Review of global warming, climate change, renewables, CCUS, geothermal and the geoscience involved: Part 3

Brian Wm. Schulte

Schiefer Reservoir, bschulte@schiefer-reservoir.com

Author’s note

This is the third part to a three-part article, and it was written so all three parts are one article.

Introduction

This part’s goal is to look at CCUS, which is necessary if we continue to use fossil fuels during the energy transition. This involves the utilization and storage of supercritical CO2 (SCCO2), geothermal energy, and the geoscience that tends to be utilized by EOR.

The geoscience will be critical, and it will involve real time data, passive monitoring, Discrete Fiber Optic Sensing, downhole measurements, and surface measurements, etc. which will be applied to reservoir characterization and geomodelling. From the geomodelling, a reservoir simulation will be created to understand fluid flow.

This will encourage companies to retain geoscientists and not only provide jobs but a better future for geoscientists.

Using SCCO2 for utilization in products, EOR and geothermal will help the ESG metrics. Geothermal will add a new source of electricity to supply the ever-growing demand. Part of the solution is electricity being used to change our living space as we experience extreme weather, such as heat waves or cold during polar vortexes.

Carbon Capture Utilization and Sequestration

Carbon Capture Utilization and Sequestration (CCUS) has the potential to be a trillion-dollar industry with immense opportunities for job creation. There are at least 26 commercial-scale carbon capture projects operating around the world, with 14 in the US, 1 with CO2 capture in the U.S. (but the CO2 is sequestered in Canada (Weyburn-Midale)), 5 in Canada, 2 in Norway, 1 in Brazil, 1 in Saudi Arabia, 1 in Abu Dhabi, and 1 in the UK. CCUS is expected to achieve 14% of the global greenhouse gas emission reductions needed by 2050 (Center for Low Carbon Built Environment, 2021).

CCUS involves the capture of CO2 from carbon-intensive industries such as steel, cement, chemicals industries, power generation, etc. The CO2 is compressed into a liquid state (supercritical) and transported by pipeline, ship, rail, or truck to be used in a range of applications, one of which is enhanced oil recovery (EOR). Alternatively, it can be injected into deep geological formations, which could include depleted oil and gas reservoirs or saline formations, to be trapped for permanent storage (Figure 25) (Lawton, 2010; IEA, 2021). This is CCS (Carbon Capture and Storage).

To maximize storage capacity, CO2 is typically injected into a storage formation in a supercritical state. Supercritical CO2 has interesting properties in both the liquid and gas phases. The storage depths targeted are 800 m or deeper because the supercritical CO2 is more like a liquid than gas beyond 800 m depth, as it is denser and requires less pore space.

In some places, like Alberta, there are regulations in place requiring the storage to be deeper than 1 km.

To share transportation pipelines for the CO2 storage infrastructure and to take advantage of economies of scale, industry is moving towards CCUS hubs. BCG has identified 14 potential hubs in Canada which would span the country and serve multiple industries, including energy, steel, cement, and refining.

Eight of these hubs could capture carbon for less than US$100 per metric tonne and have a potential capacity of more than 50 Mt, which is half of our Paris accord target (Green et al., 2021).

Oil Sands Pathways to Net Zero initiative

Canadian Natural Resources, Cenovus Energy, Imperial, MEG Energy and Suncor Energy have come together to work collectively with the federal and Alberta governments to achieve net zero greenhouse gas (GHG) emissions from oil sands operations by 2050 and to help Canada meet its climate goals, including its Paris Agreement commitments and 2050 net zero aspirations. Members of the Pathway want to help Canada to find realistic and workable solutions to the challenge of climate change.

The Pathways vision is anchored by the Alberta Carbon Trunkline (ACTL) which is currently connected to a carbon sequestration hub. Their hopes are to enable multi-sector ‘tie-in’ projects for expanded emissions reductions in the future (Oil Sands Pathways to Net Zero, 2021).

Current Canadian CCS projects

There are several commercial and non-commercial CCS projects that are testing proof of concept in Western Canada, which places Canada second behind the U.S. in CCS technology.

SaskPower Boundary Dam project in Saskatchewan, Canada

In 2014, the Boundary Dam Power Station near Estevan, which uses coal to create electricity, became the first power station in the world to successfully use Carbon Capture and Storage (CCS) technology. The CO2 is captured using the CANSOLV amine solvent carbon dioxide capture process (IEAGHG, 2015).

The captured CO₂ is compressed and transported through a 66km-long pipeline to an enhanced oil recovery project near Weyburn. Unused CO₂ is transported to an injection well and storage site belonging to an Aquistore research project that is managed by the Petroleum Technology Research Centre (PTRC) which consists of a deep saline aquifer 3.2 km in the subsurface. It captures 90% of the carbon dioxide, 100% of the sulphur dioxide, and 50% of the nitrogen oxide (Power Technology, 2015; International CCS Knowledge Centre, 2021a).

Shell Quest project in Alberta, Canada

This is the world’s first commercial-scale CCS project for an oil sands operation. The project cost $1.35bn and it captures CO2 using an amine solvent. The supercritical CO2 is transported by pipeline, and it is stored in a Basal Cambrian sand saline aquifer 2 km below the surface. It has sequestered more than one million metric tonnes of CO2 from Shell’s Scotford Upgrader near Fort Saskatchewan.

Alberta Carbon Trunk Line

The Alberta Carbon Trunk Line (ACTL) is the world’s largest carbon capture and storage project, consisting of a 240 km pipeline which gathers, compresses and stores up to 14.6 million metric tonnes of CO2 per year and injects this into depleted oil reservoirs. Its estimated cost was $1.2 billion (Alberta Government, 2021).

The ACTL system captures CO₂ at the Northwest Redwater Partnership (NWR) Sturgeon Refinery and Nutrien’s Redwater Fertilizer Facility and then safely transports it to mature oil fields in Central Alberta for use in enhanced oil recovery (EOR) before permanent storage.

The use of CO2 in EOR for depleted oil and gas reservoirs is a proven technology. It also provides secure storage for the CO₂, with it dissolving into the water contained in the rock formation. A portion will combine chemically with the rocks, which traps the CO₂ even more securely (Alberta Carbon Trunk Line, 2021).

