I don’t normally use this blog to write about Shell, but last week saw an announcement that is very relevant and worthy of some further elaboration. Shell Canada, as operator of the Athabasca Oil Sands Project joint venture (with Chevron and Marathon), announced plans to proceed with a carbon capture and storage project (Quest) within the current oils sands project. This is a project that has been under discussion in one form or another since almost day one of production from the facilities, but the lack of a workable economic justification for the project has been the major impediment to progress.

In recent years the story has changed though. The Government of Alberta has developed a carbon pricing system which provides a level of underlying support for the project. The World Bank “State and Trend of the Carbon Market 2012” report describes the Alberta system (on page 89) as follows:

Alberta is Canada’s largest greenhouse gas (GHG) emitting province, accounting for 34% of the country’s total GHG emissions in 2010. This represents 235 MtCO2e, a 41% increase from 1990 levels, driven primarily by increased production activity in its oil and gas sector. On July 1, 2007, Alberta launched a mandatory GHG emission intensity-based mechanism, enacting the first GHG emissions legislation in Canada. Approximately 100 entities with annual emissions exceeding 100,000 tCO2e (ktCO2e), are required by the legislation to reduce their emission intensity by 12% from average 2003-2005 levels. Entities that do not meet reduction requirements on a given year may choose to meet these obligations by:

Trading “Emissions Performance Credits” (EPC) that are awarded to covered entities that reduce emissions below their set target;

Paying CN$15 (US$15.2) into a technology fund; and/or

Purchasing Alberta-based offsets issued by the Alberta Offsets Registry under an approved protocol.

N.B. The World Bank chart below shows the number of offsets retired annually through the system with an estimate for 2011 (not announced at the time the report was published). The price has remained very close to the technology fund alternative.

As such, this system provides an underlying base level of support of some CAN$15 per tonne of CO2 for the CCS project. In addition, in 2011 the Alberta Government announced a further support mechanism for CCS though the system, which now grants a second bonus credit for CCS projects meeting certain criteria. The Canadian based Pembina Institute published the diagram below, challenging the environmental integrity of the approach, but it also gives a simple explanation of how the mechanism works. In a completely closed system the environmental integrity argument would be correct, but in the open ended Alberta system with payment into a technology fund as a compliance option, the argument is hardly valid.

A further, but much less quantifiable, price signal is that coming from the California Low Carbon Fuel Standard (LCFS) and to a much lesser extent the EU Fuel Quality Directive (FQD). These mechanisms place a carbon footprint target on the fuel in the transport sector with a starting baseline about equal to the carbon footprint of oil products processed through a conventional production and refining route and then declining by about 1% per annum. When oil sands products arrive in these markets, their higher carbon footprint generates a penalty on the use of the component in the fuel pool which manifests itself as a price on carbon emissions associated with the production and use of the product. Of course the product may be targeted at other markets, but even a small location constraint on a product can lead to a trading discount in some market circumstances. This is also a carbon price of sorts. In any case, the prevalence of LCFS type approaches could well increase over the years ahead, which could penalize oil sands relative to some other production routes.

The combination of Provincial and Federal grants, a Province based carbon pricing system and its bonus credits and consideration of the role played by fuel standards in export markets in the future has allowed the project to get the green light. This should be seen as good news. CCS is the critical technology for real long term reductions in emissions – I have argued in the past that it may well be the only technology, so supporting it now and getting at least some early projects up and running should be an essential policy goal. Support remains a dilemma for policy makers, particularly in challenging economic times. However, there is a valid role to play here in that almost every carbon roadmap to 2030 and beyond shows CCS being required, yet there is currently no carbon price signal strong enough in any jurisdiction to actually build one now and therefore begin the process of demonstration and commercialization.

The project itself is medium in scale, storing about one million tonnes per annum of CO2 coming from the Hydrogen Manufacturing Unit (HMU) linked to the oil sands bitumen upgrader. The HMU produces hydrogen by steam reforming of natural gas, with a nearly pure CO2 stream as a byproduct. At high temperatures (700–1100 °C), steam (H2O) reacts with methane (CH4) to yield syngas.

CH4 + H2O → CO + 3 H2

In a second stage, additional hydrogen is generated through the lower-temperature water gas shift reaction, performed at about 130 °C:

CO + H2O → CO2 + H2

Heat required to drive the process is supplied by burning some portion of the natural gas. A very simple overview of the process is shown below.

The capture plant is located in Fort Saskatchewan, approx 50 km N.E. of Edmonton, Alberta. The CO2 will be transported by 12 inch pipeline to storage, approximately 65 km north of the upgrader site. The CO2 will be stored in a saline aquifer formation called Basal Cambrian Sands (BCS). At 2,300 metres below the surface it is some of the deepest sandstone in the region, with multiple caprock and salt seal layers and no significant faulting visible from wells or seismic activity. The BCS is well below hydrocarbon bearing formations and potable water zones in the region. Relatively few wells have been drilled into the BCS and none within 10 km of the proposed storage site.

It’s been a long road from initial discussion, to early concept and finally the investment decision last week. But the end result is a real CCS project!!