Injecting and storing carbon dioxide in saline aquifers or old oil and gas fields poses challenges that can only be addressed by a forensic understanding of the geology of storage reservoirs and detailed knowledge about the behaviour of CO2 in a subsurface environment.
Once injected under an impermeable cap rock, CO2 will rise vertically to the top of the reservoir and can migrate hundreds of kilometres laterally.
A CO2 "plume" probes for weaknesses as it moves upwards and sideways, continually seeking routes to get to the surface and leak out.
A leak into the atmosphere or water column is the last thing a carbon capture and storage investor wants, as is the CO2 migrating beyond the legal boundaries of a storage licence.
Stuart Haszeldine, professor of CCS at the University of Edinburgh, explains that when underground, CO2 is “more runny” than oil or gas and “finds pathways through rock you never knew existed”.
So, CCS operators are developing methods to pinpoint weaknesses in cap rock, to identify physical interconnections between storage reservoirs and to accurately track the movement of CO2 and measure subsurface pressures.
For a storage reservoir, it is not enough to gather and evaluate cores because better resolution is needed on characteristics such as permeability.
This can be achieved using X-rays and undertaking micro-scale CO2 injection tests on cores.
Data from seismic surveys can help identify potential subsurface interconnectivity between storage reservoirs.
Haszeldine — speaking at a symposium organised by the Petroleum Exploration Society of Great Britain — highlights the UK Southern North Sea as an example, given plans to use the Bunter sandstone aquifer as a storage horizon.
As CO2 is injected, it migrates laterally into surrounding areas creating “a huge pressure cell”, he says. So, if other storage licences are awarded within the horizontal limits of this cell, their owners will find their ability to store CO2 is reduced.
Haszeldine argues that this entire, connected Bunter sandstone storage play needs to be operated as a single concession.
“The scale of CO2 storage sites can be astronomical compared to most oil and gas fields, a factor that must be considered when awarding licences.”
In terms of tracking CO2 on its subsurface migration, he notes: “The leading edge of a CO2 plume is hard to track but must be monitored to ensure it does not transgress beyond the geographical limits of a storage licence.”
Stephane Vignau, subsurface manager of the Northern Lights CCS scheme offshore Norway, notes that the injected CO2 must stay within the boundaries of the storage licence until 2054, otherwise it may affect oil and gas production at the Troll field.
Careful attention must also be paid to subsurface pressures because, if too high, rocks may fracture, compromising the integrity of a storage asset.
In depleted hydrocarbon fields, legacy development wells can offer pathways for injected CO2 to escape.
These legacy wells cause what Owain Tucker, Shell’s principal technical expert on CCS, describes as “anthropogenic bioturbation”, a shorthand for displacement of rock by human activities, including drilling.
Monitoring, perhaps every five years, is important because a regulator will want to know how much CO2 has been injected and where it is.
This can be achieved by analysing data from seismic surveys and information transmitted from downhole equipment to operations centres via fibre-optic lines.
Haszeldine says this equipment must be designed to transmit real-time data over decades, perhaps complemented by information flow from autonomous drones looking out for CO2 seeps.