Stantec assessment of greenhouse gas emissions of oil and gas development in the Arctic

On this page

• Executive summary
• Statement of approach

Executive summary

Crown-Indigenous Relations and Northern Affairs Canada (CIRNAC) retained Stantec Consulting Ltd. (Stantec) to study and estimate the greenhouse gas (GHG) emissions from potential offshore oil and gas development in the Canadian Arctic, and specifically in the region of the Canadian Beaufort Sea. The goal of the assessment is to compare the potential GHG emissions from 2 hypothetical offshore development scenarios against Canada's climate change commitments and evaluate the impact on global GHG emissions.

For the purposes of this study, the offshore oil and gas development in the Arctic includes the following activities:

• seismic exploration
• exploratory drilling
• production
• decommissioning and abandonment

Reviews of offshore oil and gas development policy and applicable GHG emissions policy in the Arctic were also included as part of this work.

Several nations border the Arctic Ocean. Other than the United Nations Convention on the Law of the Seas, there has been limited integration of regulation and policy regarding activities in the Arctic. Some consider that part of the challenge in developing resources in the Arctic is a lack of collaboration at the international level on policy and regulation. In particular, the lack of a coordinated global policy and/or regulation tied to spill control is a common point of discussion for potential offshore oil and gas development in the Arctic.

Access for Arctic exploration and development varies considerably between nations. Canada is perceived to be more accommodating to the participation of international companies. Other nations such as Norway and Russia are more restrictive in favor of their own national companies, even though they have traditionally maintained opportunities for international investment. Historically, the most restrictive countries also have realized the most oil and gas development activity in the Arctic.

Greenhouse gas emissions policies also vary noticeably between Arctic nations. Most Arctic nations (except Russia and Iceland) have goals to achieve net-zero emissions domestically by 2050, though each country is pursuing these goals in different ways. While these GHG emissions targets often lack specific regulations for their enforcement, there is evidence that investment in Arctic offshore oil and gas development is decreasing due in part to the perceived increased risk in those types of developments meeting GHG emissions targets.

Despite potential policy challenges and technological challenges of developing offshore oil and gas resources in harsh environments, development is occurring and is expected to continue throughout the next decade, particularly in Norway and Russia. Norway plans to develop the Johan Castburg oil field by 2022, while development plans for Russia include 2 potential developments by 2030, with exploration continuing through the next decade.

To meet anticipated demand, as forecasted by the Canadian Energy Regulator (CER,formerly known as the National Energy Board), electricity generation in Canada must grow by 30% by 2040, with power generated from natural gas (from 10% to 16%) and renewable-based energy (from 5% to 11%) showing the largest increases (National Energy Board 2018).

While research has established that oil and gas resources are evident in the Arctic offshore, there are 3 main challenges to future development:

1. There is a general lack of coordinated global policy and regulation, particularly regarding spill response. Environmental assessments, strategic environmental assessments, and other policy and review documents from several jurisdictions repeatedly cite the challenges of internationally coordinated oil spill response in the Arctic as a central concern of local stakeholders to oil and gas development (e.g., Gulas et al., 2017). There is a need for international preparedness to respond to spills in the Arctic. Some work has been completed and continues through several non-governmental organizations, such as the Arctic Monitoring and Assessment Programme, Nordregio, and the International Organization of Oil and Gas Producers (IOGP). However, more work is likely needed to develop more robust spill response best practices that meet the needs of local stakeholders.
2. There are increased development costs due to unique design challenges. The successfully completed offshore Arctic oil and gas developments have often been challenged by cost overruns due to their technical complexity and long drilling and deployment schedules. These developments have almost always relied on government financial support to offset these development cost risks. In the absence of technological advances to reduce costs, development in the Canadian Beaufort is understood to be contingent on a large discovery in excess of 1 billion barrels (P. Barnes, pers. comm., 2020) and/or commodity prices approaching $100 per barrel. Through their own experience with Goliat and Snøhvit (and other offshore developments), Norway has reduced development costs so that the Johan Castburg development is viable at $30 per barrel. While perhaps not directly transferable, knowledge sharing from other Arctic developments may influence decisions regarding the viability of developments in the Canadian Beaufort. However, it is not yet known if this knowledge transfer has occurred or can be applied to the Canadian Arctic.
3. There is a shifting global policy on GHG emissions. Each Arctic jurisdiction has been consistently and actively developing policies to reduce GHG emissions. Many Arctic countries, including Canada, have established targets for severely limiting GHG emissions by 2050, or even becoming carbon-neutral by that time. Most countries have committed to becoming "net-zero", including the US (historically Canada's main oil and gas customer), which has a new objective of reaching net-zero emissions by 2050. Many industrial sectors are now challenged by these GHG policies and offshore oil and gas is no exception. There are net-zero pathways where oil and gas still plays an important role in energy systems. Therefore, it is likely that offshore oil and gas developments will have to contend with this additional constraint to be viable in the future. In addition to the technical challenges of developing offshore oil and gas resources in the Arctic, further innovations will be required to remain compatible with these emerging GHG emissions policies.

