by Elizabeth Lappin, P.Geo
Elizabeth is the Geothermal Ambassador Coordinator at CanGEA, and the Founder of Castle Rock Consulting Ltd.
Alberta’s oil and gas wells produce thousands of barrels of water each day. This water is considered a waste by the oil patch, and operators pay to send it away by pipeline or truck.
But what if that water had a value? Albertans spend a lot of money heating water with natural gas. And yes – natural gas is pretty cheap right now – but costs are about to jump $1 per GJ in 2017, and an additional $0.50 in 2018 due to carbon taxes. Delivered natural gas costs in Alberta could reach over $8-10 per GJ within two years.
And that means geothermally-derived gigajoules will become cost-competitive in certain markets. Hot salty brine, or “formation water”, produced alongside oil and gas at temperatures above 30oC, can be used in a variety of direct-use applications.
These include central district heating, greenhouses, pasteurization, and even brewing beer. 46oC geothermal waters heat the popular Temple Gardens Mineral Spa from a well doublet in the Williston Basin.
Higher temperatures waters above 90oC are capable of generating power.
Geothermal Direct Use Applications & Opportunities Report, CanGEA, 2014
30oC isn’t hard to come by at depths over 1km, which means there are almost 240,000 wells to choose from, either operating or not, in Alberta alone. While not all these wells will be suitable for geothermal conversion, even a small fraction represent a huge opportunity.
The geothermal industry is well poised to take advantage, and oil and gas to geothermal well conversion is not far off. The Living Energy project in Devon, AB, will soon convert an old water disposal well near Leduc #1 (the well that kick-started Alberta’s oil industry) into a geothermal heat well, which will provide up to 120,000 BTU of heat for space heating and vertical farming.
In the Williston Basin in North Dakota, a demonstration oil and gas and geothermal co-production pilot is now producing 250kW of geothermal power. This is the same Williston Basin that stretches up into Saskatchewan with much of the same geology.
The joint venture project by the University of North Dakota and Continental Resources came online in April of this year, with the future intention of using the technology to deliver decentralized power to oil patch operators as an alternative to propane or diesel-sourced alternatives.
Over 80,000 wells in Alberta are currently inactive. Some of these wells were dusters to begin with, and some of them produced oil or gas over several decades, eventually declining to uneconomic flow rates. Many of these wells now sit idle in Canada, while operators await a favourable price environment, and delay abandonment costs (which range from 10’s to 100’s of thousands of dollars).
In light of the increase in orphaned wells due to bankruptcy in Alberta, it’s especially pertinent to consider recycling the wells into heat resource money-makers. Retrofit costs will vary depending on the application: Hot water can be circulated using a well “doublet” (a production and injection well), or secondary fluids can be circulated inside single wellbore using a U-tube or dual pipe installation. Heat is extracted from water using a heat exchanger.
A regulatory framework is in development by the Alberta provincial government, which will include new rules around permitting geothermal wells and “mineral” rights in the form of heat.
The oil patch has tremendous geothermal heat resources. Existing wells that are a liability to the oil patch and a nuisance to farmers and landowners can be converted into greenhouses, growing year-round fresh, local organic produce.
But the potential doesn’t stop there. Central district heat for municipalities, aquaculture, beet sugar extraction – or really any thermally intensive industry at all — can benefit from this resource, and that doesn’t even include the power opportunity.
The Oil Patch is in hot water, and the only question is: Who’s going to make money on it first?