The Western Canada Sedimentary Basin (WCSB) is well known as one of the world’s largest reserves of petroleum and natural gas. It is just beginning to be recognized for its massive potential for alternative energy – specifically deep, conventional geothermal energy.
The section of the basin that lies in Northeast BC (NEBC) and northwest Alberta (NWAB)has been a focus for abundant natural gas and natural gas liquids (NGLs) extraction and is now of interest for geothermal projects. This region has above-average heat flow, likely the result of the radiogenic nature of the basement rock.
There is a recognized potential for geothermal energy projects that could reduce GHG emissions for natural gas projects as well as supplement heating for nearby communities with potential for hydrogen (H2) production using excess geothermal power.
In August 2019, Natural Resources Canada announced $25.4 million in funding for a major project known as Alberta No. 1. Alberta No. 1 is a $90-million electrical and heat project and will be Alberta’s first conventional geothermal energy facility. The majority owner is a Terrapin Geothermics a waste heat recovery and geothermal company.
Catherine Hickson, Alberta No. 1’s CEO has a perspective on geothermal projects in Alberta, B.C. and globally, having experience with greenfield exploration & discovery, and operations in 24 countries. Hickson is a volcanologist, who spent 25 years as a research scientist with Natural Resources Canada and has now been involved in the geothermal industry for 41 years.
Hickson says 2019 was the year that interest in geothermal increased from countries like Canada and Eastern European countries – countries that some didn’t think of as countries that have geothermal resources. In January of 2020, she attended the International Renewable Energy Agency (IRENA) convention in Abu Dhabi – working very closely with Natural Resources Canada
It seemed geothermal was taking off until the onset of COVID 19 in 2020. By January 2021 companies had adjusted to the Covid environment and there has been an increase in both conventional geothermal companies an unconventional geothermal like Eavor Technologies who are working with closed-loop systems as previously reported in the BOE report.
Hickson says versions of closed-loop systems are prevalent in the geothermal industry, variously called downhole heat pumps, geo-exchange systems or ground-source heat pumps.
Unlike the earlier use of downhole heat pumps, these newer closed loop systems, incorporate purpose drilled wells, sealed to carry a secondary “working” fluid that will then scavenge the heat from the subsurface and bring it to the surface using the concept of a thermosyphon. She notes that more U.S. companies and companies in the UK are starting to look into this technology as well.
“What I think is important right now is innovation. In the geothermal industry, it is vital. Closed loop companies need to prove the commercial viability of these systems with their purpose drilled wells, and that hasn’t been done yet. The question with closed-loop technology is whether or not it can be economic simply because of the amount of drilling that’s required,” says Hickson.
Drilling is also one of the hurdles for deep geothermal projects whether they be closed or open-loop systems. Because of the drilling costs, the capital investment that’s involved can make geothermal projects scary for investors, according to Hickson.
She says one way to overcome that hurdle is having geothermal projects, particularly in Alberta, that demonstrate that the technologies work. Conventional deep geothermal has been proven around the world in many settings.
She points out that electrical generation from geothermal is not new and the first project was done in Italy in 1904. What is new is how we adapt what we already know from other systems and other places in the world to Alberta to southern Saskatchewan, and Northeastern B.C. -the sedimentary basins.
“So that’s where the innovation comes in. We’re so blessed with sedimentary basins I think Canadians would be crazy to not be interested in investing in them for their heat content. Hydrocarbons are here to stay – they are an incredibly valuable source of heat and energy. But what we’re trying to say on the geothermal side of the equation is that we can help, we can supplement we can provide sustainable heat in the long term,” says Hickson.
Geothermal development in the United States is similar to what’s happening in Canada. Hickson points out in areas like California, and Nevada, there is continuing geothermal development, because these are hot, high-temperature systems. They’re documented and have already been in production.
The Dixie Valley geothermal plant in Nevada for example is coming up on 40 years of operation. Hickson says one of the challenges in California -where some of the best US geothermal resources are- is in an area called the Salton Sea- in Southern California. The hot fluids in that location are also very high in total dissolved solids – basically salt. She points out there’s a lot of innovation and technology testing to generate the power with very salty brines.
“Of course, since salty brines have high concentrations of lithium, adding lithium extraction to your geothermal project is looking to be a very cost-effective value-added way of getting your geothermal project going,“ says Hickson. “You are getting additional money coming in from lithium extraction, especially with the high cost of lithium right now combined with the shortage of supply.”
In Nevada, although they don’t have the same concentration of lithium in the brine– (much like Alberta) advantage is the reservoirs are known to be hot.
Turning back to a discussion about Alberta, the advantage is the province not only has hot brines, but they are also in significant quantities. They are located in areas where hydrocarbons are being extracted. We know from hydrocarbon production that the reservoirs exist that could be tapped for geothermal. But the value of a geothermal resource is significantly less than the value of the hydrocarbons being extracted.
Geothermal projects are carbon neutral but could be developed to be carbon negative. There is potential for geothermal projects to be combined with carbon sequestration helping reduce GHG emissions for natural gas projects and providing value to those operations.
When considering geothermal heating, there are immediate price hurdles. Currently, in Alberta, we have natural gas-fired power plants that create a lot of power with high BTU natural gas very efficiently, at a relatively low carbon footprint and relatively cheaply.