Despite the challenges to future development, there have been concerted efforts from both Arctic states and industry to modernize Arctic offshore oil and gas development and to address GHG emissions.

There are also several positive aspects associated with Arctic offshore oil and gas development. These include:

• Canada's dynamic and flexible approaches to emissions mitigation: Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) and the Clean Fuel Standard are part of Canada's increasingly stringent climate policy
• in support of the Global Methane Pledge (which aims to reduce global methane emissions by 30% below 2020 levels by 2030) and the goals in Canada's climate plan, Minister Wilkinson also announced Canada's commitment to developing a plan to reduce methane emissions across the broader Canadian economy and to reducing oil and gas methane emissions by at least 75% below 2012 levels by 2030 (Government of Canada 2021)
• a commitment to carbon neutrality: most major oil and gas companies have committed to become carbon-neutral in the coming decades (at least for their own operations). Industry is employing new methane-reducing technologies to reduce GHG emissions with support from Canada's $750 Emissions Reduction Fund
• increased cooperation among Arctic states: substantial international work has aided more sustainable and consistent approaches to offshore exploration and development, for example:
  • United Nations Convention on the Law of the Sea
  • Arctic heavy oil ban
  • the "Agreement on Marine Oil Pollution Preparedness and Response in the Arctic" signed by Arctic states
  • the Arctic Council's "Arctic Offshore Oil and Gas Guidelines"

Two realistic and detailed scenarios were established for Arctic oil and gas development up to 2050. These are referred to as:

1. the Low-case scenario
2. the High-case scenario

The Low-case scenario was developed to assess the potential effects of GHG emissions associated with the development and production of oil reserves from existing Significant Discovery Licenses (for example proven resources that are known and have been delineated) and are in moderate depth of water (30 m) on the continental shelf. As designed, this scenario represents a moderate to high level of development activity. The main equipment associated with the Low-case scenario is a gravity-based structure (GBS) with crude oil extraction, processing, storage and offloading capabilities.

The High-case scenario has been developed to assess the potential effects of GHG emissions associated with exploration and hydrocarbon development within Exploration Licenses in deep water (depths of 100 to 1,200 m) in an area on the slope of the continental shelf approximately 180 km northwest of Tuktoyaktuk, Northwest Territories. Given the scale, duration and sequencing of development in the offshore location, this scenario represents a high level of development activity. The main equipment units associated with the High-case scenario are a floating production, storage, and offloading (FPSO) vessel and a drillship.

The findings of this study indicate that there are many established and emerging technologies that could be incorporated into the design, operation and construction of GBSs and FPSOs for the Arctic region. While the design and operation practices for Arctic climates are unique and challenging, the implementation of many of the referenced established technologies for GHG reduction are well suited to facilities noted in the 2 scenarios to reduce the overall GHG footprint.

For both scenarios, the production of power and generally the combustion of hydrocarbon fuel is the most significant contributor to GHG emissions in offshore oil and gas production facilities, with flaring as the next largest contributor. The FPSOs and GBSs generally have a relatively low space and weight availability for production and power equipment. The production equipment requirements are dictated by the characteristics of the well fluids and there is very little opportunity to reduce equipment footprint and weights. This makes the retrofitting of these types of existing facilities with advanced power production systems very challenging. However, for newly designed and built facilities, it is technically feasible to implement most of the advanced power production systems and other GHG reduction technologies and other best practices like zero normal flaring.

