Cold wars

C&I Issue 11, 2012

When Shell dropped plans to drill wells in the Chukchi and Beaufort seas in the Arctic in summer 2012, it was following the orders of the regulator. The company was required to have a containment dome to catch oil that could leak onto the seabed if a there was a spill. But just as the dome was undergoing final tests, it was damaged, which meant cancelling plans to drill five Arctic wells in 2012.

The incident was an expensive setback for the company. But what if it could explore and drill in a cleaner and unobtrusive way? Environmentalists would no doubt ridicule this idea, but it is taken seriously by some geologists and petrochemical engineers. Al Fraser, geology professor at Imperial College, London University, UK, contends cleaner, more efficient technology can be developed, helping not only to protect the Arctic region but also giving Western companies a competitive edge over Russia.

The Russians, states Fraser, do not have the right skills to explore and drill successfully in Arctic regions. ‘They want to use a nuclear drilling machine to operate under the ice. We don’t want them to develop that or let them loose with inadequate technologies. At least Western companies are in there bringing the right technologies to bear,’ he says.

It follows that less intrusive technology could open the door to an Arctic future and provide a degree of public acceptability. That, at least, is the thinking behind a new project at Imperial College. The university is developing a store of new technologies that may help Arctic oil hunters operate more effectively in sub-zero temperatures. Among the ideas explored by the university’s new multidisciplinary Arctic research cluster, due to start up in 2013, with funding from oil and gas companies, is a technique known as down-hole processing.

Fraser and colleagues at Imperial’s Energy Futures Lab have dedicated more than two years of initial study to down-hole processing, a gasification technique that involves processing hydrocarbons underground rather than above the surface of the Earth. They aim to develop a reactor model for the gasification of hydrocarbons in order to produce hydrogen and synthesis gas (CO and H2) combined with upgraded hydrocarbons for different energy and petrochemical applications.

This underground conversion of hydrocarbons could potentially offer an alternative route towards clean production of hydrogen. Growing fuel cell markets, they argue, will drive a greater demand for synthesis gas and hydrogen, which are produced at the moment by steam reforming and partial oxidation of hydrocarbons.
‘At the moment, we take oil and gas deep in the subsurface and don’t make use of the energy associated with extracting it at high temperatures. Instead, we lift [oil] to the surface and put more energy in to converting it to fuel, increasing the carbon dioxide (CO2) emitted at the surface. Our long term aim is to separate the gases in situ, keep the CO2 underground and take the hydrogen and methane to the surface,’ explains Geoff Maitland, the energy engineer heading the Imperial College down-hole processing research project.

If this technology could be developed and used in the Arctic, it could make industrial activity in the region more acceptable to some organisations such as government regulators because it would produce fewer emissions and also require less surface equipment. This would produce a considerable benefit. As Fraser argues: ‘The people with the cleanest and most environmentally sensitive technologies will be the ones who get the licences.’

If down-hole processing evolves, Maitland envisages fairly modest facilities on the surface. ‘In environmentally sensitive areas, the surface footprint would be quite small. An analogy with underground coal gasification in mining is quite a good one,’ he says. Nevertheless, no commercial backing has been found for a long-term project as yet. Maitland, who is also in charge of investigations on carbon capture and storage (CCS), admits it is early days and the first plant could be decades away.

The group’s initial research project examining a down-hole reactor model has consisted of a qualitative and quantitative analysis of water-oil reactions under hydrothermal conditions, using high pressure/temperature water in a hydrothermal reactor. ‘The use of a hydrothermal environment for chemical conversion has attracted much research recently due to the unique properties exhibited by hydrothermal water, which include the complete miscibility of oil in water, the enhanced heat and mass transfer, and the increase in reaction rate,’ points out Klaus Hellgardt, reader in chemical engineering at Imperial College.

The conversion of hydrocarbons underground could potentially offer an alternative route towards the clean production of hydrogen. The engineers engaged in the tests suggest that redundant production wells could be used as hydrothermal reactor systems with the explicit injection of oil, steam and air or oxygen, thus removing the need for above ground reformers.

This would mean using the sub-surface well system as a continuous processing and reactor network to carry out as much as possible of the required conversions in the well system underground or close to it at the wellhead.

‘The goal is to radically reduce, by design, the overall environmental footprint by minimising the number of species extracted other than final products, as well as the number of external processing steps and the need for transport to and from the underground fields,’ explains Hellgardt. At the same time, this would improve the overall economics of new fields and increase the efficiency of recovery from conventional, mature reservoirs. The commercialisation of this process will depend, however, on how successful they are in improving gasification efficiency. Developing the process further will mean finding out more about the effects of partial oxidation, catalysis and the sulphur contained in crude oil.

Some of their tests are informed by research at Imperial College’s new Qatar Carbonates and Carbon Storage Research Centre (QCCSRC), which is directed by Maitland, and which could yield carbon storage solutions in carbonate reservoirs that are fractured and more complex, with rocks of different pore sizes.

Fraser envisages funding of £0.5–1m/year for three to five years for the cold temperature project, dubbed the Arctic Grand Challenge and operating along the lines of the Shell Imperial Grand Challenge Project on Clean Fossil Fuels, a multi-million pound research programme focusing on developing processes that will help enhance the extraction of difficult hydrocarbons with minimal release of greenhouse gases (GHG).

In the case of Arctic engineering, the scientists want to partner with similar companies for funding and also for other research purposes. ‘In terms of Arctic exploration and production, this encompasses all aspects of subsurface resource estimation, cold weather technology, environmental impact and regulatory frameworks,’ he says. Shell and Exxon Mobil are sponsors that could get involved, he suggests.

Methane hydrates are among some of the concerns the scientists will address. This subsea methane trapped in ice can become unstable and dangerous if oil companies attempt to interfere with it. Fraser indicates his team could find a better way to address the problem than present attempts by the Russians.

‘The hydrates are a potential threat. Once the climate starts warming, they can be released and there’s a lot trapped in the Arctic. In terms of hydrates, we need to understand where they are and the physics of how they are trapped in the permafrost. How the permafrost is destabilised is not something we really understand.’

Fraser foresees particular problems in terms of gas production. ‘With gas, the pipelines will need to be buried below the Arctic seabed – there will be problems with hydrates and other cold weather operation of machinery – not insurmountable but all adding to the cost,’ he says. The gas would be transported by pipeline to Western Siberia and then to Western Europe.

Some of the Arctic is frozen for six months of the year, requiring a six months on/six months off phased oil production strategy, which was pioneered by Shell off Sakhalin Island, just off the East coast of Russia, and involves producing oil for six months of the year into tankers when there is no ice and drilling production wells and cleaning up existing wells during the ice bound shut in period.

‘Greenland, although largely ice free year round, is beset by iceberg issues. Fixed installations are difficult unless you can find a method of diverting large bergs. For the production of oil this should not be a problem, but gas pipelines will need to be buried below the seabed,’ says Fraser.

The application of medical robotics to geology is among other ideas being considered. Robots used in healthcare have been developed to work effectively in cold conditions, and could mean fewer and more mobile arctic installations as well as more remotely-controlled activity.

New laboratories at Imperial’s QCCSRC are to be the first in the world, for example, to use multi-scale X-Ray CT technology – more commonly used in hospitals to visualise internal structures of the body – alongside other state-of-the-art measurement and modelling techniques, to understand the way carbon dioxide interacts and flows in carbonate rock formations.

Technology transfer of this kind using robots to solve the problems of working in cold Arctic temperatures ‘would be a game changing technology,’ says Fraser.

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