and constituting an enormous waste of energy.

The extent of the problem can be seen from satellite images of the Earth’s night side: flared gas creates bright gashes in sparsely settled areas from Northern Africa to North Dakota. About 140 billion cubic meters of natural gas was flared worldwide in 2012, which is the latest year for which figures are available. That is 4 percent of global production or 20 percent of gas consumption in the United States. By any yardstick this is an enormous waste of energy, and would be valued at over $50 billion at today’s natural gas prices. Flaring also accounts for more than 1 percent of global carbon emissions.

The U.S. has seen a rapid increase in the amount of gas being flared, and now the country is the fifth largest flarer in the world, behind Russia, Nigeria, Iran, and Iraq.

Some 40 percent of the flaring in the U.S. occurs in North Dakota, where it is estimated that a third of the gas produced is flared, since the Bakken is primarily an oil play with gas having a marginal value. Certain Bakken producers flare more than three-quarters of the gas produced. In Texas, the second-place flaring state, development of the Eagle Ford Shale increased flaring by 400 percent from 2009 to 2012. Eagle Ford now accounts for 54 percent of the flaring in Texas despite having only 3 percent of the state’s wells.

One reason that both the Bakken and the Eagle Ford fields produce so much wasted gas is the wide employment there of hydraulic fracturing. After fracturing and completing a new oil well, there is an initial burst of natural gas, like the gas that fizzes out when you pop a soda can. Most oil wells in these regions do not have the infrastructure in place to utilize or capture this gas, and flaring remains the only practical solution to dispose it off.

Flared gas-powered vapor absorption cycle for atmospheric water harvesting: The water condenser draws moisture from the air; a secondary liquid absorbs the evaporated refrigerant; a gas-powered boiler heats the solution to release the refrigerant as high-pressure vapor.

Other factors promote flaring as an option. Texas producers, for instance, do not pay royalties or taxes on flared gas, and there are no restrictions on flaring in North Dakota in the first year, when most of the flaring actually happens. Recent rules in North Dakota require producers to have gas capture plans for new fields, but it is doubtful that regulations alone will reduce flaring, since more than half of flaring in North Dakota is from wells already connected to gas-gathering infrastructure.

Flaring is a big missed opportunity for producers. The biggest reason for producers to sell oil and burn gas is that gas has a much lower value than oil. But there are innovations that utilize flared gas to create value.


Flared gas has been used for onsite electricity generation; however, this requires sufficient onsite demand or access to the grid. Extraction of natural gas liquids (NGLs) from the gas stream is another option that is practiced in some places. Reinjection of gas to the reservoir provides another alternative to flaring, but increases the cost of the project. More recent efforts have studied the use of flared gas to treat the flowback water that follows fracking.

While the emergence of such technologies is encouraging, the solutions involve expensive infrastructure which often reduces the economic advantage of flared gas utilization projects.

Water, on the other hand, is a bottleneck to oil extraction and is increasingly more valuable than electricity or NGLs. And it turns out that there is a means to use flared gas to create water right at the production site.

The solution is called atmospheric water harvesting, or AWH. The idea is to tap the enormous freshwater reservoir in humid air by condensing moisture on chilled surfaces using a refrigeration cycle, similar to what happens in an air conditioner or a dehumidifier. This can be done even in places that receive very little rainfall.

Much like a refrigerator, however, the AWH process is very energy-intensive. Indeed, the cost of energy has been the deal breaker for industrial-scale AWH. Over the last decade, for instance, several electric-powered AWH units have been developed that are capable of harvesting hundreds of gallons of water per day. But the cost of the harvested water is more than 20 cents per gallon, which makes such harvesters impractical for industrial scale operation.

But electricity isn’t the only way to power refrigeration cycles. In places where electricity is unreliable or prohibitively expensive, propane or kerosene-powered refrigerators are available. Similarly, a large-scale AWH system can be run using gas (or some other energy source, such as sunlight or wind).

In a natural gas-powered vapor absorption refrigerator, cooling is generated by evaporating a suitable refrigerant in a bundle of tubes called an evaporator. The evaporated refrigerant is then absorbed by a secondary liquid. The refrigerant-saturated solution is then heated in the vapor generator to release the refrigerant as high-pressure vapor. This vapor condenses in the air-cooled condenser, and the cycle continues.