The established GHG reduction technologies and best practices considered in this assessment were as follows:

• waste heat recovery from power generation for thermal process load
• cogeneration via Organic Rankine Cycle
• zero normal flaring
• process heat optimization
• thermal insulation
• fugitive emissions leak detection and reporting management programs
• robust preventative and predictive maintenance programs
• use of high efficiency lighting (for example LED) and electrical equipment (for example motors)
• natural gas fueled marine vessels

The following emerging technologies were also considered:

• membrane carbon dioxide (CO₂) separation
• oxyfuel combustion
• advanced power generation with post combustion carbon capture and sequestration
• carbon capture and utilization
• wind energy
• wave energy
• tidal energy
• small modular nuclear reactors
• power hubs and platform electrification
• natural gas fueled vessels with carbon capture and sequestration

The established GHG reduction technologies and best practices are currently widely used and the costs of using these technologies are not barriers to their implementation. It is expected that any existing FPSO that would be deployed to the Arctic region would have most of the established GHG technologies and best practices implemented in those facilities. For new GBSs and FPSOs that would be purpose-built for the Arctic, as a minimum it is expected that the established technologies and best practices would also form part of those facilities. Given the relatively high equipment layout footprint, weight and cost of the advanced power generation systems and other emerging technologies, the economic feasibility of implementing these would require case-by-case studies and would be subject to economies of scale. The production levels would have to be high enough to offset costs associated with meeting the necessary policies and regulations and the costs of exploration and production.

Electrification of production field centres via onshore zero GHG emissions sources (such as hydroelectric power) provide a promising alternative for nearshore shallow water applications where GBSs are typically deployed. However, a large hydroelectric power plant or similar renewable energy source would be required to make this option truly beneficial, compared with advanced power systems and other in-situ GHG reduction technologies.

The GHG emissions were estimated for both the Low-case scenario and the High-case scenario. Two crude oil transportation cases were also considered with each scenario. In transportation Case 1, the crude oil is offloaded from the GBS or FPSO onto a shuttle tanker. This shuttle tanker, depending on its size, may transfer the crude oil to another ocean-going tanker while at sea for transport to a refinery. In transportation Case 2, the crude oil that is offloaded from the GBS or FPSO is carried by tanker to Prudhoe Bay, Alaska, USA for entry into the Trans Alaska Pipeline System. From there, the crude oil is pumped to the Valdez Terminal in Valdez, Alaska. A second tanker transports the crude oil from the Valdez Terminal to the refinery. In both cases, the crude oil is transported to a refinery in South Korea.

In addition to the 2 modes of transport, 2 different electricity generation technologies are considered in each development scenario, established technology and emerging technology. For the established technology case, electricity is assumed to be generated on the GBS or FPSO using gas turbines burning cleaned associated gas. In the emerging technology case, the GBS uses electricity sourced from renewable sources (for example wind) and the FPSO uses onboard generated nuclear power.

Overall, the GHG emissions were estimated for 24 combinations of production, technology, and transportation over the period of 2022 to 2050. The GHGs considered in the assessment are CO₂, methane (CH₄), and nitrous oxide (N₂O). After applying their respective global warming potentials of 1 (CO₂), 25 (CO₂), and 298 (N₂O), the total GHGs are expressed as carbon dioxide equivalent (CO_2e).

The methods used to estimate the GHG emissions include the OPGEE and PRELIM (El-Houjeiri et al. 2018; Abella et al. 2021). The refinery GHG emissions intensities were estimated using methods described in Jing et al. (2020). The activities that generate GHGs in each scenario may be categorized as:

1. Exploration and construction: project upstream, exploration, construction support, drilling & development
2. Operation: production & extraction, surface processing, maintenance, transport, operation support, indirect emissions from fuel manufacture
3. Downstream: refinery, fuel distribution, end use combustion

The total GHG emissions for the lowest and highest emitting combinations are provided in Table E-1 for the global activity chain, from exploration through to end use combustion.