Weyburn and Midale

The IEA Greenhouse Gas Programme Weyburn-Midale CO2 Monitoring and Storage Project (WMP for short) was one of the world’s first studies to examine injection of carbon dioxide (CO2) into geologic reservoirs.

The project was launched in 2000 and continued through to 2012; the first phase was completed in 2004. The project sought to predict and verify that the Weyburn oil reservoir could securely and economically contain CO2.

The second phase was to expand upon the work of the first phase and help to recommend a framework for measurement and monitoring stored CO2, to encourage implementation of geological storage on a worldwide basis.

The Weyburn and Midale fields combined are expected to produce at least 220 million additional barrels of incremental oil, through miscible or near-miscible displacement with CO2, from fields that have already produced over 500 million barrels (79,000,000 m3) since discovery in 1954.

The program will extend the life of the Weyburn field by approximately 20–25 years. The estimated ultimate oil recovery will increase to 34% of the oil-in-place. Estimated on a full life-cycle basis, the oil produced at Weyburn by CO2 EOR will release only two-thirds as much CO2 to the atmosphere as oil produced using conventional technology (Wikipedia, 2022i)).

Carbon Management Canada (CMC) Containment and Monitoring Institute (CaMI) Field Research Station

The Containment and Monitoring Institute works with industry, academic researchers, and other technology developers to test and demonstrate accurate, cost-effective measurement and verification technologies for hydrocarbons in the air, soil and water.

Petroleum Technology Research Centre (PTRC) Aquistore Project

This project is involved with measurement, monitoring, and verification (MMV) activities prior to and during injection, as well as over the life of the project of the Aquistore Project (deep saline carbon dioxide storage research and demonstration project). The Aquistore Project is managed by the Petroleum Technology Research Centre in Regina, Saskatchewan.

Project CO2ment

This is a CCUS demonstration project now in its second phase at Lafarge’s Richmond cement plant. Flue gas from the plant’s manufacturing facility is now captured using a metal-organic framework (MOF) sorbent which uses rapid solid adsorption and low temperature steam. Svante, with the University of Calgary, developed this sorbent, which can capture up to 95% of carbon dioxide (CO2) emitted from industrial sources, such as cement and blue hydrogen plants (Process Worldwide, 2021; Lafarge, 2021).

International CCS Knowledge Centre

The International CCS Knowledge Centre supports new CCS projects with business development, operations, and technological improvements to advance the deployment of CCS facilities around the world in an effort to reduce greenhouse gas emissions.

They were involved with SaskPower’s Boundary Dam 3 Carbon Capture Facility and the Shand CCS Feasibility Study (International CCS Knowledge Centre, 2021b).

Future CCS Canada projects

There are new CCS projects being planned as Canada strives to reduce its greenhouse gas emissions (GHG) by 40‑45% below 2005 levels by 2030.

Lehigh Cement’s plant

This is a feasibility study in the use of CCUS with plans to capture 90-95% of the carbon dioxide (CO2), an estimated 600,000 metric tonnes of CO2 annually, which is emitted in the cement plant’s flue gas. This project is built upon knowledge gained from the design, construction, operation, and subsequent enhancements / modifications of the SaskPower Boundary Dam 3 CCS Facility (BD3 Facility). It shows how Wright’s law of the Learning Curve can reduce the cost of CCUS (GlobeNewswire, 2021).

Molten Carbonate Fuel Cell

Alberta Innovates and Canadian Oil Sands Innovation Alliance (COSIA) members Cenovus Energy, BP Canada, Canadian Natural and Suncor and other non-COSIA participants (MEG Energy and Shell) are exploring integrating Molten Carbonate Fuel Cell (MCFC) technology into SAGD facilities to capture 90% of the CO2 emissions associated with SAGD steam generation using Once Through Steam Generators (OTSG) and to generate electricity at the same time as CO2 is captured. The excess electricity will be sold into the Alberta power grid, providing clean energy to Albertans and a revenue stream to offset the costs associated with carbon capture.

The Joint Industry Project (JIP) builds on a feasibility study that was funded by Cenovus, BP, Devon, Shell, Suncor, Alberta Innovates and MEG Energy. The study concluded that using MCFCs would potentially be far less energy-intensive and more cost effective than conventional post-combustion carbon capture methods (Bright et al., 2015; COSIA, 2021).

Two new CCUS hubs

Canada’s federal government is pushing to provide incentives for at least two massive new carbon capture projects by 2030, with nearly a dozen oil and gas companies already pursuing rights to store carbon dioxide in Alberta’s vast underground caverns (Globalnewsdigital, 2021).

How sites are chosen

The depth of the site must be 800 m or greater because CO2 gas remains in its dense phase at this depth, making it possible to store more CO2 in a given space. The second criterion is that the type of rock in these storage sites must be porous and permeable.

The CO2 is stored in rocks, and the formations that are suitable for storage are covered by cap rock that is strong and not porous, thus creating a barrier to movement.

The third criterion is capacity. The goal is to find sites where over 50 million metric tons can be stored for economic and monitoring reasons.

CO2 pipelines

With the building of CCS hubs which will enable companies to share costs and risks and to achieve economies of scale, we will also need to create a vast, nationwide network of pipelines that will move CO2 from industrial emitters to those storage sites. These pipelines will be similar to the ACTL.

CO2 for depleted reservoirs

CO2 EOR targets have included localized high-quality oil reservoirs, such as the Viking Formation in the Joffre Field (clastic high-energy shoreface) or the Leduc Formation in the Clive Field (carbonate reef complex) (Couëslan et al., 2021).

Advantages of using a depleted reservoir are that the reservoir geometry and properties are well known, there is a physical or well-understood stratigraphic trapping mechanism, the cap rock integrity is established, and fluid flow within the reservoir has often been history-matched at production wells.

The disadvantage is that there are usually a significant number of producing or abandoned wells that penetrate the reservoir, and some of these may constitute leakage paths to shallow aquifers or to the ground surface (Lawton, 2010).

CO2 for saline aquifers

Saline aquifer storage is preferred because the available pore space volume is significantly greater than that available in depleted hydrocarbon reservoirs (Bachu and Gunter, 1999; Lawton, 2010), and the number of well penetrations is small, which reduces the possible leakage paths through wells.

