Geothermal Energy is heat that is stored and generated within the Earth. It is partially residual heat from the planet’s formation and partially new heat generated by radioactive decay within the Earth’s crust. This energy source is not a new or novel one in the green revolution we are currently in. But it is an energy source not being utilized near its full potential.
Humans have been utilizing this energy for over 2000 years. Recorded instances of geothermal energy use date back to the 3rd century BC, when the Chinese built a hot spring spa on Mount Lisan, which later became the site and heat source of the Huaqing Chi Palace. The Romans widely used geothermal energy for heating public baths. In the first century AD, the Romans conquered Aquae Sulis (present-day Bath, England) and used the local hot springs for public baths and underfloor heating (Cataldi, 1992). The first residential heat networks were used in the 14th century AD in Chaudes-Aigues, France (Lund, 2007).
While using geothermal energy to heat water and buildings is not new, using geothermal energy to generate electricity is a more recent usage. In 1904, the first successful test to use geothermal energy to generate electricity was completed in Prince Piero Ginori Conti, Italy, where electrical energy was generated to power four lightbulbs. While this was a small start, by 1911 at this same location, the world’s first commercial geothermal power plant was constructed (Tiwari & Ghosal, 2005).
Through the 1960s, geothermal plants were being constructed worldwide, resulting in 14,900 MWatts of global production capacity (ThinkGeoEnergy, 2019). In comparison to the world’s energy demands, geothermal energy supplies only a fraction of a percent of the world’s electricity. Unfortunately, geothermal energy has been slow to develop due to the associated high costs relative to hydrocarbon exploration and development. This is due to the need to drill deep wells into hot strata in hopes of finding a permeable reservoir.
The development of traditional power generating geothermal systems is quite simple. Two wells are drilled into a hot, permeable reservoir, which are often referred to as doublets. One of the wells, called the producer well, pumps hot formation water brine to the surface to feed a power generating plant. The cooled water brine is then returned to the reservoir via a second well, called the injector well.
Hot, permeable reservoirs are often challenging to discover as they typically need to be close to a high heat source such as volcanos, in a rift valley where the crust is thin, or target deep rock strata in sedimentary basins. For example, the largest geothermal field in the world, the Geysers Field in Northern California, produces from a sandstone reservoir, which is believed to have a magma chamber immediately below, superheating the rocks and fluids in the field. Iceland is well known worldwide as a pioneer for geothermal energy and heating. Due to the tectonic plate rifting through Iceland, there is a high concentration of volcanoes which heat underground geothermal reservoirs.
While some geothermal operations produce only hot brine from the subsurface, in instances such as the Geysers Field, both hot water and/or in situ steam are produced, which can both be utilized by a geothermal plant – depending on the plant design. Steam is utilized in Dry Steam Plants where the reservoir temperature is generally 240-300 °C. The product from the reservoir at surface is entirely steam vapour. This steam is used to power, turbines which in turn produce electricity. Two geothermal fields, Geysers (California) and Larderello (Italy), have formation temperatures that are hot enough for dry steam production.
When temperatures are greater than 200 °C, and hot liquid water is produced along with the steam, Flash Steam plants are utilized. These plants pump the hot water and steam brine into a separator. The separator ‘flashes’ the hot water with cooler water, creating more steam which in turn separates the steam to be used in power generation.
The third and most common type of plant is referred to as a Binary Cycle Plant. These binary cycle plants can utilize hot temperatures in combination with fluids with temperatures below 100°C. The produced fluid is pumped into a heat exchanger and is used to heat up a fluid with a lower boiling point (typically isobutane), causing it to flash vaporize and drive the turbines. These binary cycle plants can be used in traditional geothermal as well as co-production from oil and gas operations.
The estimation of the installed capacity (the amount of electricity under ideal conditions) of a geothermal power plant relies heavily on the temperature and flow rate the target reservoir is capable of. Geothermal capacity is fundamentally how much energy is extracted from the hot fluid coming to surface. The calculation of plant capacity can be simplified to the following formula:
This plant capacity can be multiplied by a recovery efficiency to estimate power generation. Estimation of flow potential of a reservoir requires understanding the components controlling productivity in a target reservoir. Additionally, understanding reservoir temperature is an important factor, as it is directly correlated to the input temperature of a plant.
Hot water brines produced from reservoirs can also be used for district heating rather than power generation. District heating is a system of distributing heat from a centralized location i.e. geothermal well, through a series of insulated pipes to be utilized for residential or commercial heating requirements, such as space heating or heating water. For example, in the Paris Basin, hot water is produced from the Dogger Sandstone and is fed into a district heating network which is popular in many European cities.
Enhanced Geothermal Systems (EGS) have gained traction in the geothermal spotlight in the past few years. These systems drill into ultra-hot basement or volcanic rock. One well injects cold water at high rates, causing the surrounding rock to fracture, also known as hydroshearing. If the hydroshearing fractures develop according to plan, the fracture network created will communicate with the second producer well. The water injected heats up within the induced fractures and is produced from the producer well. By continuing to inject water, the fracture network will remain open. The development of these systems requires a strong understanding of the geomechanical properties and stresses of the rock to estimate the direction of growth of the fracture network.