The total estimated GHG emissions for the operation and downstream activities range from approximately 10 million t CO_2e per year from the lowest emitting combination to approximately 40 million t CO_2e per year from the highest emitting combination. In both scenarios, the largest portion of the GHG emissions are generated during the end-use combustion of the refined petroleum products.

The total GHG emissions generated from the activities in Canada were also estimated. These represent a smaller set of activities than presented in Table E-1 and include exploration, indirect emissions, construction, and drilling and development activities in Canada with transport of the crude out to the Canadian border. These values are provided in Table E-2. The activities that occur downstream (for example refining, distribution, and combustion) are excluded in this estimate as they occur outside of Canada.

The estimated GHG emissions occurring in Canada for the lowest and highest emitting combinations are presented in Table E-3.

The total estimated annual GHG emissions that occur in Canada from the 2 development scenarios range from 64,179 t CO_2e per year from the lowest emitting case to 705,362 t CO_2e per year from the highest emitting case. In the lowest emitting combination, a large portion of the emissions come from the surface processing activities (for example crude oil processing, associated gas processing). In the highest emitting combination, the largest source of emissions is operation support. However, production and extraction and surface processing are also substantive contributors.

A summary of the GHG emissions in Canada at the mid-production level is presented in Table E-4 for the years 2030 and 2050.

For the High scenario, the GHG emissions in 2030 are higher than the GHG emissions in 2050 when using nuclear energy mainly due to the presence of the drillship in 2030. Otherwise, the 2050 emissions are higher as more electricity is needed over time as the reservoir ages.

In addition to the estimates of overall GHG emissions and the GHG emissions within Canada, a full life cycle assessment (LCA) was completed for the Arctic crude oil, for 2 life cycles: Well to Refinery, and Well to Combustion. The estimates are provided in Table E-5.

The Well to Refinery GHG intensity values range from 1.8 to 2.7 g CO_2e/MJ crude oil. Note that these intensities include emissions from Construction Support (for example tugboats) and Operation Support (for example supply vessels) that are not included in other, similar LCAs, but that these account for a negligible amount of the intensity. The estimated GHG intensities are lower than those found in the literature for 3 crude oils in Iran, Saudi Arabia and Venezuela, which ranged from 6 to 15 g CO_2e /MJ crude (Di Lullo 2016).

The Well to Combustion GHG intensity values ranged from 78.0 to 79.1 g CO_2e/MJ crude oil. These values include GHG emissions from the Construction Support and Operation Support activities. As shown in Table E-1, these intensities are equivalent to a range of 479 to 488 kg CO_2e/bbl. These estimates compare reasonably well with those found in the literature for crudes around the world (Newfoundland, Alberta, Alaska, Norway), which ranged from 481 to 736 kg CO_2e/bbl. The estimated Well to Combustion GHG emissions intensity for Arctic crude are very similar to those values for offshore crude oils in Newfoundland and Norway (Oil-Climate Index 2021, Carnegie Endowment for International Peace 2015).

The uncertainty in the Arctic estimates is low due to the conservative approach and associated assumptions used in estimating the emissions.

The LCA GHG emissions from other sources of energy are compared with the Arctic estimates in Table E-6.

The Arctic estimates are less than the conventional oil, heavy oil, and coal GHG intensities. This is likely associated with the approach and assumptions for the Arctic estimates, that include the extraction of a relatively light oil (assumed Hibernia assay would be similar to oil in the Arctic), and the use of established technologies to reduce GHGs during exploration, extraction, production and the other activities down the value chain.

Looking beyond 2030, Canada recently committed to reaching net-zero emissions by 2050, and the Canadian Net-Zero Emissions Accountability Act establishes a legally binding process of interim targets, plans and reports toward this objective. Achieving net-zero means the Canadian economy either releases no GHG emissions or creates offsets that take GHGs out of the atmosphere. This could be done, for example, through actions such as tree planting or employing technologies that can capture carbon before it is released into the air (Environment and Climate Change Canada [ECCC] 2021).

