Geological

UKCCSC Theme B - Geological storage

Theme leader: Jonathan Pierce, British Geological Survey

Most of the key issues that need to be considered in long term CO2 storage are geological. These include the available underground storage capacity in saline aquifers and oil and gas fields, and the characterization, modelling, risk assessment, monitoring and long term management of underground storage reservoirs. The integrity of a potential storage site (i.e. will it leak?) is possibly the most contentious issue. Reducing the uncertainty associated with the above is of prime importance in assessing the technical feasibility of large-scale CCS in the UK. The project will address these issues through 3 themes which address potential UK CO2 storage sites:

  • B1 - CO2 storage integrity: pre-assessment
  • B2 - UK Hydrocarbon fields and added value from CO2
  • B3 - UK offshore and onshore aquifers: injectivity and storage volumes

Assessing the cost, additional benefits (e.g. enhanced oil recovery), environmental implications, public acceptability and the role that CCS could play in future energy scenarios also all require major inputs from the characterisation and modelling of geological storage sites. Thus there will be major inputs from theme B: Geological Storage into theme E: Geographical Information System and theme A: Fossil Energy Systems themes including CO2 transport topics.

Theme B1 - CO2 storage integrity: pre-assessment

The prime objective of this topic is to combine state-of-the-art knowledge of storage issues with relevant expertise from other areas to provide an informed assessment. The integrity and performance of geological repositories is potentially the most contentious issue in all the stages involved in CCS. To gain acceptance with policy-makers, regulators and the public, it will be necessary to demonstrate that storage sites are both effective and safe. The definition of a robust site characterisation, performance prediction methodology and monitoring programme is likely to form a key component of a successful site licensing application.

Therefore, it is necessary to:

  • Demonstrate that CO2 could remain stored for periods in excess of 1000 to 10,000 years.
  • Show that if a leak does occur, it is unlikely to pose a significant hazard at the surface.
  • Investigate the effects of leakage to the surface, and ascertain the level of hazard this poses.
  • Show that for more significant leaks, a remediation programme is feasible.
  • Devise a remediation programme to address more significant leaks.
  • Formulate a regulatory framework including verification for emissions credits and national inventories, site licensing including risk assessment, monitoring and site abandonment.

To do this it will be required to characterise the whole reservoir setting, identify risks and monitor injection, and validate predictive models of long-term CO2behaviour in the geosphere. Reservoir modelling is complicated, since the flow of multi-phase fluids (e.g. CO2, water, gas, oil) is a difficult physical and chemical problem to understand. The chemical reactions between fluids and rocks vary in rate from seconds to millions of years and the kinetics of these reactions are poorly constrained. The processes of injection, flow and fluid and mineral reactions all cause modification of the reservoir. It is necessary to make predictions for periods up to 1000 times longer than it has been possible to directly observe reservoirs. This topic will make a rigorous evaluation of four, mutually-dependent projects considered critical for the site characterisation, reservoir modelling, risk assessment and regulatory framework development and are described more fully below:

B1.1a Caprocks and seals: permeability modelling

Leader: Andrew Aplin, University of Newcastle

Mud-rich caprocks and evaporites are the critical layers that will retain CO2. It is essential to show that the mudrock seals are able to retain potentially chemically active CO2 fluids for appropriate timescales.  One sub-project will estimate the potential reliability of caprocks overlying chosen UK candidate reservoirs. University of Newcastle (Prof A. Aplin, Kurtev) will develop a model to estimate the relative permeability of mudstones from pore size and connectivity data using both a modified capillary pressure-saturation approach and, with Heriot Watt, a pore network modelling approach.

B1.1b Caprocks and seals: Field studies of naturally leaking mudrocks

Leaders: Stuart Haszeldine, University of Edinburgh; Zoe Shipton, University of Glasgow

The Universities of Edinburgh and Glasgow will carry out field studies where CO 2 fluids are known to be naturally leaking through mudrocks. This work will be combined with modelling of CO2 flows through reservoirs. This sub-project will inform the reliability assessments in B1.1a, above, and define criteria for, and identify knowledge gaps in, a regulatory framework.