In contrast, the disadvantages are that the reservoir may not be confined, the integrity of the cap rock may be poorly known, and there is no history match to understand fluid flow in the reservoir. Saline aquifer storage requires a comprehensive site assessment and reservoir characterization be undertaken before large-scale CO2 injection is started.

Open saline formations bounded by continuous impermeable layers that prevent the migration of CO2 out of the storage formation are preferred to maximize the storage capacity over structural or stratigraphic traps with closure. The CCUS project also needs to be in an area with a minimal number of well penetrations to reduce the risk of CO2 migrating up along wellbores that penetrate the storage formation (Couëslan et al., 2021).

In Alberta, good potential candidates for CO2 storage in saline aquifers are in the Cambrian, Devonian, Permian, Jurassic, and Lower and Upper Cretaceous-aged sediments in different parts of the basin. Regional mapping must be done to determine the depositional extent and depth of some of the formations.

A saline aquifer that is a good candidate in some parts of the province may be too shallow to maintain supercritical conditions in other parts of the province, or too deep to provide adequate reservoir properties for storage. Depositional settings that encourage formations with a large aerial extent are the most sought-after for storage (Couëslan et al., 2021).

Utilization of CO2 for frac fluid

Water or slick water (chemicals are added to water to increase flow) or gelled water tends to represent the majority of working fluids used for commercial hydraulic fracturing. The issue with using these frac fluids are (Simal and Lancaster, 1987; Hu et al., 2019; Watts, 2014):

  1. Challenges with acquiring, transporting, storing, recovering, and recycling or disposing of water, especially in areas where there are shortages of water
  2. Environmental impact from constituent chemicals used in frac fluids
  3. Swelling of clays
  4. Increase in water saturation significantly reduces formation’s relative permeability to hydrocarbons
  5. Any fluid left behind in the formation negatively impacts physical properties of the rock, lowering conductivity of the reservoir and reducing or impeding flow of oil and gas
  6. Poor fracture performance.

Instead of using water we can use nitrogen (N2) or CO2. CO2 tends to be used predominately in gas wells because it preferentially displaces the methane and sits on the rock surface, giving the potential for much enhanced production of methane gas from shales (Science Media Centre, 2019).

Benefits of using CO2 for fracking are:

  1. High flowback
  2. Small damage in reservoir
  3. Outstanding stimulation effect
  4. Sequestering CO2 into the subsurface

CO2 can either be used as a liquid or supercritical or as energized frac fluid.

Fracking with Liquid CO2

Since 1960’s liquid CO2 has been used in oil and gas field stimulation. CO2 is a liquid at temperatures between -20 oC and -40 oC which are noncryogenic temperatures. It can be pumped with conventional frac equipment and injected directly into the well. The liquid CO2 then vaporizes as it approaches equilibrium with reservoir temperature and pressure. The lower viscosity of the gaseous CO2 allows it to flow back from the formation to the wellbore and gaseous CO2 aids in lifting formation fluids that are produced back during the clean-up operation (Simal and Lancaster, 1987).

Fracking with Supercritical CO2

Supercritical CO2 (SC-CO2) occurs when temperature and pressure exceed 31.1 ◦C and 7.38 MPa respectively. Properties of SC-CO2 that make it attractive as a frack fluid are (Hu et al., 2019):

  1. Low viscosity like the gas state,
  2. Large density like the liquid state
  3. Low surface tension
  4. High diffusivity
  5. Percolation effect of SC-CO2 can greatly increase pore pressure, which leads to a decrease in breakdown pressure
  6. Acoustic emission (AE) energy release rate of SC-CO2 fracturing is 1–2 orders of magnitude higher than that of water fracturing
  7. In shale with weak structural planes, the propagation direction of the fracture is controlled by the combined effect of a weak structural plane and in-situ stress.

Fracking with Energized Frac Water

Fracking fluids that include at least one compressible, sometimes soluble, gas phase are known as energized. There have been studies that indicate fracking with solutions energized by CO2 or N2 can economically achieve significantly more hydrocarbon recovery than non-energized approaches. One study found using energized fluids improved well performance by 1.6-2.1 times, compared with non-energized solutions (Watts, 2014).

Fracking with fluids that are not energized leave liquids trapped in low-permeability, tight, depleted or water-sensitive formations. The fluid remaining in the formation negatively impacts the physical properties of the rock, lowering conductivity of the reservoir and reducing or impeding flow of oil and gas (Watts, 2014).

CCUS and availability of CO2

As the use of CCUS increases, the costs of obtaining and using CO2 should decrease, making it economical to be used as a frac fluid.

Utilization of CO2

Though most of the discussion has been around sequestering carbon into the earth, we can use the carbon in various products. McKinsey & Company estimates that by 2030 CO2-based products could be worth between $800 billion and $1 trillion, and the use of CO2 for producing fuel, enriching concrete, and generating power alone could reduce greenhouse gas emissions by a billion metric tons yearly.

Having genuinely marketable products using CO2 could be transformational with respect to carbon capture technology.

Incorporating CO2 into concrete might be the best prospect for widespread use of CO2 in the near term because of the enormous amounts of concrete used to construct buildings and infrastructure around the world. The University of Michigan has developed a methodology to incorporate it into the composition and structural use of a new, super low-carbon-footprint, engineered cementitious composite (ECC) concrete. ECC behaves more like a metallic material, particularly in the way it responds to loads. The microcracks it sustains under duress do not compromise a structure in the same way that larger cracks would in traditional, steel-reinforced concrete (Cho, 2019).

ECC was used in the Grove Street Bridge deck over I-94 in Ypsilanti, Michigan and is estimated to have a cost savings of 37% and a carbon emissions reduction of 39% (Center for Low Carbon Built Environment, 2021).

CO2 is also used to cure concrete by infusing the wet mix with CO2, which reacts with water and calcium to form solid calcium carbonates. This spontaneous chemical reaction does not require much added energy and results in concrete that is 4% CO2 (Cho, 2019).

CO2 can be used in carbon materials such as graphene, carbon nanotubes, and carbon fibres.