Natural gas from the wellhead that might otherwise be flared off can be fed to a boiler (after treatment in a gas conditioning module). The steam generated in the boiler can then be used to release the refrigerant in the vapor generator of the refrigeration cycle.

Vapor absorption-powered AWH has advantages over other refrigeration options, such as vapor compression and desiccant dehumidification. Calculations indicate that cooling via vapor absorption yields more water than competing technologies, because of the higher cooling capacity generated per unit of gas burnt. An important advantage is that, at the wellhead, the gas is essentially free.

The amount of water that can be expected to be harvested depends on flaring rates and the ambient weather. The average flaring rate per well in the Eagle Ford is 9,600 cubic meters per day; for the Bakken, it is 5,500 cubic meters per day. Employing that gas to run AWH units instead of simply flaring it could yield as much as 30,000 gallons of fresh water per day from a single well in the Eagle Ford. From the Bakken, that figure is 18,000 gallons. Such harvest rates are possible from the gas that gushes out of a newly fracked well. Gas production declines in the weeks and months after a new well comes online. The decline rates vary a lot and are not well reported, which makes it challenging to predict the water production over time. In all, about 2 billion and 4 billion gallons water (about 10 percent and 66 percent of total water consumption) can be harvested annually from all the gas flared in the Eagle Ford and Bakken respectively.

What can that water be used for? While many oilfield operations require water, the two most important ones are drilling and hydraulic fracturing. At more than 50 locations in the Bakken (which flare more than 34,000 cubic meters per day), the water required to drill a new well can be provided onsite using flared gas in just three days. The water required to frack a new well can be met in three weeks. Those numbers suggest that with proper planning, AWH can supply a significant fraction of the water required to develop additional wells at existing sites. All told, 22,000 wells can be drilled or 2,200 wells can be fracked from the water produced annually by using flared gas in North Dakota and Texas.


The benefits of onsite water harvesting go beyond reduced water costs. For each well that is fracked with AWH water, 450 truck roundtrips are eliminated. My research estimates that using harvested water can eliminate 7 million truck roundtrips annually in Texas and North Dakota. There are many other soft benefits in the form of goodwill generated in local rural communities due to reduced traffic, pollution, and accidents.

Despite the strong case for flared gas-based AWH, there are still challenges to be overcome before this technology can be deployed. For instance, in order to make the technology economically viable, the AWH system has to be made compact to the point that it can be mounted on a semi-trailer. Portability is critical, since flaring is a temporary situation and the equipment needs to be relocated where it is needed.

The systems that are the most cumbersome are the water condenser and the air-cooled heat exchanger, both of which are bulky configurations of metal tubes and plates. Researchers are working to increase the performance of the condensers by coating the condenser tubes with water-shedding superhydrophobic materials, which drain the condensed water and can increase the thermal performance by a factor of ten.

Similarly, there are multiple R&D efforts targeted at developing compact, lightweight air-cooled condensers. Notably, the Advanced Research Projects Agency-Energy has a specific program on this effort. The good news is that large-scale refrigeration systems of the required tonnage are already available. Ongoing R&D efforts across the nation will provide solutions that make this technology more viable than it is today.

Looking beyond the United States, AWH can benefit oil producing regions such as the Middle East and portions of Africa which flare large volumes of gas, face perpetual water crises, and have year-round high humidity. The technology can also be positioned as an alternative to desalination in humid places with high flaring rates, but which lack brackish water sources that could be treated.

In an era when natural gas prices have remained stubbornly low, employing this technology in parched countries could be a means to provide a new market for natural gas.

“Keep burning gas, but to create water” sounds like a business-as-usual message to an industry that is traditionally slow to change. It remains to be seen if industry has the fire to fight flaring with water.

Vaibhav Bahadur is an assistant professor in the Department of Mechanical Engineering at the University of Texas at Austin.
Total water costs for a fracked well can reach 15 cents per gallon, which works out to as much as $2 per barrel of oil produced.


March 2016

by Vaibhav Bahadur, University of Texas at Austin