There is considerable range in the forecasts for crude oil demand/production out to 2050. The differences between the production scenarios are influenced by a combination of global demand and GHG policies. For example, the CER has stated that by 2050, Canadian crude oil production is forecast to be between 5 and 7 million barrels per day (MMbbl/d) (approximately 1.1 million meters cubedm³/d) depending on future GHG policies and action globally. This represents a 7% to 40% increase over 2019 production levels. Forecasts are for production to occur largely in Alberta, with additional volumes in Saskatchewan and offshore Newfoundland and Labrador (CER 2020). No Arctic onshore or offshore development has been included in the current forecasts.

The International Energy Agency (IEA) released a report titled "Net Zero by 2050, a Roadmap for the Global Energy Sector" in May 2021 that defines a high-level global pathway to net zero and presents the anticipated sectoral impacts. In this roadmap, it is assumed that oil demand never returns to its 2019 peak, and it declines from 88 to 72 to 24 MMbbl/d in 2020, 2030 and 2050 respectively. This is a decrease of almost 75% between 2020 and 2050 (IEA 2021). It is noted that the global path is contrary to Canadian oil production forecasts which show an increase out to 2050. The trajectory of oil demand in the net zero global scenario assumes no exploration for new resources is required and, other than fields already approved for development, no new oil fields are necessary. The oil price in the net zero pathway would be sufficient in principle to cover the cost of developing new fields for the lowest cost producers, including those in the Middle East, but it is assumed that major resource holders do not proceed with investment in new fields because doing so would create significant additional downward pressure on prices (IEA 2021).

Based on the LCA estimates presented herein, Arctic oil and gas development would represent a relatively small contribution to global production and associated GHG emissions. However, the GHG emissions released within Canada could adversely affect Canada's ability to meet its GHG reduction targets for 2030 if those emissions are not offset by reductions or offsets elsewhere in Canada. If the hypothetical Arctic production of 240,000 bbl/d is a net increase in the forecasted oil production in Canada in 2030, the increased emissions within Canada are estimated to be 0.4 million t CO_2e for the year in the high case.

It is likely that each petroleum source of energy within Canada and beyond (coal, oil, heavy crude, natural gas) will be required to reduce its GHG emissions to near zero in the future, leaving very small quantities to be offset in some way. Further, corporate, environmental, social and governance initiatives will result in a reduction of GHG emissions per bbl of production. However, the timing and implementation of these reductions is far from certain. The Arctic development would most likely be required to do the same. This may well be achieved by engaging new technologies that are being developed currently, or at some point in the future.

This assessment includes consideration of leakage, which refers to changes in GHGs outside of a specified boundary such as Canada, by including LCA emissions globally. Use of LCAs in considering the effects of new policy or development regulations assists in evaluating and managing GHG leakage by considering GHGs globally and from cradle to grave. To avoid negative leakage (such as increases in GHGs globally linked to an action within Canada that may decrease domestic emissions), countries need to make policy decisions not just based on their inventory boundary but also consider how their decisions/policies internally impact GHGs globally.

Statement of approach

As part of the study, CIRNAC was supported by a technical working group that included Environment and Climate Change Canada (ECCC), the Government of the Northwest Territories, the Government of Yukon, and the Inuvialuit Regional Corporation. Using a collaborative approach, several issues were raised during the course of this work by the members of the technical working group. An example of the issues raised included identifying where the hypothetical oil production facilities would be located in the Beaufort Sea, and where would the crude oil be refined and consumed. After considerable discussion of various options, 2 locations were selected, near shore and further offshore. It was also agreed that the crude oil would not likely be refined in Canada but somewhere west of Canada. After discussion, South Korea, was selected as a likely location. These and several other assumptions were used to develop the full life-cycle assessment (LCA). The approach and the assumptions were vetted by the technical working group. These assumptions are intended to provide a reasonable and practical estimate of GHG emissions from the 2 production scenarios to assist CIRNAC for planning purposes. The numbers are presented using the best information that was available to the technical working group at the time of assessment. While the data and results are provided herein, this report should not be construed in any way as offering any opinion as to whether oil and gas development in the Arctic should be approved by any regulatory agency to proceed.