C2CNT, a company based in Calgary, Alberta, has found a way to produce carbon nanotubes 100 times more cheaply than usual. Their technology uses low-cost nickel and steel electrodes, flue gas, and low voltage current to create carbon nanotubes that conduct electricity better than copper. Carbon nanotubes are valued at over $100,000 per ton, and the nanotubes can be used by steel, aluminum, textiles, ceramics, and cement producers, and in electronics, packaging, manufacturing and construction (Cho, 2019).

Carbon nanotubes are being used for tires for EVs. They are used because EVs are up to 30% heavier than ICE counterparts and the EVs’ direct-drive electric motors produce near-instant torque which makes them accelerate quickly. These two factors equate to increased tire wear, so carbon nanotubes are being used (Molecular Rebar Design, 2021).

Carbon nanotubes are being looked at to store hydrogen as a fuel source. By utilizing the capillary effects of the small carbon nanotubes, it is possible to condense gases in high density inside single-walled nanotubes. This will allow for hydrogen to be stored at high densities without being condensed into a liquid. Potentially, instead of using fueling tanks we could use this storage method for a hydrogen-powered car (Wikipedia, 2021f).

Funding, Tax credits and Carbon offset credits

US – 45Q tax credit

The 45Q tax credit provides an incentive of up to $50 per ton for pure geological sequestration and up to $25 per ton for EOR. These numbers increase gradually and are limited to 12 years of credits (Bomgardner, 2020).

Federal Carbon Tax and Clean Fuel Standard

A carbon tax simply charges emitters a financial amount per metric tonne of CO2 emitted. In Canada, the federal minimum price started at $20 per metric tonne of CO2 equivalent in 2019 and will be increasing annually by $15 annually until it reaches $170 in 2030.

If it costs $100 per mT to sequester CO2, then emitters will become motivated to capture and store CO2 to avoid paying these taxes. These sorts of incentives are considered necessary for CCS to become a major technology solution for reducing emissions. As well, the costs of CCS technologies will come down when more capture and storage projects go forward due to growing economies of scale and the learning curve. The fact is that large industrial-scale CCS projects are not likely to occur without incentives.

Carbon Offset Credits

Under Canada’s Climate Plan are the Clean Fuel Regulations (CFR). It is expected that a new regulatory credit market for compliance credits will be established where producers and importers who surpass the minimum clean fuel standard are rewarded with credits which may then be purchased by other producers and importers to achieve compliance. The future market value will be directly correlated to the implementation of projects, including CCUS, that generate or use these credits (BOE Report Staff, 2021).

Tax Credit

In the Canadian federal Budget 2021, there was a proposal to introduce an investment tax credit for capital invested in carbon capture, utilization, and storage (CCUS) projects with the goal of reducing emissions by at least 15 metric megatonnes of CO2 annually.

It is intended for the new investment tax credit to be available for a broad range of CCUS applications across different industrial subsectors, such as concrete, plastics, fuels, blue hydrogen projects, and direct air capture projects, to the extent that captured CO2 is not used in enhanced oil recovery projects. The federal government is also expected to announce a cap on emissions which will be close to the current emissions, and it would be lowered over time (Government of Canada, 2021; Tuttle, 2022).

EOR

The commercial sale of CO2 becomes a source of revenue and helps to offset the cost of the capture process. The CO2 that is injected into oil reservoirs is recycled in the process without being released into the atmosphere, and eventually, it is permanently and safely stored underground.

In the Weyburn-Midale fields, CO2 water-alternating-gas (WAG) injection is used to improve sweep efficiency during CO2 injection, with the injected water controlling the mobility of CO2 and stabilizing the gas front. CO2 injection has been utilized in West Texas for decades, and it can increase reservoir pressure and oil mobility, enabling oil to escape from rock pores and to flow more readily toward production wells (Chen and Reynolds, 2018; Wikipedia, 2021j).

It has been found that 1 metric tonne of CO2 increases oil production in Weyburn by almost three barrels.

Price per metric tonne needs to be set before CCUS is begun, and a long-term contract should be put in place. In Texas recently, the Petra Nova Texas coal plant CCUS project, which was a joint venture project between NRG Energy Inc and Japan’s JX Nippon, was shut down. Its shutdown was due to the collapse of the price of oil prompted by the coronavirus pandemic. The drop in price of oil made it uneconomical to inject CO2 into the West Ranch oil field (Groom, 2020). This demonstrates that economic incentives are needed to encourage businesses to implement CCUS and CCS.

Geothermal

In the past, some of the barriers to entry of geothermal into the mainstream energy market were:

  1. High initial capital costs related to drilling and constructing new geothermal wells
  2. Long payback periods
  3. Risk associated with unknown formation performance when drilling in a new area.

With the downturn in the oil and gas industry, proven technology, expertise, and reservoir data from the petroleum industry was applied. This unlikely partnership is providing a springboard for the geothermal industry to enter the mainstream renewable energy market, while at the same time benefiting the petroleum industry. This is coming at a time when we see lower investment into oil and gas due to GHG emissions; declining reserves; aging oilfields; increasing costs for exploration, operating, and decommissioning; volatile oil prices; and a push by governments to increase renewables through grants and incentives. Current Western Canadian geothermal projects are listed in Table 1.

Table 1. Geothermal projects in Western Canada

Canadian Government Funding for Geothermal

Canadian government funding both provincially and federally have helped with geothermal projects.

Funding is available in Canada through programs like:

  1. The Emerging Renewable Power Program, which provides up to $200 million to expand the portfolio of commercially viable renewable energy sources available to provinces and territories as they work to reduce GHG emissions from their electricity sectors.
  2. The Pacific Economic Development Canada (BC) / Prairies Economic Development Canada (Alberta, Saskatchewan, and Manitoba), which is working to diversify the western economy while improving the quality of life of western Canadians.
  3. Indigenous Services Canada (ISC) collaborates with partners to improve access to high quality services for First Nations, Inuit and Métis.
  4. First Nations Clean Energy Business Fund promotes increased Indigenous community participation in the clean energy sector within their asserted traditional territories and treaty areas.
  5. Alberta Innovates supports research and growth of business and helps the start-up community to build new technology and test new ideas.