B1.1c Well integrity studies; experiments on cement stability in CO2

Leader: Geoffrey Maitland, Imperial College of Science and Technology

The chemomechanical durability of the cement behind casings in the wells used for CO2 injection into storage reservoirs, and the integrity of the final well seals are amongst the most crucial issues for the technical viability and the public perception of CCS. This work is aimed at understanding how cements interact with CO2, and to relate chemical changes to structural changes (fractures, microannulus formation) and mechanical property deterioration. The main technique used to follow chemical changes is Fourier Transform Infra-red Spectroscopy (FTIR) using high pressure cells. These will be linked to mechanical sealing experiments where the leakage of CO2 can be monitored alongside the chemomechanical condition of the sealant. A variety of oilfield cements will be studied alongside other sealing materials that might be considered as alternatives. The aims of the work are to understand better the mechanisms at work when CO2 interacts with cements, elastomers etc, and to identify the physical and chemical characteristics that are needed to optimize sealant durability under typical well conditions, so that ultimately improved cements or other materials may be designed for CO2 well integrity. Collaboration with complementary work at BGS and Heriot Watt is being explored.

B1.2 Geochemical Responses to Storage

Leaders: Mike Bickle, University of Cambridge; Bruce Yardley, University of Leeds

The Universities of Cambridge & Leeds and the BGS will lead a project designed to assess the thermodynamics, kinetics and geochemical signatures of flow and reaction processes in reservoirs. The injection of CO2, an acid gas, into reservoirs where it can interact with existing formation waters, leads to a lowering of pH that creates disequilibrium between pore waters and their host rock. Some impurity gases can have even more dramatic effects on pH.

Chemical reactions instigated by these pH changes may threaten the physical integrity of storage by dissolving solid phases, but can also lead to a permeability reduction through the precipitation of carbonate minerals and permanent fixation of CO2. The fluid-fluid and fluid-solid reactions will moderate both the physical properties of the fluids and the permeability structure of the solids. Knowledge of these processes is therefore also critical to physical models of multiphase flow in reservoirs. Resolving what is likely to happen in any specific reservoir requires an understanding of the absolute and relative rates of a series of processes involving fluid-fluid and fluid-mineral interactions and because of variability of reservoir characteristics must be evaluated for specific sites. The project will:

  1. identify the critical reactions and carry out kinetic experiments at the BGS hydrothermal laboratory
  2. initiate development of a database of key fluid thermodynamic and reaction-kinetic properties in conjunction with researchers currently working on the physics of multi-phase flow at the BP Institute, Cambridge University
  3. assess potential geochemical and isotopic monitors of fluid flow and reactions in reservoirs.

B1.3 Geophysical monitoring

Leader: Mike Kendall, University of Bristol; Andrew Chadwick, British Geological Survey; Quentin Fisher, University of Leeds

This project will generate an improved quantitative understanding of fluid-fluid and fluid-rock interaction through seismic monitoring using time-lapse 3D (4D) reflection techniques, which is the prime method for mapping subsurface fluid movement. As well as improving verification of stored volumes, the modelling will provide generic insights into how seismic response varies with CO2 distribution in a porous reservoir. Results will help constrain reservoir simulations and provide guidelines for designing future, more sophisticated monitoring surveys. Precise quantification and location of CO2 is critical for evaluating reservoir performance but has proved difficult when CO2 is in solution. A number of more sophisticated techniques have proved effective at imaging other geological fluids and their application should substantially enhance our ability to image and quantify CO2 and its movement in the repositories. The BGS will deploy wave propagation modelling techniques on the Sleipner Field (Norwegian North Sea CO2 Storage project) CO2 plume.

B2 UK Hydrocarbon fields and added value from CO2

While recent DTI studies have indicated that at present North Sea operators are not actively interested in CO2 injection for enhanced oil recovery (EOR) due unfavourable project economics, the North Sea oil and gas fields are an ideal location to store CO2 since they offer known structural traps and infrastructure, and CO2 injection can be used to boost hydrocarbon recovery. The economic benefit of EOR makes hydrocarbon fields likely early storage candidates. However, if EOR is delayed far into the next decade removal of the field infrastructure will mean that only a fraction the maximum potential capacity available will be left, creating some urgency in getting this technology adopted. An integrated assessment of CO2 EOR will be performed with a detailed analysis of injection into two or three specific case studies.