In addition, most buildings in Alberta are heated by natural gas boilers. Natural gas is piped directly to homes and that infrastructure has already been paid for and put in place. Hickson points out to consider heating homes with conventional geothermal, the ideal scenario is in a new subdivision or industrial complex. You essentially create a whole new infrastructure with and for geothermal.
“I think the best thing that the industry can do is to focus on a new build. Here’s where I think that governments could play a role especially if they are building government buildings-multiplexes or sports complexes-large buildings,” says Hickson.
She has encountered a further challenge to the application of geothermal for new subdivisions. A developer in Saskatchewan who develops large suburbs and public buildings was interested in putting a conventional geothermal system into a new subdivision.
Besides facing the high cost of drilling the system a market study revealed that people still wanted natural gas service to their homes because they want to run their fireplaces and barbecues.
“There would no cost savings in the short term,” says Hickson. “So even in a new subdivision, we’re not talking about replacements, we’re likely talking about, augmenting natural gas systems.”
There is an option that geothermal has to compete against the low price advantage of natural gas. Geothermal is competing on a BTU basis with natural gas, which is very low cost and already has built infrastructure. It’s also competing against the low price of electricity. But the additional value that geothermal has in the Alberta marketplace is that the Alberta electrical grid is quite carbon-intensive.
The Alberta No. 1 project generates a type of credit -not exactly a carbon credit, but an offset because the project is selling electricity and thermal energy onto a carbon-intensive grid and gets carbon credits or offsets for producing low carbon energy.
Another interesting development is the use of waste heat in oil and gas processing. Hickson points out that many large industrial processes, particularly hydrocarbon processing, or pipelines with compressors, create waste heat that can be converted into electricity. The industry has long been aware of and developed processes to use that energy. Waste heat projects use this generated heat, putting it to useful purposes.
The Clark Lake project, just north of Fort Nelson NEBC is an example. It is a project looking at repurposing an abandoned gas field to produce geothermal energy. The project is an economic development initiative of Fort Nelson First Nation.
They have repurposed one existing gas well as a geothermal injection well and drilled a second, new production geothermal wells as of Sept 2021. In March 2021, Natural Resources Canada announced $40.5 million in funding for the project.
“The Clark Lake field is a hot field and it’s known to have very high water flows, which is why the project is located there. It’s a conventional geothermal project. hopefully, they will be successful. Certainly, their early results look very encouraging,” says Hickson.
Hickson sees a lot of promise in Proterra energy’s proposed project in the Jedney field. The company proposes to use natural gas-fired electrical generation – but they’re going to augment that natural gas fuel with their hot geothermal fluid that they produce at the same time as they’re producing oil and gas.
This is a development pathway already started down by Futera Energy in Alberta who are calling it co-production- it’s very innovative. Instead of wasting the heat you already have- use it to augment the electricity that you’re planning to generate. I think we’re going to see a lot of growth in the geothermal industry both in Canada and in the US using co-production facilities.
“You’re already pumping oil and gas to the surface and it’s hot. Typically in an oil and gas field, you don’t produce just oil and gas. There is a certain percentage of water mixed with the hydrocarbons, called the water cut. Many of the fields in Alberta as well as in the US have a very high water cut- as much as 98%. So you produce that water-cut. If that water cut is hot, why don’t we use that heat before we have to dispose of it?”
With geothermal advantages in Alberta, geothermal could become an increasingly important component of delivering on carbon reduction commitments, especially when paired with oil and gas production. Attention has turned to Alberta’s regulatory regime and the changes needed to facilitate collaboration with geothermal projects., according to Catherine Hickson.
In the case of the Alberta No. 1 project, it is a conventional geothermal project which has advantages because it is more flexible in terms of which products are produced from their wells, creating different revenue streams. The project uses purpose-drilled wells to extract brine. So the advantage of this process over a truly closed-loop system, is that the brines are brought to the surface.
“If those brines happen to contain oil and gas, those products could be extracted. If they happen to have lithium, we could extract that too. There is certainly a discussion about the lithium concentrations in the oilfield brines of Alberta, but we have to have rights to those commodities or work on partnerships with the current rights holders,” says Hickson.
New regulations- Alberta’s Bill 36 Geothermal Resource Development Act came into effect January 1, 2022. Hickson says the bill is a start, but on the face of it, there are still apparent hurdles to supporting a stand-alone geothermal industry in Alberta.
Alberta No. 1 is currently going through the new process to apply for geothermal leases, when complete, they will have a much better understanding of just how the government is going to apply the new regulations. In areas where petroleum and natural gas (PNG) rights are already divested, it will be interesting to see if it is possible to obtain the right to drill for geothermal resources as a stand-alone development.
“In the case of Alberta No. 1, we have three sites and each of the three sites has a different problem that needs to be addressed by the regulations. One of the sites has a fully abandoned well with the wellhead removed. This gas well has a completion at a shallower level than where we’re wanting to drill to. We can’t hold the surface rights because of that existing gas well, and we do not have the rights to the completion zone.
“At a second site there is an existing water well, and a PNG rights holder who has objected to us drilling under our Metallic and Industrial mineral permit. The third site, where we hold the geothermal rights, we are not allowed to apply for the well licence until after the directives for Bill 36 is made public. We have been advised that this will be sometime in April or May.”
Hickson makes a case for regulatory development that is more supportive of oil and gas and geothermal project collaboration. She says geothermal can only be supportive of and a supplement to the oil and gas industry.
Maureen McCall is an energy professional who writes on issues affecting the energy industry.