Many believe that, as with solar and wind, we are relatively early on the learning curve with geothermal, so grants and tax credits are necessary to subsidize it. Subsidies allow U.S. companies to get past set-up hurdles and to help companies invest in safe developments and fund risk mitigation during pilot projects. As growth in geothermal increases, we will see the costs or price decrease following a learning curve.

As we expect electricity demand to rise globally, we must develop new energy sources if we are going to reduce the use of fossil fuels. IEA reported in 2021 that we had the steepest ever increase in the demand for electricity, with global electricity demand rising by 6% or 1,500 TWh. This is largest percentage gain since the recovery from a global financial crisis in 2010 and the largest total rise on record. This increase in demand led to blackouts and record-high prices and an increase in greenhouse gas emissions around the world. IEA predicts that this trend could continue for the next three years, with electricity demand forecasted to increase by 2.7% on average to 2024 unless there is a more rapid structural change in electricity production (Bradstock, 2022; Reuters, 2022).

Table 2. Government funding for geothermal projects

Low temperature geothermal

Low temperature geothermal is being pursued in Western Canada due to the low geothermal gradients that are present in the Western Canadian Sedimentary Basin (WCSB), with at least 5 projects (see Table 2). If we look at most of the geothermal wells, they tend to be in deeper Paleozoic formations. The Paleozoic formations in Alberta tend to be shales and limestones from reef complexes. With reefs there still may be a small amount of hydrocarbons remaining, so cogeneration may be a possibility.

Geothermal power generation

For low temperature geothermal to work, we need heat and water flow. The temperature of the water needs to be around 100oC to be used to generate electricity using binary plants such as the Organic Rankine Cycle (ORC) systems. ORC uses organic substances instead of water (steam) as the working fluid. The organic working fluid has a lower boiling point and a higher vapour pressure than water and can use low temperature heat sources to produce electricity (Macchi and Astolfi, 2021).

Issues with abandoned wells

The issue with wells that are abandoned or near abandonment is the flow rate. The flow rates from such wells are much lower than from newly drilled geothermal wells. The other issue is the existing wells often suffer from well integrity issues that will make them ill-suited for a 20–40-year lifespan as a producing geothermal asset (Slav, 2021).

Some companies are now injecting water into the abandoned wells, heat it up and then use it for heat or power generation using ORC technology. Heating can be used in agriculture to dry wheat or produce instead of using gas especially if the wells are near agricultural infrastructure such as grain elevators (Slav, 2021).

Enhanced Geothermal System (EGS)

An Enhanced Geothermal System (EGS) involves extracting heat from a hot subsurface rock which lacks natural permeability sufficient for fluid flow. EGS uses technologies to enhance the reservoir permeability and fluid saturation.

The EGS reservoir properties depend on the natural fracture network and on the changes to this network induced by the reservoir stimulation. The goal of EGS is to increase reservoir permeability either by widening (re-opening) the fractures in the existing natural fracture network or by creating new fractures. This creates permeable pathways that allow the injected cold fluid to be heated up by direct contact with the surrounding hot matrix. Cold fluid is then passed from injection wells to production wells with one or more production wells returning the heated fluid to ground surface for electricity generation (Kalinina at al., 2014; Okoroafor et al., 2021).

Vertical geothermal wells are affected by:

  1. Well separation
  2. Thickness of the injection interval
  3. Vertical anisotropy in reservoir permeability
  4. Fracture properties and orientation.

The near-vertical orientation of fractures often found in EGS environments means that vertical wells cannot optimally exploit the geothermal resources. Vertical wells can also be impacted by density differences that cause the colder injected water to sink to the bottom of the injection interval, figure 26 (Kalinina et al., 2012a, 2012b, and 2014).

Figure 26. On the left is a vertical well and its water flow pattern and, on the right, a horizontal well.

With EGS, horizontal wells are used because the heat extraction is not affected by the length of the injection interval or by fracture properties. What affects the performance is the well separation distance; with larger well separation, more heat can be extracted. The maximum distance of separation might be limited by the reservoir extent, the achievable stimulation radius, and the potential pumping requirements (Kalinina at al., 2014).

Enhanced Geothermal System (EGS) Geothermal with H2O or CO2

The advantages of supercritical CO2 are (Brown, 2000; Pruess, 2006; Luo and Jiang, 2014; Isaka et al., 2019; Wu and Li, 2020; Okoroafor et al., 2021):

  1. Higher density-to-viscosity ratio
  2. Larger buoyancy force
  3. Lower salt solubility
  4. Greater power output
  5. Simultaneously sequester CO2
  6. CO2 minimizes parasitic losses from pumping and cooling
  7. Reduces the use of water
  8. Reduce scaling and corrosion of system components due to CO2 having a much lower tendency to dissolve minerals and other substances compared to water.

Supercritical CO2 is gaseous in nature, which may be a disadvantage when the flow and heat extraction are modeled with a heterogenous fracture aperture and with realistic time periods for heat extraction. CO2 is affected by channeling due to viscous fingering and fracture aperture heterogeneity. Channels persist over time, leading to a very inefficient thermal sweep.

Water at low temperatures is more viscous than the background reservoir water and so cooler pathways become less preferential, and the sweep can contact more area of the rock over time. Thus, the net energy extracted from the reservoir became more than that with CO2 after about a year and half into the simulation.

Looking at the results of the EOR when WAG injection is used to improve sweep efficiency during CO2 injection, one may consider doing the same with geothermal wells, so using both water and CO2 may improve our geothermal results (Okoroafor et al., 2021).

Geothermal heavy oil extraction

Canadian Oil Sands Innovation Alliance (COSIA) did an initial study looking at an EGS as a low-carbon, hot water source to replace or reduce the natural gas usage associated with water heating in mining. Preliminary reports forecasted a reduction in greenhouse gas (GHG) emissions by an average of almost 60 kilotons of C02 annually over a mine’s 30-year project life, which is equivalent to the C02 emissions of 15,000 vehicles a year (COSIA, 2022).

COSIA now plans to do a second study evaluating Eavor’s advanced geothermal system (AGS) in the oil sands with their closed loop system called Eavo-loop. AGS uses no fracking but circulates fluids through a closed-loop system of wells (COSIA, 2022).