B2.1 Near-field and reservoir characterisation

Leader: Stuart Haszeldine

Imperial College London will describe in detail candidate North Sea fields, especially trap structure and integrity, using data acquired from the BGS and collaborating North Sea oil operators, including data from the Maureen field for which geological models already exist. It is anticipated that reservoir descriptions will also be made available from Forties, including a previous feasibility study for CO2 EOR, and other fields.

B2.2 Subsurface flow modelling

Leader: Martin Blunt, Imperial College of Science and Technology

This will involve the assessment by the Universities of Edinburgh and Leeds of CO2 injection in order to maximise storage and to determine the long-term fate of CO2. Traditional reservoir simulation methods will be combined with streamline-based simulation, which will include rate-limited geochemistry, dispersion and phase exchange between hydrocarbon, CO2 and aqueous phases. It will be validated by comparison with conventional grid-based codes. The uncertainty of the location and fate of CO2 will be quantified. The effects of faults on EOR/CO2 injection will be included by incorporating fault rock properties using state-of-the-art software from the University of Leeds. The fault rock properties included in the model will be taken from the extensive North Sea database at University of Leeds.

B2.3 Phase behaviour and injectivity in CO2/EOR processes

Leader Fatosh Gozalpour, Heriot-Watt University

A multiphase compositional phase behaviour model will be developed at Heriot-Watt University to determine the relative amounts and compositions of gas, liquid and solid phases present during CO2 injection. The model will be verified against laboratory measurements. Depending on the reservoir conditions, up to five separate phases can exist in the reservoir:

  • vapour
  • CO2 rich-supercritical fluid (halfway between a liquid and a gas)
  • hydrocarbon-rich liquid
  • aqueous phase
  • solid (asphaltene & hydrate).

It is necessary for a phase behaviour model to handle the mutual solubility of CO2 and hydrocarbons with water, because CO2 solubility in water can be significant. This which will reduce the available CO2 to displace the oil, resulting in a reduction in oil recovery, but will increase CO2 storage. The simulation models will be used by the Applied Geophysics Group at Leeds University to assess when and where best to apply time-lapse seismic to monitor CO2 movement within the specific reservoirs being assessed as potential sites for storage.

B2.4 Economic analysis

Leader: Alex Kemp, University of Aberdeen

The economic aspects of CO2 capture, storage and EOR in oil/gas fields in the UK sector of the North Sea will be assessed by the University of Aberdeen. Estimates of capture and transportation costs to potential North Sea storage and/or EOR fields will be made, in conjunction with the results from other themes and strong links will be developed with theme E (GIS). The financial modelling will estimate the benefits of additional oil production and the deferral of decommissioning of platforms. Calculating the national costs and returns will include the benefit of the value of reduced CO2 emissions and the impact of taxation. The risks and uncertainties involved can conveniently be examined through Monte Carlo techniques. The end result would be estimates of the net present values at various discount rates of a range of potential schemes.

B3 UK offshore & onshore aquifers: injectivity and storage volumes

Leaders: Sam Holloway, British Geological Survey; Stuart Haszeldine, University of Edinburgh

This topic will characterise selected aquifer storage sites, and improve estimates of UK aquifer storage capacity. Outputs and data will input to the economic analysis and integrated assessment. Saline aquifers represent a significant proportion of total UK capacity for geological storage (previous estimates for aquifers are ~70,200MT CO2 compared to ~14,900MT CO2 for hydrocarbon fields). However, unlike hydrocarbon fields, where extensive exploration has produced large datasets, there is much less data available for saline aquifers. Consequently, the accuracy of previous aquifer capacity estimates is much lower than for hydrocarbon fields. The data generated will further populate and improve functionality of an existing UK CO2 storage GIS to create a CO2 Source/Sink Decision Support System (DSS) - see theme E (GIS). The principal goals are to:

  1. Characterize selected potential offshore sites both east and west of the UK, to a level at which their efficacy and storage capacity can be judged and costs of storage can be incorporated meaningfully into wider energy systems analysis. This will include some reservoir quality analyses.
  2. Significantly reduce uncertainty in previous estimates of UK aquifer storage capacity.
  3. Upgrade the existing DSS by entering key datasets of current and planned industrial CO2 sources, potential pipeline routes and sinks, which will be obtained from both outside and inside the project.
  4. Improve GIS functionality to a level at which it can provide meaningful technical, economic, environmental and social information to assess different CCS scenarios.