Through its Emissions Reduction Alberta (ERA) initiative, the province has announced up to $70.6 million in funding toward oilsands projects estimated to result in potential greenhouse gas emissions reductions of up to four megatonnes of annual CO2 equivalent reductions in Alberta by 2030.
The nine projects, launched by ERA’s Oil Sands Innovation Challenge, advance technologies in bitumen production, steam generation, upgrading, tailings management and land reclamation.
“This is ERA’s largest challenge yet,” said ERA CEO Steve MacDonald. “Our funding is leveraged, and with that leveraging we expect industry to invest approximately $723 million in these projects.”
The oilsands sector emits roughly 70 megatonnes of greenhouse gases (GHGs) each year, accounting for roughly a quarter of Alberta’s annual emissions.
The projects are as follows.
CLEANSEAS Demonstration Project
Enlighten Innovations Inc. (formerly Field Upgrading) will receive $10 million for its CLEANSEAS Demonstration Project, which will design and construct a demonstration facility for its DSU technology. DSU removes sulphur and partially upgrades heavy oil including Alberta bitumen into low-sulphur marine fuel.
Low-sulfur marine fuel is an alternate, value-added market that is growing in response to new marine transport regulations. The CLEANSEAS project is a commercial scale of the technology and signifies a critical step toward full commercial rollout. Commercial implementation of the technology will involve construction of modules at the same scale as the demonstration plant. The modules can be installed close to bitumen production facilities or refining facilities.
“We mix sodium with oil, and sodium melts at 100 degrees C. It has the same physical properties as oil, the same density, and it mixes well with the oil,” said Neil Camarta, director and founder, Enlighten Innovations. “And what it does when it gets in the oil [is] it reacts specifically with the nasty stuff, exactly the stuff you want to get out of oil, the dirty stuff. You want to get out the acid, you want to get out the metals, you want to get out the sulphur. That’s what the sodium goes for and the sodium removes that stuff from the oil, so it cleans up the oil in one step.”
Enlighten Innovations estimates DSU technology reduces GHG emissions on a lifecycle basis by up to 40 per cent compared to alternative pathways for production of marine fuel.
Enhanced Bitumen Recovery Technology Pilot
Imperial Oil Limited was granted $10 million to advance a field trial of its Enhanced Bitumen Recovery Technology (EBRT) to validate the method and prepare it for commercial use. The process uses a recovery solution to dilute and mobilize bitumen in the reservoir, reducing the amount of steam needed as much as 90 per cent compared to current methods.
Based on Imperial’s research, it is expected the technology could reduce GHG emissions intensity from in-situ oil sands extraction facilities by approximately 60 per cent compared to conventional SAGD production methods. EBRT can be applied at both existing and new build sites in place of conventional in-situ facilities. The technology operates at lower pressures and may enable recovery from reservoirs not previously considered viable. It is also expected to reduce initial capital and operating costs by approximately 50 per cent.
Partial Upgrader with Integrated Water Treatment
Heavy Oil Solutions and Cenovus Energy Inc. were granted $10 million to test a process to upgrade bitumen to lighter oil at Cenovus’s Christina Lake oilsands project, potentially eliminating the need to blend the bitumen with diluent to make it flow through a pipeline. The process has potential to reduce costs, shrink Cenovus’s environmental footprint and free up pipeline capacity.
Through a single-step operation, using water that is produced alongside the oil, the process is designed to return crude oil that is effectively pipeline ready and water that can be reused in the crude oil production cycle without extensive treatment. Originally developed for the remediation of nuclear waste, the technology holds potential for simplifying and integrating all surface operations at the well pad.
FSG Field Prototype
Cenovus and FSG Technologies Inc. will collect $10 million to demonstrate FSG technology, also known as Flash Steam Generation, for production of steam for in-situ oil sands extraction. FSG’s boiler design may enable more efficient steam generation and eliminate some of the water treatment infrastructure typically required to support in situ projects, which is expected to result in meaningful cost reductions and lower GHG emissions.
FSG units could be deployed in lieu of conventional once-through steam generators and associated water treatment equipment at new in situ extraction facilities, while smaller scale versions could be used at existing facilities. The FSG technology may reduce GHG emissions by up to 14 per cent and is expected to achieve up to a 20 per cent reduction in capital expenditures and a 15 per cent reduction in operating expenditures compared with conventional technology.
MEG Energy Corp. receives $10 million to develop phase 3 of its eMVAPEX technology. Enhanced Modified VAPour EXtraction involves the application of infill wells and the injection of a condensable gas (such as propane) in lieu of steam after initial SAGD operation.