Geothermal and nearly abandoned wells

Mature fields are characterized by a large amount of co-produced hot water stored in the reservoir that must be treated and reinjected in the underground. The amount of water increases compared to hydrocarbons until the costs of electricity, transporting and re-injecting the water into the ground exceed the amount that is being made by the field. There is a possibility of using these hot fluids to produce geothermal energy during the final stage of the life of an oil field (Soldo and Alimonti, 2015).

One of current ideas is to repurpose existing oil and gas wells in these mature fields to:

  1. Increase geothermal energy production
  2. Increase the value of the oil or gas field
  3. Decrease costs for electricity, allowing the mature field to operate longer
  4. Reduce the environmental footprint of operations.

The geothermal energy can be used to power infrastructure in the field such as artificial lift, and excess power can be sold to the local grid or to other operators using block chain technology (Boak et al., 2021).

Utilization of geothermal power for the oil and gas field instead of purchasing power from the grid lowers costs. This lowering of costs can allow a field to continue to be operated past its expectations. Many feel cogeneration of hydrocarbons and geothermal will be more economical than just using geothermal wells. The other advantage is that infrastructure within the producing field can be used, lowering the costs even more compared to drilling a new geothermal well.

Companies like Petrolern have developed proprietary technology such as a workflow and screening platform which integrates several effective criteria to select appropriate late-stage oil and gas wells to convert to clean and lower-cost geothermal energy sources. It allows for the ranking of potential candidates to reduce costs. It can be applied to the large numbers of abandoned oil and gas wells, many of which are left unplugged, and which create liability for companies and provincial or state governments. In Alberta alone there are 2,992 orphan wells (Boak et al., 2021).

Currently Petrolern is utilizing their proprietary technology to identify targets for utilization of geothermal power in selected basins in Colombia for Ecopetrol. Ecopetrol is rethinking its business strategy, diversifying into non-fossil sources of revenue (Petrolern LLC, 2021; Palacios and Monaldi, 2021).

FutEra co-generation of natural gas and geothermal

FutEra is capturing energy from the heated hot water it produces and re-injecting it as part of its conventional operations and producing electricity in the process. Co-production has a range of benefits, such as producing two forms of energy from one production facility and with related gathering, processing, and distribution infrastructure. By doing this the economics are more predictable.

The first phase will produce up to 5 MW using a hybrid design which will allow the project to go up to 21 MW once a gas turbine is added. They are looking into using CCUS with the gas turbine. Geothermal energy is baseload, so there are no issues with intermittency problems faced by other renewable energy sources and therefore no need for storage. FutEra expects the total capital cost of the geothermal project to be C$34 million. (Richter, 2021; Whitelaw, 2022).

Blackburn Oilfield Nevada Geothermal

Transitional Energy has been selected to receive a $2,500,000 award from the U.S. Department of Energy Geothermal Technologies Office (GTO) to support the transition of hydrocarbon wells into geothermal wells. Its goal is to produce 1 MW from an operating oil field. (Richter, 2022).

Geothermal and lithium

Geothermal and lithium extraction are a natural pair, especially when the reservoir is close to the basement where minerals from the basement may be in solution. It is extraction of these minerals from the brines that most are looking into. It isn’t just lithium that can be extracted, but also caesium, rubidium and potassium as well.

Merging oil and gas with renewable energy

Merging renewable energy technologies with oil and gas production methods could enhance training opportunities and could also provide those in oil and gas with employment prospects as we reduce GHG emissions and transition to cleaner energy.

CCUS could provide the CO2 required for EOR in some oil and gas fields. If we look at Weyburn-Midale, it has extended this play by 20-25 years. With the lack of funding, oil and gas operators are not exploring but are trying to increase production in existing assets. The CO2 can be used to enhance geothermal, especially when it is being used in conjunction of CCUS that is using a saline aquifer for injection.

This transition to cleaner energy will require innovation to develop ideas to maximize our returns and minimize our costs.

It is this innovation that will attract investors back to the industry, and hopefully we will obtain the necessary funding to continue green- and brownfield development as our mature fields are being depleted. Due to the shortfall in upstream investment, prices of oil and natural gas will become volatile.

Reservoir characterization

CCUS and geothermal require geomodelling to understand the subsurface and the fluid flow. It will require compression of data, data from different sources such as passive receivers, Distributed Fibre Optic Sensing (DFOS), 4D VSP’s, 4D seismic, gauges downhole and on the surface, etc., and the building of geomodels which are a repository for data. All of this data will be real time, so there is a need to do analytics to be able to pick up anomalous events.

Currently there have been technological changes in what we do. An example of this is event-driven passive seismic-acoustic monitoring receivers, which classify and locate subsurface events of interest, automatically and in real-time, such as Quantum Technology Sciences (subsidiary of Geospace Technologies) SADAR. Some of this technology is being tested in the CMC Containment and Monitoring Institute (CaMI) Field Research Station. Passive monitoring will be required because CCUS and geothermal tend to be within 1 km of the basement, where there is a higher probability of induced seismicity.

One of the technologies under development is Tesseral’s Duplex Wave Migration (DWM) to map porosity, permeability, and fractures. Studies in Russia indicate the amplitude of the DWM corresponds to the permeability.

Geomodelling

Figure 27. . Diagram showing the steps of building a geomodel. A geomodel is a multidisciplinary, interoperable, and updatable database about the subsurface (Schulte, 2022).

 

A geomodel is a multidisciplinary, interoperable, and updatable database about the subsurface (figure 27). It is the numerical equivalent of a three-dimensional geological map complemented by a description of physical quantities in the domain of interest, such as porosity, permeability, effective porosity, water saturation, shale / sand volume, and more.

Geomodels include detailed 3D facies and petrophysical property models that are contained within a geological framework. Well data tends to be used for the generation of the facies and petrophysical parameters that populate this 3D model, and seismic data is used to supply a structural interpretation for the generation of the framework.

The issues with the use of seismic to populate the 3D facies and petrophysical properties are:

  1. Lack of a direct link between seismic data and some reservoir properties, e.g. permeabilility.
  2. Lack of sufficient vertical resolution to generate detailed property models

Most approaches of integrating seismic data into reservoir model are statistical in nature, that is, a statistical calibration is done between seismic attribute(s) and the petrophysical properties of interest. The statistical calibration tends to be CoKriging which calculates better estimates for a poorly spatially-sampled data such as well log data with help of a well-sampled data such as seismic.