Canadian company Eavor Technologies Ltd. (a current client of GLJ) has drilled a pilot for a new geothermal technology near Rocky Mountain House, Alberta. They have utilized oil and gas horizontal drilling technology to design a closed-loop system that uses conduction to heat fluid running through the wells rather than producing hot formation water. The system does not produce any brine or rely on hydraulic fracturing. The fluid in the wells are closed off to the reservoir, and the only interaction between the reservoir is heat through conduction.
The closed-loop system, Eavor-LoopTM, consists of large U-tube shaped wells at depths of around 3 kilometres, with several kilometres of multilateral horizontal wellbores. Two drilling rigs are operated simultaneously from both sites and intersect the multilateral wellbores at depth. Water is circulated in the inlet well, through the parallel wellbores to extract heat by conductive heat transfer with the rock. The water then rises up the outlet wellbore at a higher temperature. The density and temperature difference between the inlet well and outlet well create a thermosiphon which drives the flow, without any pumping power. With the use of conduction, Eavor does not require a permeable reservoir to produce fluids, like traditional geothermal. Their main requirement for a reservoir is heat.
Whether dealing with traditional geothermal systems or new technology like the Eavor-LoopTM, the technology behind geothermal energy generation is relatively simple, but requires a strong understanding of the subsurface to predict reservoir temperatures, lithology, faulting and fracturing, permeability as well as potential flow rates from traditional geothermal production wells to help mitigate reservoir, drilling and completion problems.
Even though Canada currently has no commercial geothermal production, it has geothermal potential from a reservoir perspective. The Western Canadian Sedimentary Basin (WCSB) and the Williston Basin in southern Saskatchewan are vast areas with numerous porous and permeable rocks at temperatures greater than 100 °C. Elsewhere in Canada, such as interior British Columbia and the Yukon, plutonic rocks have heated groundwater, which has been utilized in commercial hot springs. Areas around these hot springs may be potential targets if sedimentary strata reside nearby.
To calculate potential for the WCSB, an understanding of the Geothermal gradient within the basin is crucial. A geothermal gradient is calculated using the following formula:
In oil and gas basins, care must be taken in determining formation temperature. Bottom hole temperatures (BHT) measured from wireline logs are usually lower than actual temperatures due to cooling from drilling mud. Using temperature from pressure data or drill stem test temperatures is a closer approximation to actual reservoir temperature. Applying a variable correction to the bottom hole temperature allows for a modification of BHT to true reservoir temperatures (Figure 6). These increases are typically on the order of 10 to 20%.
The lithology of rock changes vertically and laterally within a sedimentary basin, along with the thermal properties of the rocks. When investigating a sedimentary basin on a regional scale, geothermal gradients can be assumed to vertically constant and only changing gradient laterally.
Surface temperature is also needed to calculate the geothermal gradient. As Canada has significant seasonal temperature differences, ranging from -30°C to +30°C, the ambient surface temperature is not an appropriate value to use. Instead, it is recommended that an extrapolated value from BHT and True Vertical Depth (TVD) is used to calculate the average temperature below the frost line. In Canada we see the average temperature below the frost line to be estimated around +5°C, shown as the X axis intersection point in Figure 6.
By using our calculated geothermal gradient from well data, we can map geothermal gradient across the WCSB (Figure 7).
To understand the areas of potentially higher temperatures in the WCSB, we can estimate the temperature at the base of the sedimentary column or the top of the Precambrian basement. By mapping the TVD structure of the Precambrian basement, we can multiply the TVD by the geothermal gradient and add the surface temperature to result in a predicted temperature (Figure 8). The thickness for the WCSB reaches over 5,000 metres thick and can reach temperatures of up to 250°C.
We can also calculate the temperature at depth slices (Figure 9) to help estimate the temperature of a formation if an approximate depth is known, or if depth mapping of a zone has been conducted.
Activity is starting to pick up in Canada for geothermal projects with a few projects underway and a few in the planning stages. Five companies contribute to most of the geothermal activity in Canada:
- Eavor Technologies Inc. drilled a pilot near Rocky Mountain House, Alberta using their new closed-loop technology.
- Deep Earth Energy Production Corp. (DEEP) is developing traditional geothermal doublet in southern Saskatchewan by Estevan (12-10-001-11W2) into the basal Deadwood Formation sandstones.
- Razor Energy Corp. has received funding from Alberta innovates to build a co-production pilot at their South Swan Hills oil field in Central Alberta.
- Terrapin has received funding to explore geothermal energy in the M.D. of Greenview.
- Borealis Geopower has a few projects planned in British Columbia, as well as NWT, to micro-generate electricity and supply district heating primarily from fractured igneous rocks.
The geothermal potential in Canada is just being explored. With the large availability of subsurface data in the WCSB, from oil and gas exploration and development, there is the ability to map and understand the potential for geothermal and reduce exploration risks. Drilling equipment is readily available, and drilling costs are significantly less than many countries worldwide, making Canada attractive. The Intermontane basins in British Columbia and the Yukon Territory hold potential due to proximity of hot springs, whereas the Western Canadian Sedimentary Basin has the potential for conventional geothermal, co-production with oil and gas activities as well as the implementation of new technologies to develop this potentially extensive geothermal resource.
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