SCCS – new study of multiple CO2 storage sites

Sep 21 2015

UK research group Scottish Carbon Capture & Storage has released a study of multiple user storage sites in the North Sea, showing that it is safe to inject in the same formation at different points at the same time

UK research group Scottish Carbon Capture and Storage, which is based at the University of Edinburgh, has released a detailed study of how CO2 injection will work in the Captain Sandstone aquifer of the North Sea, with CO2 injected in two different sites in the same aquifer at the same time.

The purpose of the study is to give more confidence to people considering investing or sanctioning CCS construction projects in the UK.

It was also to provide further proof that CO2 storage in the North Sea can be safe and reliable, and give further confidence to anyone considering a carbon capture plant that there is a fully assessed storage facility available.

It aims to develop a standard methodology for assessing a reservoir for carbon dioxide storage.

The project can be a first step to any formal application for a license to store CO2 in the North Sea.

The study was made using 20-30 years of detailed reservoir data provided by Shell, from its oil and gas production operations in the region.

The project was led by Scottish Carbon Capture & Storage (SCCS) with support from the Scottish Government, The Crown Estate, Shell, Scottish Enterprise and Vattenfall.

The project also aims to get more benefit from the high initial investment in Phase 1 projects (Peterhead and White Rose).

It demonstrates that subsequent Phase 2 projects could inject their CO2 into the same reservoir at a different place.

The study also demonstrates how the UK’s CO2 storage infrastructure could also be made available to other countries around the North Sea, including Germany and the Netherlands. The CO2 could be transported cross border by pipeline or ship.

If more CCS projects are injecting into the aquifer, the cost per tonne of CO2 should drop.

The rough timescale is that 2007 to 2012 was spent ‘scoping’ CO2 storage sites, 2012 to 2015 was spent on studies like this one on specific sites, the carbon capture plants should be designed and built over 2015 to 2021, and then they would be operated for 40 years from 2021 to 2061.

The full report is online here

Storage potential

The UK’s CO2 storage potential in the North Sea has been estimated at 78 billion tonnes. As an illustration, the second largest power station in Europe, Drax, emits 22.8m tonnes of CO2 per year. So the UK could store Drax emissions for 3,400 years.

The Captain Sandstone aquifer, which is more than a mile beneath the Moray Firth off North East Scotland, could securely store at least 360m tonnes of CO2 (or 15 years of Drax emissions) in just one sixth of its area, with CO2 injected at between 6 and 12m tonnes per year over 3 decades, the study found.

The reservoir is 100 to 200m thick. It has a low permeability caprock above it, and then very low permeability chalk about that.

The Captain Oil Field, was discovered in 1977, and hydrocarbon production is still going on in it.



The project aims to create a “huge step forward in confidence” in CO2 storage, said Stuart Haszeldine, director of Scottish Carbon Capture and Storage. The study shows that guaranteeing safe CO2 storage “is not nearly as difficult as it’s imagined to be.”

Many members of the public still perceive that security of CO2 storage could be a huge risk, he said.

This project verifies the amount of secure offshore storage which is available in the UK. “It confirms the 2009 estimate of storage capacity.”

“This sandstone can handle all the Phase 1 and 2 projects we are talking about. There’s enough storage capacity for 200-300 years of electricity generation for the UK.”

The geological work to fully assess a storage site could be done in two years with a larger team, he said.



The study was made on the basis of having a first CO2 storage project, then adding a second one later, injecting into the same formation.

The model looked at injection from only site A from 2016 to 2046, then simultaneous injection in site A and site B over the same period.

It showed that CO2 injected into a reservoir at high pressure sees a fairly immediate pressure drop, as it flows into the reservoir.

It found that injection would lead to uplift (pushing up the caprock above), which would extend the size of the storage area.

By using two injection sites, it is of course possible to inject much bigger volumes of CO2 than with one injection site.

The modelling work started with a static geological model, and then modelled how it would change over time as CO2 was injected.

The project modelled how the pressure would build in the reservoir as the CO2 was injected, and how it would affect rock stresses. By modelling the rock integrity and fractures, it could calculate how much pressure the reservoir could withstand.

It looked at how the system responds to temperature changes, since CO2 temperature is different to the reservoir temperature.

It used Schlumberger’s Eclipse reservoir simulator and Petrel subsurface software, together with CMG’s GEM reservoir management software.

The study made use of detailed production data, which was provided by Shell. This included data about rock thermal stress, pressure, fractures and rock integrity.

It modelled the permeability and porosity of the rock, and how this can change. Cells in the model were 0.5m high vertically.


The study was made using data supplied by Shell. “Shell donated 20-30 years of data which enabled us to progress much faster and deeper than we did before,” Mr Haszeldine said.

There is an extensive archive of physical cores available from reservoir operations over the past decades, it is important that these are not disposed of, Mr Haszeldine said.

One possible concern is that the project depended on willingness from an oil company to provide the data, said Dr Maxine Akhurst, British Geological Survey, who led the project for SCCS.

If the oil company owning the data was not willing to share it, then there could be a problem, unless there is a regulatory agency able to force the data to be shared.

The study team also developed a method for how a subsurface team can be brought together to manage storage, similar to the way that oil companies put together an asset team with people with different skills to work out how to develop a reservoir.

It showed how the modelling could be done with industry standard software.

The study also showed that a lot of data you need is available commercially (ie within oil companies), including seismic data, subsurface pressure data, well log data and rock mechanical properties.


Download the full report

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