It is anticipated the eMVAPEX process can reduce the company’s steam-oil-ratio (SOR), thereby freeing up steam to apply to new wells and increase overall production. For example, an industry standard SAGD asset with an operating SOR of 3.0 could increase bitumen production by up to 76 per cent with the same steam assets by employing eMVAPEX. The resulting overall GHG emission intensity could be reduced by as much as 43 per cent. In addition, the overall recovery from the reservoir is expected to improve.
To date, the company has implemented the technology on three well pairs and their associated infill wells with encouraging results. MEG’s 2018 capital program allows for the conversion to eMVAPEX of up to seven additional well pairs and associated infills, and the construction of a propane recycling facility to test the commerciality and scalability of the technology.
Multi-Pad Pilot of a Solvent-Aided Process
Cenovus will receive $10 million to advance its solvent-aided process, or SAP, which involves adding a solvent such as propane to the steam that’s injected into the reservoir in SAGD.
Cenovus estimates that on a field-basis, SAP could reduce emissions intensity by about a third compared to SAGD. Cenovus is now planning a SAP operational demonstration project on multiple well pads at its Foster Creek oilsands project.
In-Pit Extraction Process
Canadian Natural Resources Limited will receive $5.6 million to demonstrate a field pilot of its In-Pit Extraction Process (IPEP) technology, an alternative to conventional oilsands mining and ore processing. IPEP involves a relocatable, modular extraction plant that can be moved as the mine face advances. Ore processing and bitumen separation occurs adjacent to mining operations, significantly reducing material transportation. IPEP produces stackable tailings within the mine pit, greatly reducing the volume of fluid tailings and ultimately accelerating reclamation of oilsands mines.
“The period of time from mining to reclamation is basically immediate, because it produces dry stackable tailings that can support reclamation immediately,” said Joy Romero, vice-president Technology and Innovation at Canadian Natural. “There are no tailings ponds in the mine pit. And so we go forward, this is truly a significant change.”
Canadian Natural estimates IPEP could reduce GHG emissions by up to 40 per cent in bitumen production compared to typical oilsands surface mining and extraction processes. The IPEP system would also enable expansion of mining operations without constructing new central ore processing facilities.
Canadian Natural has committed to make this technology available to oilsands mining companies through COSIA for more rapid industry-wide adoption. It is estimated the technology will reduce production costs by roughly $2/bbl and substantially reduce long term tailings management costs and liabilities.
High-Temperature Membranes for SAGD Water Treatment
Suncor Energy Inc. will partner with Devon Energy and Suez (formerly GE Water Treatment) to demonstrate High Temperature Reverse Osmosis (HTRO) membranes for SAGD water treatment with a $2.5 million grant from ERA. The project will validate the technology for application in high-temperature, high-pressure SAGD conditions. If successful, the membranes could eliminate the need to reduce the temperature and pressure of produced water prior to water treatment. This will reduce the infrastructure and energy required for the SAGD water treatment process.
Reverse osmosis using membranes is used globally in other industries, such as the power industry, desalination and water production, but hasn’t been used in the oilsands “because we run at high temperature,” said Michael McGregor, senior development engineer, Oilsands and In Situ at Suncor. “So, what this project is aiming to do is to transition this technology into our field, and the reason we are trying to do it is to improve our steam generation.
For example, the cleaner water produced will limit development of scale. “If we put cleaner water into our steam generation facilities, then we are just going to be able to produce that steam much more efficiently and in a more cleaner fashion.”
The technology has the potential to reduce GHG emissions by up to five-10 per cent compared to a typical SAGD baseline facility. For new builds, the technology could reduce capital costs by 16 per cent.
Non-Condensable Gas Co-Injection for Thief Zones
ConocoPhillips Canada, as operator of its Surmont joint venture with Total E&P Canada, will receive $2.5 million to deploy its non-condensable gas (NCG) injection technology at 12 SAGD well pairs to validate the technology at commercial scale. NCG injection has the potential to mitigate “thief zones” – areas above or below the oil zones where energy and pressure can be lost, resulting in a need for more steam to be injected to recover bitumen. The project builds on past work in NCG injection by expanding the application to the full well life.
NCG injection at the proposed scale could reduce GHG emissions by up to 15 per cent in reservoirs affected by thief zones. Initial commercial deployment would occur at existing and new Surmont sites. The technology could be available for other SAGD operators to deploy as early as 2021. In addition to reducing GHG emissions, the technology could reduce operating costs for SAGD facilities by up to 20 per cent.