Figure 28. Flow chart showing the strengths of stochastic inversion (Schulte, 2022).

 

One way to incorporate seismic into the geomodel is to utilize stochastic inversion (fig. 28). Stochastic inversion combines the vertical resolution of well log data and the horizontal resolution of seismic data. Utilizing Bayes Theorem and stochastic inversion can incorporate more rigorous probabilistic estimates of reservoir properties and pore fluid. Probabilistic inversion uses seismic attributes in a quantitative manner for risking exploration and development prospects.

An important part of geologic modelling is related to geostatistics, which deals with probabilities and not absolute answers. It is important to realize that a lot of what is done deals with probabilities. Geostatistics use a variogram to better populate the rock properties in the model. The variogram reflects the understanding of geometry and the continuity of the reservoir properties. It can have an important effect on prediction of flow behaviour (Gringarten and Deutsch, 1999; Alexeyev et al., 2019).

Geomodelling emphasizes an integrated multi-disciplinary team. It brings together data from different sources such as well data, well tops, completion information, pressure data, production data, seismic data, seismic inversion products, and seismic horizons. All this data needs to follow standards (Schulte, 2019).

Geomodelling in understanding flow

CCUS, geothermal, EOR, etc. require an understanding of flow. To understand flow, a reservoir simulation needs to be done which involves the building of a geomodel. To quality-control the reservoir simulation, production history matching needs to be done; and if the production history does not match the predictions of the reservoir simulation, the geomodel needs to be changed.

Geomodelling and 4D seismic and fluid flow

4D seismic is composed of a base seismic survey and monitor seismic surveys. There can be multiple monitor surveys over time. Like the reservoir simulation, 4D seismic is used to understand fluid movement over time. It works best with rocks that are sensitive to changes in fluid and/or pressure, and these changes are reflected in changes in AVO signatures such as class 4, 3, 2, and 2P AVO’s.

4D seismic data is used in developing mature fields, CO2 injection, CCUS or geothermal, but some companies have begun to record what is referred as the base survey within the appraisal stage of evaluating the reservoir, just in case later on they wish to do a monitor survey.

To predict what changes may occur in a 4D seismic survey between the base and monitor survey a reservoir simulation can be used. This prediction from the reservoir simulation can then be compared with the changes between the base and monitor surveys. Then the reservoir simulation is updated to reflect the changes in the 4D seismic survey. The flowchart is in Figure 29.

Figure 29. Workflow showing how the reservoir simulation is used with the 4D seismic results to understand what is occurring in the subsurface.


Utilizing 3C 3D 4D VSPs rather than 4D seismic to understand fluid flow

The acquiring of multiple seismic surveys over time can be costly so to lower costs, E&P companies have been looking into using Vertical Seismic Profiles (VSPs).

There is a significant amount of information with economic value can be derived from a VSP (Schweigert and Schulte, 2019; Stewart, 2001). Some of this information includes:

  1. Improved velocity model
  2. AVO behaviour
  3. Multiple identification
  4. 2D reflectivity image away from borehole
  5. Anisotropic measurements
  6. High frequency 3D reflectivity volume around from borehole

A VSP is a useful tool to obtain measurements of rock properties of the subsurface (Stewart, 2001). Rock properties include velocity, impedance, attenuation, and anisotropy. VSP data has higher frequency and therefore higher resolution at depth when compared to surface seismic because the downgoing seismic energy is only required to travel through the highly attenuative near surface once. Its ability to extract local velocity estimations as well as anisotropic measurements even with no knowledge of the overburden makes a VSP an excellent tool for advanced processing methods (Schweigert and Schulte, 2019; Grechka et al., 2007).

The higher frequency content leads to high S/N images, making 3D VSPs very valuable for reservoir characterization in the vicinity of the well (O’Brien et al, 2013). The higher resolution data near the well will also help identify smaller faults/fractures that are beyond surface seismic resolution (Schweigert and Schulte, 2019; Hardage, 2000).

3C 4D VSP data can be used determine fluid flow, which can help in the determination of future enhanced oil recovery (EOR) techniques.

In the heavy oil sands, different production techniques are utilized such as steam injection and Cold Heavy Oil Production with Sand (CHOPS) dependent of the depth and thickness.

SAGD is used for deposits located greater than 200 metres below the surface and a with a recommended minimum thickness of 15 meters so that two parallel horizontal wells can be drilled some distance apart. While CHOPS is used when the reservoir is located at a depth greater than 400 metres and the thickness of the reservoir is low (Wikipedia, 2021i; Anderson, 2012; Medina, 2020; Jaremko, 2022a; Talinga et al., 2021).

In thermal recovery processes, the PS splitting can be used to detect stress effects in the reservoir and/or caprock. These data can be used as a constraint on reservoir simulation and for geomechanical analysis of the reservoir and caprock (Schweigert and Schulte, 2019; Wikel and Kendall, 2013).

With CHOPS development of wormholes can be monitored using a 4D VSP, because when the sand is produced, it will cause the reservoir pressure to fall below the bubble point, causing the gas to come out of solution and causing a time lapse anomaly (Schweigert and Schulte, 2019; Wikel and Kendall, 2013).

Distributed Acoustic Sensing technology

Recording a VSP with Distributed Acoustic Sensing (DAS) technology allows the recording of the signal over an extremely small station interval which removes any potential aliasing of high frequencies caused by the larger sensor spacings that are typical downhole tools. DAS also allows the recording of information on the horizontal portion of the borehole, on top of the typically recorded vertical portion.

In unconventional plays it has been noticed that there are amplitude changes and traveltime differences observed in 3D DAS VSPs that changed azimuthally between the before and after volumes. The height of the stimulation inferred from these differences was similar to the height estimates obtained from analysis of the other methods employed, such as a conventional VSP with geophones, microseismic data, tiltmeters, external pressure gauges, radioactive tracers, and distributed thermal sensing (DTS) (Schweigert and Schulte, 2019; Meek et al., 2017).

