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CCS technologies show long, safe history
Shell’s Quest project is the first project to demonstrate carbon capture and storage technology in an oil sands application but most of the component parts have logged decades of dependable service.
“Most of these technologies have already been separately tested and proven over many years of reliable use in the energy industry,” said Len Heckel, Shell Canada’s Quest Venture Manager.
The three component technologies of CCS are:
- carbon dioxide (CO2) extraction from process gas streams;
- pipeline transportation, and;
- injection of CO2 into a deep geological formation.
“We’re confident Quest will demonstrate that these components will work just as safely and reliably within an integrated CCS system as they have in other applications,” Heckel said.
Shell will construct the Quest CCS project on behalf of the Athabasca Oil Sands Project joint venture owners, which are Shell Canada Energy (60 per cent), Chevron Canada Limited (20 per cent) and Marathon Oil Canada Corporation (20 per cent). The project has also received funding from the governments of Alberta and Canada.
Beginning in 2015, Quest will capture more than one million tonnes per year of CO2 from Shell’s Scotford oil sands upgrader near Fort Saskatchewan, Alberta -- the equivalent of taking 175,000 cars off the road annually. The CO2 will be sent by an 80-km pipeline to a suitable storage site where it will be injected and permanently stored more than two km underground.
Quest uses Shell technologies
Shell’s patented ADIP-X amine-based capture technology has been a worldwide gas processing industry standard for extracting hydrogen sulphide and CO2 from natural gas for more than 40 years. Fine-tuning the amine process to preferentially recover 98-per-cent-pure CO2 from the upgrader’s hydrogen manufacturing units is the only new aspect of the Quest carbon capture unit.
The Scotford upgrading process adds hydrogen to the heavy oil to break it down into synthetic crude oil which can then be processed into products like gasoline. Producing this hydrogen produces one of the largest sources of CO2 emissions from the upgrader.
Capture facilities will use an amine solvent to capture the CO2 from the process stream. The CO2 is released from the amine by heating and then dehydrated and compressed. The compression reduces its volume by about 400 times turning it into a very dense fluid. The “liquid” CO2 will be transported by an underground pipeline to between three to eight injection wells located north of the upgrader.
CO2 has been transported by pipelines in large volumes since 1972, for use in enhanced oil recovery (EOR) from declining oil fields, mostly in Texas. The longest, largest-capacity pipeline in the world was originally built in 1983 and was operated by Shell, moving CO2 800 km from the naturally-occurring McElmo Dome reservoir in Colorado to the Wassan oilfield in Texas. Today, the U.S. Energy Information Administration says 105 projects in that country safely inject more than 50 million tonnes of CO2 per year into oil formations to produce 90 million barrels of oil per year.
The natural gas industry also has decades of experience in injecting into underground geological formations. Although underground geological formations were first proposed by the U.S. Geological Survey in 1909 as the safest and most secure way to temporarily store large volumes of natural gas, the first commercial gas storage facility was opened in Welland County, Ontario in 1915.
Demonstrating storage capacity
Shell’s Quest CO2 storage formation is not connected to an oil or gas reservoir. Rather, Quest is designed to prove the storage capabilities of the very deep Basal Cambrian Sandstone (BCS) formation that underlies large parts of Alberta, Saskatchewan and the Northern Plains in the U.S. The BCS is considered ideal for CO2 storage at the chosen location because of its more than 2-km depth and multiple overlying layers of impermeable rock formations that act as regional seals.
Demonstrating the capacity and capability of this formation for high-volume permanent CO2 storage is important for the CCS projects that will be required in future to help governments achieve their CO2 reduction targets.
According to Dr. Stefan Bachu, a Distinguished Scientist with Alberta Innovates – Technology Futures*, the BCS is the best formation for permanent storage of CO2 in Alberta and Western Canada based on its large storage capacity; lack of hydrocarbons or other resources that would conflict with its use as a CO2 storage reservoir; and the fact that historically it has been penetrated by very few wells.
“Developing CCS as a technology to address climate change is vital,” says Dr. Bachu. “Shell's Quest project is important because it will help to demonstrate the integrated technology and the suitability of the BCS for CO2 storage.”
Quest will be the first CCS project in North America to inject commercial-scale volumes of CO2 into the BCS – after being the first project in Alberta to receive the rights to inject CO2 into “pore space” under new provincial CCS legislation enacted in 2011.
