Oil shale is a fine-grained sedimentary rock containing kerogen—a solid organic precursor to oil and gas—from which oil and gas can be obtained through the application of heat. There are two basic approaches to processing oil shale: mining the rock and heating it in a surface retort, and heating the rock in the ground, to then pump up the resulting oil.

In its in-situ process, Shell drills holes into the shale resource, inserts electric resistance heaters, and heats the subsurface to around 343º C (650º F) over a 3- to 4-year period. During this time, very dense oil and gas is expelled from the kerogen and undergoes a series of changes, including the shearing of lighter components from the dense carbon compounds, the concentration of available hydrogen into these lighter compounds, and the changing of phase of those lighter more hydrogen rich compounds from liquid to gas.

These gaseous lighter fractions are now far more mobile and can move in the subsurface through existing or induced fractures to conventional producing wells from which they are brought to the surface.

Shell says that ICP results in the production of about 65%–70% of the original carbon in place in the subsurface. The carbon that does remain in the sub-surface resembles a char, is extremely hydrogen deficient and if brought to the surface would require extensive energy intensive upgrading and saturation with hydrogen. (Earlier post.)

The ICP process consists of four primary steps:

• A freeze wall is created around the perimeter of an area of shale to be retorted (a production “cell”).

• The oil shale within the cell is heated using electric resistance heating. The heat conducts through the formation, slowly heating the shale to the temperature of kerogen decomposition.

• After kerogen conversion, the resulting hydrocarbons are pumped from the earth.

• The production cell undergoes remediation: residual mobile hydrocarbons are flushed from the earth and the freeze wall is thawed.

(In 2007, Shell withdrew the application for a mining permit on one of its three oil-shale research and demonstration leases for economic reasons: costs for building the underground freeze wall of frozen water to contain melted shale had “significantly escalated.”) (Earlier post.)

Brandt modeled two commercial-scale cases of ICP deployment, representing low and high energy and GHG intensity, to come up with the 30.6-37.1 grams of carbon equivalent result. An earlier study of Shell’s ICP by other researchers derived a 27-34g carbon equivalent per MJ of refined fuel delivered.

Earlier analyses of surface retorting cited by Brandt projected emissions estimates in the range of 31-75 gC_equiv/MJ RFD. Emissions from Alberta tar sand production are in the range of 29-36 gC_equiv/MJ, while those from coal-based synthetic fuels are in the range of 42-49 gC_equiv/MJ, Brandt notes.

Near-term emissions from the ICP are likely to be closer to the high estimate presented in this report...In the long term, it is possible to implement a low-carbon ICP. The energy requirements of heating are likely to not be sensitive to intermittency, because of the high heat capacity of the large mass of shale and the long heating time. Thus, intermittent renewables could be used in off-peak times.

Second, the reuse of waste heat seems feasible, given that the hot, depleted production cells will need be flushed with water to meet the water quality requirements in any case. However, these low-carbon ICP options are costly and, therefore, are unlikely without regulation of carbon emissions.

Large-scale oil shale development could result in significant additional emissions. If we produce, refine, and combust fuel equal to 10% of the 2005 US gasoline consumption (~1.8 x 10¹⁸ J) using the ICP instead of conventional oil, full-fuel cycle emissions increase from ~45 million tonnes of carbon (MtC) for conventional oil to 55-67 MtC. This approximate increase of 10-20 MtC can be compared to total emissions from the state of Colorado, which were 24 MtC in 2001.

The wide range of potential impacts of the ICP and its inherent flexibility underscore the importance of deliberately and consciously choosing our path as we transition to oil substitutes. Finding an environmentally responsible path to secure domestic fuel supplies will be dependent not only on developing new alternatives to oil, but also on implementing policies and programs to guide the responsible deployment of these technologies.

—Brandt (2008)

Separately, a recent report from MIT’s Laboratory for Energy and the Environment concluded that a 10% oil sands component in US petroleum fuels would increase fuel cycle greenhouse emissions approximately equal to the loss of one to three MPG in new vehicle fuel economy in 2035.

In other words, in order to make up for the additional emissions from fuel cycle [with a 10% oil sand component], the cars and light-trucks will have to attain higher levels of fuel economy to keep the well-to-wheels emissions from getting worse. This loss is equivalent to the fuel use reduction achieved through a 7.5 % market penetration of hybrid vehicles by 2035 in case of low oil sands share and up to 20% market penetration of hybrid vehicles by 2035 in case of high oil sands share.

—On the Road in 2035

Resources

• Adam R. Brandt (2008) Converting Oil Shale to Liquid Fuels: Energy Inputs and Greenhouse Gas Emissions of the Shell in Situ Conversion Process. ASAP Environ. Sci. Technol., doi: 10.1021/es800531f

• On the Road in 2035 (MIT 2008)