SAGD cogeneration strategy would shrink the carbon footprint of both the Alberta electrical grid and the oil sands

Alberta could simultaneously achieve two of its biggest energy objectives – accelerating the phase-out of coal-fired power and reducing greenhouse gas emissions from oil sands crude production – using a readily available, proven technology, according to two major new studies (Figure 1) by the Canadian Energy Systems Analysis Research (CESAR) Initiative.

Expanding the use of combined heat and power (called cogeneration) technology) at steam assisted gravity drainage (SAGD) oil sands operations would cut more greenhouse gas (GHG) emissions from Alberta’s electrical grid – and at a lower cost – than simply replacing coal with stand alone natural gas-fired power, the studies show.

Figure 1. Cover pages of the two reports (click on the images to download the reports).

At the same time, assigning oil sands companies temporary GHG credits for investing in cogeneration and reducing the province’s overall GHG emissions would also reduce the GHG intensity of SAGD production to be equivalent to, or lower than conventional oil (Figure 2) – something that won’t happen by replacing coal with technologies like natural gas combined cycle (NGCC) to generate electricity.

SAGD cogeneration would also stabilize electricity prices and provide a reliable source of base load and backup power for the expanded renewable energy that the government wants to incorporate into the Alberta grid, as part of its Climate Leadership Plan.

Figure 2. Comparison of the five scenarios for the GHG intensity of SAGD production (SOR=3) in kg co₂/bbl (A), and of the public electrical grid in kg co₂/MWh (B) when emission reductions resulting from the early retirement of coal are temporarily assigned to oil sands crude production. In panel A, the shaded area shows the range of GHG intensities for conventional oil production and the dashed line shows intensity values when emission reductions are assigned only to those barrels recovered with the heat from SAGD cogeneration.

“Over the next 14 years, much of the province’s electricity generating infrastructure will be replaced, but if this is done with stand-alone thermal power generation technologies, at least 50 per cent of the energy in the fuel will be discarded as waste heat,” says David Layzell, Director of CESAR.

“SAGD cogeneration may be a better alternative, since it can use more than 70 per cent of the energy in the fuel. With SAGD cogeneration, oil sands operations can be part of the solution to climate change challenge, not just part of the problem.”

Cogeneration with gas turbines and heat recovery steam generators using natural gas is a commercial technology. It has been installed in several SAGD projects ranging in size from 80 megawatts to 400 megawatts and proven to be reliable and easy to operate.

“Compared with existing steam generation, cogeneration is much more energy efficient in generating the same amount of steam using less natural gas and electricity. This is a big advantage in the current low oil price environment for SAGD operators,” notes Dr. Song P. Sit, a Senior CESAR Associate and a 30-year veteran in the oil sands business.

“Cogeneration equipment is available from several suppliers, potentially offering price competition. Engineering services to install cogeneration in SAGD are also widely available, which will reduce the risks of install in new projects or retrofit in existing operating projects,” Sit adds.

Cogeneration a good fit for SAGD operations

CESAR’s new studies explored the technical, environmental and economic implications of integrating large-scale changes in Alberta’s electricity sector with changes in the heat and power generation technologies used in SAGD operations. Specifically, the studies investigated whether SAGD development, which is continuing to grow, has the capacity to install cogeneration to match its growth, but also assist in the retirement of coal-fired power. To carry out this work, CESAR’s researchers drew on a wide range of data resources built some powerful new computer models and then used them to explore and visualize energy future.

CESAR’s first study, described in the report, Cogeneration Options for a 33,000 BPD SAGD Facility: Greenhouse Gas and Economic Implications, is a detailed techno-economic-environmental assessment of the impact of cogeneration on a 33,000 barrel per day SAGD facility. Research involved creating a detailed computer model of a 33,000 BPD SAGD facility with steam to oil ratios (SOR) that varied from two to four barrels of water needed per barrel of bitumen recovered.

Figure 3. The effect of two 85 MWe gas turbines with cogeneration running at 100% load factor per 33,000 BPD SAGD facility on the system level flows of energy (Sankey diagrams) and greenhouse gases (bar charts). The right side of the chart shows the equivalent crude and grid power output without cogeneration, so all electricity requirements are provided by the public grid.

Using the model, four different Case studies (three Cogen Cases and one Base Case with no cogen) were built and compared, each differing in the technologies used to provide heat and power to the SAGD process as well as power to Alberta’s public electrical grid.

CESAR’s analysis and modelling found that, for all the Cogen Cases, cogeneration reduced fuel use, conversion losses and GHG emissions for the model SAGD facility, compared with the no-cogen operation. Figure 3 compares one of the Cogen Cases and it corresponding base case.

