ERA OIL SANDS INNOVATION CHALLENGE PROJECTS

MEG Energy eMVAPEX Pilot, Phase 3
ERA contribution: $10 million
MEG Energy Corp. (“MEG”) is an Alberta company focused on sustainable in situ oil sands development and production in the southern Athabasca oil sands region of Alberta. Current bitumen production averages approximately 90,000 bpd.

For long term success, MEG uses innovation to lower the cost and greenhouse gas (GHG) emission intensity of bitumen production. Steam generation is the main contributor to GHG emissions, water consumption and the capital/operating costs of bitumen production. The concept eMVAPEX (enhanced Modified VAPour EXtraction involves the application of infill wells and the injection of a condensable gas (ex. propane) in lieu of steam after initial steam-assisted gravity drainage (SAGD) operation. It is anticipated that 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% with the same steam assets by employing eMVAPEX. The resulting overall GHG emission intensity could be reduced by as much as 43%. 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.

Media contact
Davis Shermata
Senior External Communications Advisor
MEG Energy
587-233-8311 Cell 403-671-7281
davis.sheremata@megenergy.com


Cenovus Energy Inc.
FSG Field Prototype
ERA contribution: $10 million
Cenovus will partner with FSG Technologies Inc. to demonstrate FSG technology, also known as Flash Steam Generation, for production of steam for in-situ oil sands extraction.

FSG’s novel 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% compared to conventional steam generation and water treatment. In addition to reducing GHG emissions, implementation of an FSG in-situ facility is expected to achieve up to a 20% reduction in capital expenditures and a 15% reduction in operating expenditures, compared with conventional technology.

Media contact
Sonja Franklin
Senior Media Advisor
Cenovus Energy
403-766-7264
Media line 403-766-7751
media.relations@cenovus.com


Suncor Energy Inc.
High Temperature Membranes for SAGD Produced Water Treatment
ERA contribution: $2.5 million
Suncor will partner with Devon Energy and Suez (formerly GE Water) to demonstrate High Temperature Reverse Osmosis (HTRO) membranes for SAGD water treatment.

The project will validate the technology for application in high-temperature SAGD conditions. If successful, the membranes could eliminate the need to reduce the temperature and pressure of produced water prior to water treatment. A high temperature membrane plant could reduce the energy required and infrastructure for the SAGD water treatment process.

The technology has the potential to reduce GHG emissions by up to 5-10%, compared to a typical SAGD baseline facility. In addition, for new builds, the technology could reduce capital costs compared to conventional SAGD water treatment facilities.

Media contact
Suncor Media Relations
403-296-4000
media@suncor.com


ConocoPhillips Canada
Non-Condensable Gas Co-Injection for Thief Zones
ERA contribution: $2.5 million
ConocoPhillips Canada, as operator of its Surmont joint venture with Total E&P Canada, will 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% 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%.

Media contact
Katherine Springall
Senior Communications Advisor
ConocoPhillips Canada
403-260-1764
katherine.springall@cop.com


Heavy Oil Solutions and Cenovus Energy Inc.
Partial Upgrader with Integrated Water Treatment
ERA contribution: $10 million
Heavy Oil Solutions and Cenovus plan to test a process to upgrade bitumen to lighter oil at Cenovus’s Christina Lake oil sands 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 much-needed 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.

Media contact
Chris Traylor, CEO
Heavy Oil Solutions
505-710-9030
chris.traylor@heavyoilsolutions.com


Enlighten Innovations Inc. (Formerly Field Upgrading)
CLEANSEAS™ Demonstration Project
ERA contribution: $10 million
Enlighten Innovations Inc. will design and construct a demonstration facility for its DSU® technology. DSU removes sulphur and partially upgrades heavy oil including Alberta bitumen into low-sulfur 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 towards 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.

Enlighten Innovations estimates that the DSU technology reduces GHG emissions on a lifecycle basis by up to 40% compared to alternative pathways for production of marine fuel.

Media contact
Michelle Chidley
Enlighten Innovations
403-540-2048
michelle@aislingcommunications.ca


Cenovus Energy Inc
.
Multi-Pad Pilot of a Solvent-Aided Process
ERA contribution: $10 million
Solvent use is one of the key technologies Cenovus is working on to improve the efficiency of its in-situ oil sands recovery and reduce its environmental impact, especially in the area of GHG emissions.

Solvent-aided process, or SAP for short, 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 oil sands project.

Media contact
Sonja Franklin
Senior Media Advisor
Cenovus Energy
403-766-7264 Media line 403-766-7751
media.relations@cenovus.com


Canadian Natural Resources Limited
In-Pit Extraction Process
ERA contribution: $5.6 million
Canadian Natural Resources Limited (Canadian Natural) will demonstrate a field pilot of its In-Pit Extraction Process (IPEP) technology, an alternative to conventional oil sands mining and ore processing.

The IPEP technology 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. In addition to reducing GHG emissions, IPEP produces stackable tailings within the mine pit, greatly reducing the volume of fluid tailings and ultimately accelerating reclamation of oil sands mines.

Canadian Natural estimates that the IPEP technology could reduce GHG emissions by up to 40% in bitumen production compared to typical oil sands 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 oil sands mining companies through COSIA for more rapid industry-wide adoption. In addition to reducing GHG emissions and creating other environmental benefits, it is estimated that the technology will reduce production costs by roughly $2/bbl and substantially reduce long term tailings management costs and liabilities.

Media contact
Julie Woo
Public Affairs Lead
Canadian Natural Resources Limited
403-514-7777
ir@cnrl.com

 

Imperial
Enhanced Bitumen Recovery Technology Pilot
ERA contribution: $10 million
Imperial is advancing 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% compared to current methods. Alternatives to steam are key to increasing energy efficiency and reducing water use from oil sands operations. 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% 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%.

Media contact
Lisa Schmidt
Media Relations Advisor
Imperial
587-476-7010
lisa.m.schmidt@esso.ca