The petroleum industry in Alberta’s oil sands region faces some challenges related to Canada’s commitment to achieve net zero carbon emissions by 2050. Producers extracting heavy oil (bitumen) from reserves too deep to mine most commonly rely on a process known as steam assisted gravity drainage (SAGD) to heat the oil so that it can be pumped to the surface for processing. This process, however, emits CO2.
Mark Heigold, department manager and associate process engineer, offers some perspective on the challenges and opportunities facing Canada’s petroleum industry in the coming era of lower carbon emissions. With nearly 30 years of direct experience with many aspects of SAGD operations, Mark has direct experience on a number of projects related to the heavy oil operations in Canada.
A: I developed a love for process engineering very early due to my dad. He was a process engineer too and would occasionally take me into the office. One time, he showed me how to simulate a distillation column with Hysim. I was 13 at the time, but I was hooked. I absolutely loved it and from that point, I knew what I wanted to do.
After school, I had the opportunity to join him at the same company. He had been promoted out of the department manager role he had been in, so I was able to step right in as a new process engineer. We were able to work together on a couple of projects over the years. Process engineering has been my passion throughout my working life and I never considered doing anything else, starting from an early age. It’s easy for me to talk about my love of process engineering because it’s so closely linked to my family.
A: The acronym stands for steam assisted gravity drainage, a process that has been used effectively to extract significant volumes of bitumen from the unique oil sands formations in Alberta. It involves drilling two horizontal wells into the oil deposits, with one located above the other. Following this, steam is injected into the upper well, which heats the bitumen, allowing it to flow by gravity down to the lower well. At this point, it has a low enough viscosity to be pumped to the surface for processing. Once there at the surface, the process involves separating the production mixture. You are getting bitumen, produced gas, and the water that has condensed from the steam injections.
Currently, there are other solutions being explored to reduce the viscosity of the oil without using as much steam. One method involves injecting a hydrocarbon down the well to act as a diluent in combination with the steam. The process called ES, or expanding solvent, uses a hydrocarbon like butane, to mix with the bitumen and lower the viscosity. The fuel gas consumption rate goes down because less steam is needed. Of course, the tradeoff is that the hydrocarbon being added is very expensive, so you have to analyze the cost/benefit ratio of reducing fuel gas consumption to make steam, or increasing costs by sending this expensive fluid downhole.
A: The adage in a SAGD facility is that you are really operating steam plants that are producing oil as a byproduct. These plants are essentially massive boilers fueled by natural gas and even the dedicated power plants on-site are natural gas-fired. This entire process requires an enormous amount of energy to produce the heat and steam along with energy for wastewater treatment and auxiliary operations. All that energy has traditionally been supplied by burning hydrocarbons.
Capturing at least some of the CO2 generated by SAGD is the objective and there are some proven and emerging carbon capture technologies that would do the job. Amine-based capture is one technology pathway that is proven. However, this capture process also requires a significant amount of energy and heat to drive off the CO2 once it is captured by the amine. Usually that is done with steam via a package boiler. In a heavy oil operation, surplus steam is a scarce commodity as all of it is being pushed downhole for oil production. By pulling off some steam for carbon capture, you are essentially reducing production and reducing revenue. In most SAGD operations there is no surplus steam for regeneration of the amine capture cycle.
A: In some geological formations, carbon dioxide can be injected at high pressures to squeeze out extra volumes of oil and we have some conventional reserves like that in Alberta. Unfortunately, that doesn’t work for the heavy oil operations. You need heat, and carbon dioxide doesn’t supply heat. There is some opportunity to inject CO2 downhole when a well pad is near end-of-life. This helps maintain formation pressure, which helps sustain production volumes. However, this usage won’t consume all the CO2 recovered. The only option for captured CO2 from SAGD operations is to transport the CO2 via pipeline for injection into a suitable formation underground. The Alberta trunkline is being developed as a means to do this.
A: The carbon tax is really the big driver for decarbonization in Canada. It has been increasing in increments of $15 per metric tonne of carbon emitted annually, and in 2023 rose to $65. It’s on an eight-year phase-in and will cap out at $170 per tonne by 2030.
The theory behind the carbon tax is to impose an escalating cost on the use of hydrocarbon energy. The impact of the tax is mostly borne by the industrial and commercial sectors, but like every tax, there is a trickle-down effect for consumers. The Canadian tax code recognizes this effect and a system of credits and subsidies has been enacted to soften the blow for people of more moderate incomes.
The current carbon tax rewards companies that invest in decarbonization efforts, spending money to save money. Early adopters may benefit from avoidance of the tax. Producers need to consider the tax benefits, payback of the project and risk profile of the dynamic nature of the market.
The ultimate effect is that the cost of consuming hydrocarbons will go up every year, and it will drive a certain amount of investment in various forms of decarbonization.
A: There are two sides to this question. Side one is that producers can reduce their tax bill by recovering at least some of the carbon dioxide they are emitting from the hydrocarbons they are burning. But the other side of the coin is that this comes at a cost of less production or higher operating costs to maintain production. The other difficulty is that the capture process doesn’t really reduce the consumption of hydrocarbons because producers are in the business of producing hydrocarbons. The carbon capture units reduce the carbon footprint but also require heat as well, further increasing consumption.
Can you offset either reduced revenue or higher operating costs with the credits gained from reducing the carbon tax liability? And just as important, will the carbon capture process actually reduce overall net emissions? This is going to become a very complicated analysis, particularly as the carbon tax keeps escalating.
As interest in carbon capture technology grows worldwide, refineries and industrial facilities increasingly must choose between capturing low-concentration CO2 streams and higher-concentration streams produced by chemical reactions or treatment processes.