Hot fluid is a byproduct of many oil and gas wells across the country. At least 25 billion barrels of it are produced each year, according the U.S. Department of Energy (DOE). The hot water has proved burdensome for many oil and gas producers historically, especially with respect to disposal. But research has demonstrated that the fluid itself is capable of producing energy, and it can actually help cut costs for energy producers instead of raising them.
Researchers at the University of North Dakota (UND), with support from the DOE Geothermal Technologies Office (GTO), helped launch the nation’s first commercial enterprise to co-produce electricity from geothermal resources at an oil and gas well earlier this year. UND researchers successfully bred geothermal power from hot water that flows naturally from petroleum wells in the Williston Sedimentary Basin in western North Dakota. The facility started generating electricity for the first time in April.
“If we can capture that energy, it’s almost like free and clean energy, off of an oil and gas production.”
“It’s a definite breakthrough,” says Karl Gawell, executive director of the Geothermal Energy Association (GEA). “People have talked about the potential for years, knowing that there’s hot water in oil wells. Nobody had really put a permanent system in place. … So this is, to me, a really momentous time.”
The research project received the 2016 GEA Technological Advancement award in June and Gawell says it ties in closely with the association’s mission to expand the use of geothermal resources. He says there is an abundance of megawatts of power available from oil and gas wells in the U.S.
“So we’re literally wasting it right now because most of these wells are pumping up hot water,” he says. “What are they doing with it? They’re reinjecting it and not using the heat. So if we can capture that energy, it’s almost like free and clean energy, off of an oil and gas production. I think it’s one more way to get the job done in terms of changing our energy system.”
Will Gosnold, professor of geophysics at UND and principal investigator of the research projects, says he has always been interested in this kind of thing. Starting in the late 1970s, he was involved in research that aimed to estimate the amount of thermal energy stored in relatively shallow areas geothermally speaking, not much deeper than three or four kilometers. He found that there is a lot of heat there, but realized it could not do much good without being brought up in some useful form.
“Then along came the idea of producing the fluids from the oil fields. This was others in, I think, about 2005 when it started coming out in the literature,” Gosnold says. “I saw that and got pretty excited about it because I realized that at that time, we could have a use for all of that energy that is there. It’s now coming to fruition; 10 years later, but these things do take time.”
He says his team received the DOE grant in 2009 and they immediately started developing the system. He expected to be done by 2012. Largely because of the oil boom in North Dakota, he says the price of oilfield operations in construction skyrocketed, so a lot of the time was spent raising additional funds.
“I think potentially it’s huge because we could supply an enormous amount of power from the oil fields,” Gosnold says. “I’ve already been contacted by several geothermal developers who want to come in and try to do this themselves as a business.”
He points out that while the oil industry is generally focused solely on pumping oil and gas, and selling it, the drop in oil prices makes the major cost of electricity especially heavy. With the opportunity to generate geothermal energy from existing wells of their own, there is potential for oil and gas producers to power their entire operations at virtually no cost.
Gosnold says this also opens the door to distributed power systems that are immune from the power grid and are not affected if the grid goes down. Should the oil field play out, he says, the geothermal power can be fed into the existing power grid and the power company, the new recipient, can sell it.
The two horizontal wells involved in the research project are about 8,000 feet deep, Gosnold says. Owned and operated by Continental Resources, they were initially drilled for oil and gas production purposes. He explains that pressure in the oil field tends to drop over time, meaning oil does not flow to production wells as it did when production began. The two wells, which together have a flow volume of about 875 gallons per minute, address the slowdown by injecting water into the oil-producing formation, toward the oil production well, and pressurizing it.
One of the challenges Continental Resources was running into, and one reason they were interested in being a part of the research project, is the high temperature of the water, Gosnold says. It created safety hazards around their site and was tough on the injection equipment as well. The company was cooling the water through two large cooling towers, which used a lot of electricity.
Now the water is still primarily used for water-flood oil production, but also secondarily to produce geothermal power. It goes through organic Rankine cycle engines (ORC) prior to going through the cooling tower. So heat is simply being taken from the water as it passes through the system, then the water is sent back to the injection system. The fact that the heat is being taken from the water not only makes the process safer and easier to handle; it also means that instead of using electricity to cool the water down, electricity is being generated by cooling the water down.
Essentially, the technology offsets the need for costly transmission construction and reduces energy costs at remote oil fields. According to the DOE, co-produced geothermal resources like these have the potential to produce significant amounts of baseload electricity at low costs and with near zero emissions.
That said, these energy sources aren’t as deep and hot as traditional geothermal resources. Often referred to as low-temperature, the co-produced resources represent a small but growing sector of hydrothermal development in geothermal resources below 300 degrees Fahrenheit, according to the DOE. They are considered non-conventional hydrothermal resources. Gosnold says these particular wells supply water around 212 degrees Fahrenheit.
In addition to electrical energy, co-producing geothermal systems could help power up drilling job prospects. In cases like this one, wells may need to be further developed. That could mean drilling deeper — vertically, horizontally or both — or widening hole size. A geothermal production well is typically two or three times larger than an oil or gas well because higher fluid volumes are necessary.
Drilling expertise could also come in handy to repurpose actual oil or gas production wells when they play out and it is no longer economical to use them. Gosnold points out that larger pumps could be installed to pump the wells at much faster rates and produce high volumes of water. What’s more, entirely new wells may need to be drilled altogether.
“In many of these cases, they’re going to have to look at the sedimentary basins where they’re getting this type of oil and gas recovery and realize they might be able to get additional recovery from drilling additional wells,” Gawell says.
He says that geothermal continues to grow in the U.S. and around the world, but that we are still at the front end of the process.
“Today we’re producing in about 28 countries and we’ve got about another 15 or 20 under development. So you’re seeing things move in the right direction. But I think we have to get beyond the slow pace I think we’re facing today,” he says. “It’s a question of human knowledge and ability. I’ve always thought that when the challenges require us to learn how to use our brains and our ingenuity to do things better, we can win those battles.”
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