“Adding cogeneration that is capable of meeting 100 per cent of the steam demands of an average facility (33,000 BPD, SOR of 3) would allow the producer to export more than 11 times the energy used on site to Alberta’s public grid,” says Eric Shewchuk, a CESAR Research Engineer and a 10-year electrical engineer with a background in generation projects. “This could provide an additional source of revenue that would help in a low oil price environment.”

Investing in cogeneration would have a positive economic value for SAGD operators, according to an economic analysis included in the study.

Researchers calculated the 20-year net present value (NPV) of the investment for the three Cogen Cases relative to the Base Case (no cogeneration). The median values for all simulations showed a positive NPV in the range of $90 million to $190 million (before tax and royalty), depending on the number of cogen units (one or two) and the facility’s steam to oil ratio, compared with the no-cogen option.

Reducing GHG emissions in both Alberta’s grid and the oil sands

CESAR’s second study, described in the report, SAGD Cogeneration: Reducing the Carbon Footprint of Oil Sands Production and the Alberta Grid, integrated the SAGD model from the first report, into a scenario model describing the past, present and possible futures  of the Alberta electrical grid. Modeled energy futures varied in the rate of coal plant retirement, the rate for deployment of new renewable generation, and the role of NGCC vs. SAGD cogeneration in replacing the base load needs created by coal retirements.

Figure 4. Modelled early retirement of coal plants in Alberta, and the impact on generation (A) and GHG emissions (B) compared to the federal coal retirement schedule. (Assumes coal replaced by 12 TWh/yr renewables + baseload power at 390 kg CO₂/MWh). This report explores the implications of incentivizing SAGD producers to negotiate and achieve early coal retirement (yellow shaded area, panel A) by allowing them to assign the resulting GHG reductions to oil sands crude production (Panel B).

Using boundary conditions that include the energy and GHG flows for both the entire electrical grid and all of the SAGD production facilities in the province, researchers generated five scenarios and compared them for the delivery of electrical power to the Alberta grid over the 2017 to 2030 period.

The study shows how, by 2030, existing and planned SAGD operations in Alberta could use off-the-shelf cogeneration technology to achieve the early retirement of coal from the electrical grid, provide for 12 Terawatt-hours of new renewable generation, stabilize electricity prices and reduce GHG emissions by 170 million tonnes (Mt) of carbon dioxide – the equivalent of removing more than 2.78 million cars from Alberta’s roads.

In comparison, replacing coal with only natural gas-fired power and renewables would result in a lower amount of GHG emissions reduced – 147 Mt co₂ – by 2030.

CESAR’s analysis found that if the government assigned oil sands companies GHG credits – but only for a limited period (See Figure 4) – for helping to significantly reduce Alberta’s GHG emissions, this would also cut the GHG intensity of SAGD oil produced to a level less than or equal to conventional oil. Cogeneration is the only proven and economic technology capable of achieving this goal by 2030.

SAGD operators would receive the temporary GHG credits only if their deployment of cogeneration was formally linked to the early retirement of coal-fired power and/or the backup of greatly expanded renewables on Alberta’s electrical grid, CESAR’s study notes.

Shrinking the carbon footprint of the oil sands as fast as possible is of vital strategic importance to the Alberta government, which hopes to secure public support for the oil sands industry and new bitumen export pipelines. Moreover, from a climate change perspective, the atmosphere doesn’t ‘care’ about the origin of the emission reduction – only that it occurs.

CESAR’s studies point out that the SAGD cogeneration strategy is aligned with the Alberta government’s publicly stated desire (including in its Climate Leadership Plan) to find cost-effective, collaborative, multi-stakeholder solutions to address GHG emissions and climate change. The approach is also aligned with the oil sands industry’s stated goal to become not only cost-competitive with crude oil producers in other countries but also carbon-competitive – and as quickly as possible.

“SAGD cogeneration represents a ‘made in Alberta’ solution to the government’s desire to drive coal off the grid and increase the role for renewables in the province,” Layzell says.  “Most jurisdictions in the world do not have an industrial heat demand that could use the waste heat from thermal power generation. Alberta does – and it is SAGD.

“We in CESAR hope that these reports will be a catalyst that brings government and the power generation and oil sands sectors together for the benefit of the environment and the economy.”

CESAR’s two studies were supported by the Edmonton Community Foundation, Alberta Innovates – Energy and Environmental Solutions, Candor Engineering Ltd., and several oil sands companies including MEG Energy, Suncor Energy, Cenovus Energy and Nexen Energy ULC. Sponsors had no editorial control over the studies or their findings.