Modeling the subsurface
Shell has made a competitive advantage of its ability to model subsurface formations and this expertise has been used to ascertain the containment integrity of the underground area selected for storage.
“Our confidence in ability to safely and permanently store CO2 underground is partly based on experience with natural gas storage, which our industry has done with an excellent safety record for nearly 100 years,” said Project Subsurface Manager, Sean McFadden.
“We’ve taken extensive measures to be sure that the Quest storage formation is located in an area where there are multiple layers of impermeable sealing formations,” McFadden said.
Careful site selection
“Three sealing layers immediately overlying the Quest storage reservoir located deep underground include rock salt layers and a shale layer, totaling some 150 metres (485 feet) of impermeable rock. Chemical comparisons of salt water content in the BCS, with formations just above it show that there has been no communication between the two zones and that the salt water in this formation has been securely isolated for hundreds of millions of years.
“We’ve selected a storage site in the Basal Cambrian Sands because leading independent geologists rate it an excellent reservoir for large-scale carbon storage,” says McFadden.
According to McFadden, as a further precaution Shell selected a site that would avoid proximity to any legacy wells drilled into the BCS or its sealing formations.
“We’ve also designed the Shell injection wells with safety in mind,” McFadden said. “To protect shallow groundwater we’ve designed our CO2 injection wells with three layers of steel casing, each cemented in place to the surface,” McFadden said.
To avoid corrosion in either the pipeline or the injection wells that can be caused by water associated with the CO2, Shell has included a dehydration unit at Scotford to remove free water content from the CO2 stream. As further protection against corrosion, the bottom sections of tubing within CO2 injection wells will be chrome steel.
The materials selected for the pipeline were also based on their suitability for CO2 transport, and the pipeline will be made from low-temperature carbon steel material with specific toughness requirements.
Sophisticated monitoring technology
“As a new project type we recognize the onus is on Shell to do more, rather than less, in the area of safety assurance,” says McFadden.
“That’s why we will install a comprehensive suite of very sophisticated monitoring equipment at the Quest storage site to maintain multiple levels of measurement, monitoring and verification (MMV) over the life of our project to confirm that the CO2 remains contained. We’re conducting extensive monitoring underground – in the injection wells, the storage formation, deep monitoring wells and shallow groundwater wells - to provide the highest possible levels of assurance to area residents ,” McFadden said.
Quest also underwent a comprehensive third-party expert audit of its storage development plan and is the first project in the world to have received certification of fitness for safe CO2 storage by DNV (Det Norske Veritas) of Norway.
Cost reduction vital
Quest is intended to demonstrate that all the components of CCS work reliably together in an integrated system for safe and effective capture, transport and storage of CO2 from an oil sands upgrader — but Heckel said the real technical challenge is to identify ways to reduce the costs of commercial-scale CCS projects.
“CCS is something we need to do in order to reduce the carbon profile of industry in general and the oil sands in particular,” he said.
“A functioning industrial economy will need hydrocarbon energy for decades to come. By 2050, global energy demand is expected to double and, while hydrocarbons will be a smaller portion of energy totals, their use will increase in absolute terms. At the same time that energy demand increases, we must cut total CO2 emissions and CCS will be essential to that effort.
“The really big challenge will lie in driving down CCS costs in order to deliver energy that’s both affordable and has lower CO2 emissions,” Heckel said. “What we learn from Quest will be very important to that effort. And it will be even more important to the oil sands because of its high-cost production profile. Reducing CCS costs will be vital to keeping the oil sands and Alberta competitive.”
* Dr. Stefan Bachu is a Distinguished Scientist, CO2 Storage, at the Alberta Innovates - Technology Futures (formerly Alberta Research Council). He has spent two decades researching carbon storage and over 30 years researching subsurface flow of fluids and heat in the Western Canadian Sedimentary Basin. As a result of his contribution, in 2007 he shared in the Nobel Peace Prize awarded to the Intergovernmental Panel on Climate Change (IPCC).
He represents Alberta and Canada on various national and international bodies dealing with CO2 Capture and Storage such as the Carbon Sequestration Leadership Forum, sits on various advisory panels, and, is Associate Editor of the International Journal of Greenhouse Gas Control.