This data can provide more comprehensive and accurate estimation of the hydraulic fracture geometry and the dynamic processes taking place internal to the propagating fractures. These data could also be used to calibrate fracture models and the fracture interaction with the surrounding unconventional reservoirs (Schweigert and Schulte, 2019; Meek et al., 2019).

Conclusion

Climate change has occurred in our geological past, especially in the Cretaceous, and in our recent human history. With climate change, we are seeing that weather phenomena such as hurricanes are shifting northward above the equator and southward below the equator. We are seeing hurricanes in places like New Jersey, New York, Newfoundland, and Labrador. East Coast Canada may consider having hurricane plans in place.

The area where tornadoes occur is shifting eastward of the present tornado alley. This will affect insurance costs, real estate, and business in that area.

Weather is complicated and we are still learning how weather works; it is about the interaction of oceanic oscillations, thermohaline currents, the jet stream, and other factors. With regards to tornadoes and hurricanes, we do not see the frequency increasing, but do see the intensity of storms increase due to the warmer temperatures and increased humidity. The La Niña cycle influences these storms, something we have known for a while.

Our GHG emissions are said to be accelerating climate change, and that will influence our economies. With more intense storms, property damage and loss of life increase.

We can look at the Cretaceous to understand what will happen when the ice caps at the poles disappear. We do know that there were numerous inland shallow seas in the Cretaceous that underwent multiple periods of anoxia, when the bottom water was devoid of oxygen and the water column was stratified (Hay, 2009; Lowery et al., 2017).

There was also a reduction of the temperature gradient between the Equator and the Poles (as we see these days), destabilizing the winds at mid-and high latitude and affecting the global temperature distribution and the wind-driven ocean circulation (Hay, 2009; Lucy, 2018). This lowering or stilling of the wind may affect our ability to derive electricity from wind turbines. Already Europe sees wind droughts which affect the production of electricity. The EU has already launched a study to understand the worldwide decline in windspeed in a climate change scenario (Lucy, 2018).

Demand for oil and gas is increasing, causing GHG emissions to increase. Divesting oil and gas stocks and bonds will not curtail the demand and will create supply shortages, driving up the price of oil and natural gas. This increase in the price of oil and natural gas will drive inflation.

Electrification and installation of wind and solar generation capacity is not the only answer, due to issues with seasonality. The wind is stronger in the spring when wind power is competing with hydroelectricity and weaker in the summer when we have a demand for air conditioning. Electricity is hard to store in lithium batteries and cannot be held for extended periods for release when demand and price is high. Wind and solar, though, can be part of an integrated solution using various sources of energy to ensure energy security.

Using EROI, it looks like a mix of 1/3 renewables, 1/3 fossil fuels, and 1/3 nuclear will provide an EROI of 36 and will half the GHG emissions. CCUS should be used to reduce the GHG emissions further.

LNG is in demand for electricity generation since natural gas burns about 50% cleaner than coal; that demand has increased, especially with the commitments of COP26.

CCUS and the ability to use the CO2 for EOR in depleted oil fields or for geothermal in basal sands should be part of this integrated solution. Currently Canada is capturing about 7 Mt of CO2 annually, roughly 1% of our total emissions, which is equivalent to removing the emissions from 1,522,359 passenger vehicles driven in 1 year. We are second behind the U.S. in CCS projects and are developing many of the tools that are needed for CCS through Carbon Management Canada (CMC) (Green et al., 2021).

CMC supports advancement of technologies to reduce carbon emissions; it moves in the space between bench-scale research and commercialization. It helps innovators scale up and prove their carbon capture, conversion, and storage technologies.

With the development of reservoir simulations, 4D seismic, 3D 4D VSP’s, passive monitoring etc., monitoring of what is happening in the subsurface can be done which allows us to avoid any potential problems before they happen.

There is a lot of development in understanding geothermal and implementing it with the University of Calgary Geothermal Lab, which is a multidisciplinary collaboration between the Departments of Chemical and Petroleum Engineering and Civil Engineering in the Schulich School of Engineering, the Department of Geoscience in the Faculty of Science, and the Faculty of Law (University of Calgary Geothermal Energy Lab, 2021) which can help develop some of the ideas especially with CCUS and geothermal.

As I see it, changing how we manage GHG emissions helps us to reduce some of the negative effects we are beginning to see with climate change and shows to our investors that we are thinking about the future and how we will deal with net zero emissions. And it creates jobs and futures for young scientists and engineers.

We need to make these changes for future generations.

Now more than ever we need to emphasize a collaborative approach which will include oil and gas. Because we are still in the early stages, we will also be asking questions rather than dictating answers, testing ideas, designing pilot projects, and so forth as we work out what will be the best solutions both economically and for the environment.


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About the Author

Brian Wm. Schulte attended The University of Calgary graduating in 1989 with a Bachelor of Science in Geology and a minor in Geophysics. Brian has worked in seismic processing, acquisition, interpretation, rock physics, and petro-physics. Some of the companies he worked for are: Gale-Horizon, Schlumberger, Vastar (division of Arco), BP, Explora Seismic Processing (ESP), Geokinetics, Talisman Energy Inc., and Repsol. Brian also served as an Instructor of Petroleum Engineering Technology at Houston Community College-NE Energy Institute and made outstanding contributions as a member of the Program Industry Advisory Committee that lead to several program recognitions and students’ successes. Brian is working at his own consulting company Schiefer Reservoir Consulting.

He volunteers on occasion with the ReDevelop program (https://www.redevelop.ca/) which trains graduate students studying Geoscience, Engineering, and Public Policy from five Canadian universities in soft skills not taught at university, with an emphasis on projects involved with low carbon energy, and integration and thinking out of the box with these projects.

Keywords:

Carbon Capture Utilization and Sequestration, CCUS, super critical CO2, Weyburn, Midale, CO2 injection, Molten Carbonate Fuel Cell, CO2 pipelines, Oil Sands Pathways, Alberta Carbon Trunk Line, saline aquifers, geothermal, utilization of CO2, 45Q tax credit, Federal carbon tax, Clean Fuel Standard, geothermal, Enhanced Geothermal System, EGS, geothermal heavy oil extraction, reservoir characterization