Piping up about carbon
The technical details surrounding CO2 pipelines that will push forward carbon capture and storage from coal-fired power plants were hot topics at an event on 28 October, in London, UK. Rachel Connolly reports
Several questions regarding material choice, valve design, stream impurities and health and safety will impact upon CO2 pipeline construction for carbon capture storage (CCS) from coal-fired power plants.
Standard pipeline failure data from the European Gas Pipeline Failure Group, United Kingdom Offshore Piping Association, Conservation of Clean Air and Water in Europe, and the Pipeline and Hazardous Materials Administration reveal that the larger pipelines deeper underground are less likely to have incident or rupture. However, this information is not specific to CCS.
Isabelle McKenzie from the UK’s Energy Institute, based in London, presented their work at the Carbon Capture and Storage event held in London on 28 October. Her research led to modelling of CO2 pipeline rupture and the hazard analysis for onshore CO2 systems to screen projects and evaluate mitigation. She hopes to produce CO2 specific frequency failure data and will look ahead to research offshore installations and produce guidelines for industry training on plant and pipeline design and operation.
The capability of modern pipe mills to produce high toughness steel that can withstand low temperatures was considered. Speakers referred to the need for pipeline specifications and agreed that thicker pipe wall thickness would insure against long running fractures.
Experience of carbon steel (such as API X -60/65/70) for transporting dry CO2 streams for enhanced oil recovery (EOR) is already available in the USA with more than 3,500km of CO2 pipework.
The choice of material reflects the corrosive effect of water and CO2 together. Additionally, hydrates could form at low temperatures, causing blockages and scaling. Corrosion will not, however, occur if the saturation levels are below 60%, approximately 1,576mg/m3. Given that industry accepted levels of water are as 288-480mg/m3, this specification is generally accepted for CO2 pipelines as well.
In the stream
Another aspect is the influence of impurities like hydrogen sulphide, sulphur dioxide or hydrogen in CO2 streams on the physical phase behaviour, and consequently on pipeline design.
The Oslo Paris Commission, made up of representatives of the Governments of 15 Contracting Parties and the European Commission, says that ‘provided no wastes or other matter are added, streams may contain incidental associated substances derived from the source material and the capture transport and storage processes used’.
A pipeline must therefore consider the safety issues associated not only with CO2 but with its contaminants and ensure, as a minimum, that they stay within their short-term exposure limit. These levels must also be critically reviewed, as the results are dependant on time exposed to CO2. More threatening hazards caused by a pipeline leak include hydrogen sulphide, which causes headaches and nausea at 50ppm, whereas 100ppm can cause unconsciousness within a few minutes (statistics from the International Environment Agency Green House Gas 2004).
As well as the physical constituents of the stream, its condition will also influence pipeline design. The pressure and temperature for entry must be kept at a near uniform level to avoid local pressure problems such as two-phase flow or changes in bulk temperature. A specification must include a minimum pressure and a maximum temperature. Generally, given the critical point, temperature is limited to less than 30ºC, a minimum pressure of 100bar would be acceptable. This gives a 30bar margin from the critical point to allow for pressure drops within the system.
To control these factors and detect a leak, there must be a system in place to monitor CO2 flow. Dr Klaus Kaufmann, Lead Process Engineer in the Oil and Gas Division at ILF Consulting Engineers, in Munich, Germany, presented a potential hazard scenario where a damaged pipeline results in a gaseous CO2 with fine dispersed solid particles propelled in a cold momentum jet stream (-78.5ºC) into the atmosphere. A CO2 cloud mixed with air would be influenced by metrological and topographic conditions and would disperse and dilute to a non-dangerous concentration. The leak would be expected to be identified by a sensitive detection system, which would in turn cause the adjacent line valve to rapidly close to minimise CO2 inventory loss.
As the impetus for building a CCS system is likely to be financial (based on selling carbon credits), metering of CO2 sent for disposal will be necessary at all sources prior to injection. Metering would also be required at the point of storage to ensure that all CO2 is injected.
Tony Grayling, Head of Climate Change and Sustainable Development, at the Environment Agency UK, wants early public engagement. He says ‘we need to review if CCS is economically and technically proven. Are projects elsewhere transferable to the UK?’
Industrial scale sites such as Weyburn, Canada, Sleipner in the Norwegian sector of the North Sea and In Salh in the Algerian desert, are now in operation. The UK is however still waiting for funding before research can be carried out on the first UK demonstration plant.