Sep. 12, 2021

Regarding the Extraction of Geothermal Energy from Orphaned and Inactive Oil and Natural Gas Wells in Western Canada

In late July of 2021 I began an investigation into the practicality of recovering 'energy' from out-of-service Wells. It did not need to be just Geothermal energy; it could be thermo-electric or it might be a low flow of the resource for which the Well was originally drilled.

This research was initiated after a suggestion from an Environmental scientist that my experience might be put to use in this regard. Eight weeks have passed and in that time I have generated many geothermal and thermo-electric models for what are 'typical' Oil and Gas Well bores in Western Canada (Alberta and N. Eastern British Columbia), and the results are more than frustrating.

Let me explain;

Oil and Gas Wells drilled in Alberta tap into layers of sand, gravel and shale that sit upon relatively cold, Precambrian Shield basement rock. Well depths range between 600M and more than 3,000M, with 5,000M not unheard of. Although most of the land mass is cold, there are several geographic areas of Alberta where the basement rock temperature is relatively high and that heat transmits upward and into what is only a few Well boreholes.

By some accounting there are between 500 and 1,200 Wells with recorded bottom-hole temperatures between 90oC and 120oC, making them suitable for some form of Geothermal energy recovery. This is a small number out of the more than 100,000 Orphaned and Inactive Wells identified to date, most of which have temperature profiles reflecting a 25oC ground temperature rise per 1,000 meters.

For context, a more conventional Geothermal system is drilled into igneous and metamorphic rock where the temperature at 300 Meters depth can be greater than 100oC. When a suitably fractured reservoir of hot water is found, an open-loop system is applied and a thousand tonnes of hot water and steam are recovered daily, with the condensate and cooled water re-injected into the reservoir for reheating.

Similarly this type and temperature of formation supports a closed-loop system of heat recovery, where a hair-pin U-tube is inserted down hole to carry thermal fluid for heating. A closed-loop system does not contaminate the surrounding formation which means fluids with lower boiling points can be used to transport heat energy to surface. A single closed-loop system is limited by the heat medium fluid pump volume flow against 300 or more meters of liquid head pressure, plus that pressure required to overcome the friction generated by liquid flowing within the pipe.

Temperature and depth are not the only differences between an Oil/Gas Well and a Geothermal 'well' (bore hole). A Geothermal bore hole can have a bottom-hole diameter of greater than 250mm, where the inside of most Oil and Gas production casings is less than 100mm diameter. This narrow bore substantially limits the mass of thermal fluid available to transport heat energy out of the Well, no matter which system is applied.

Last on the list of observations made during the process modelling, but certainly not the least important component of the system is fluid production; getting the hot water to surface from an under-pressured, 3000 meter deep well. This depth was chosen for the first series of models because bottom-hole temperatures are expected to be above 80oC, and it is on the deep side of the average well. Wells of this depth are shut in when there is insufficient bottom-hole pressure to lift the fluid (gas/oil) to surface and it is the shut-in wells to which this research is devoted.

Deep wells are shut in when bottom-hole pressure can no longer push liquid to the surface because Jet pumps and Submersible pumps don't work well below 200 meters. At this writing, the only low energy option (of which I am aware) for lifting 80oC water from a depth of 3000 meters is a sucker rod pump. Sadly the trip from bottom-hole to surface requires almost 7-hours and the 1 M3/Hr of water that does make it to surface will contain less than half the heat it held at bottom-hole.

To overcome the transport challenge of drawing liquid from the bore hole, a closed-loop system might be applied, but not if the well is 3000 meters deep. A closed-loop U-tube pipe arrangement full of water weighs more than 48,000 kg per 1000 meters of well depth. Pipe wall thickness must increase to overcome not only the liquid head pressure at that depth, but it must also be thick enough to support its own weight.

Combine the need for thick pipe wall, partial insulation of the production leg plus a deep, narrow well bore, and fluid transport rates drop below 200 tonne per day; not enough energy to pay for operating costs, never mind paying back the capital.

Two thermo-electric generators were modelled; a thermopile and a thermocouple. A thermopile generates a usable DC voltage when one of it's two surfaces is many tens of degrees hotter than the other. Ideally there will be a 100oC difference between the two metal surfaces of the pile body.

When a thermopile is installed down-hole, there is no practical way to cool one surface of the thermopile to create a temperature difference. With both surfaces of the thermopile at the same temperature, no current is generated. Not that thermopiles generate much current to begin with and should some inexpensive method of cooling be found, there is the 3000 meters of insulated wire and its resultant voltage drop to deal with.

A thermocouple generates a very small current relative to the thermopile but it is more efficient at generating that current. Sadly the most efficient combination of dis-similar metals will only generate 4 millivolts at typical Well temperatures. This fact, combined with the voltage drop over even 1000 meters of cable renders this method of generating electricity impractical.

There is another way to use a thermopile on a Well and that is to draw off a relatively small amount of sweet, natural gas and burn it in a thermo-electric generator. This technology has been in use for decades to power remote well sites, which means this stable source of electrical power can be sold into the grid and/or used locally.

Tapping into a pressurised gas well, even if the gas flow is less than the well would normally produce, means that the well has been put back into production and must be monitored and maintained. This costs money which means the rate of electricity generated must cover these costs, plus the cost of installation.

It has taken 40-plus hours of research, process modelling and pipe string design to realise that my chances of mass producing down-hole heat exchangers to meet the challenges of MOST orphaned oil and gas wells are limited at the moment

Of the tens of thousands of wells under review, perhaps one-third of one percent have a suitable combination of bore diameter, shallow depth and high temperature to generate Geothermal energy. Hardly mass production.

In fact there are no two wells exactly the same which means that each well under consideration for some form of energy recovery must be thoroughly reviewed to establish not only the types of energy available but also the costs and liabilities involved in that energy recovery operation. This research will save millions of dollars in experimental equipment installation and perhaps identify means of generating energy not previously considered.

I thank you for your interest and reaching this point in the article. It would be my pleasure to work with you in establishing practical technology to exploit old and/or expended resource Wells and I look forward to your comments.