Overall good progress is being made with the experience gained in both monitoring and modelling from demonstration and pilot projects. There is real progress in streamlining MMV at projects and reducing the costs of monitoring. Several sites have now demonstrated conformance of a modelling-monitoring loop, leading to an improvement in the understanding of this principle.
Key monitoring discussion points:
- The use of fibre-optic distributed acoustic sensors (DAS) at projects, including helical configured cables to overcome the limitations of directional signals.
- Reducing the level (and cost) of monitoring for commercial scale projects compared with the initial research-orientated projects. This is now happening at Shell’s QUEST project in Alberta where the research team are able to streamline their initial modelling, monitoring and verification (MMV) strategy without losing monitoring effectiveness, including the use of a new laser-based low-cost leakage detection technique over the well area.
- This reduced monitoring principle was also studied in the monitoring, reporting and verification (MRV) plan for Occidental’s CO2-EOR project.
- Leakage detection discussions were centred on the temporal and spatial complexity of near surface baselines and the implications for near-surface monitoring, its purpose, optimization and value to stakeholders, and hence the need for attribution methodologies to identify genuine leakage. An example from Japan on a new technique for doing this for offshore leakage was presented.
Key modelling discussion points:
- The complexities and challenges of upscaling from pore to core to reservoir, highlighting the importance of the influence of heterogeneity in the reservoir.
- Modelling flow in wellbores was discussed with several examples showing that it can require a different modelling approach.
- The US DOE’s (Department of Energy) NRAP programme has produced 10 ‘tools’ for reduced-order modelling of CO2 storage, these have been beta-tested and useful feedback was given in a dedicated session.
The effectiveness of CCS as a global solution to carbon emission abatement will depend on widespread deployment in both established industrialised and developing economies. One of the key stages for any country is the identification of a national CO2 storage resource. To help understand the challenges faced by different countries that have either conducted, or are planning such a resource assessment, a survey was commissioned by the UK and Korean governments. The responses to this survey have generated a useful foundation that can aid governments and other organisations who are less advanced in planning CO2 storage assessments. IEAGHG has now produced a guide based on the survey’s findings. It is designed to help government bodies and policy makers with limited CCS experience to identify and select information on assessment methodologies. The guide provides information on where to find the material required to undertake initial national scale storage assessments. The guidance also includes definitions of technical terminology, proposed steps to establishing a national storage assessment and recent up to date case studies from a variety of countries focussing on Africa and Asia. A variety of methods for capacity estimation have been used and this guide provides explanations of where to find these studies and sources of information including websites, papers and organisations. Most companies and organisations engaged in CCS development have stated their ambition to share knowledge and experience; and they actively collaborate at an international level to aid future projects. This guide provides a link with current expertise in CO2 storage to help facilitate new CCS projects especially in developing countries.
It should be stressed that many detailed storage assessments have been conducted and published in the past decade. A wide variety of techniques and technologies have been used to complete them given the varying nature of each country and individual sites. Although a standardised method has yet to be established, this guide aims to provide links to the most developed methodologies providing a direction on the most suitable approach to adopt.
At the conclusion of this guide there is a nine point summary of the key stages that are recommended for the establishment of a national CO2 storage assessment.
CO2 storage has now been tested at a number of demonstration sites around the world, including some depleted oil and gas reservoirs. The use of depleted reservoirs can offer some advantages because the geological characteristics that are pertinent to CO2 storage, such as the distribution of porosity and permeability, have been pre-determined. Although depleted hydrocarbon fields can show strong evidence of fluid retention, there are risks associated with existing wellbores and the possibility of caprock deterioration.
In 2016 IEAGHG published a study reviewing key factors that influence CO2 storage in depleted oil and gas fields based on four detailed examples. Comparisons were made between storage operations in depleted fields (with or without enhanced hydrocarbon recovery) and storage in saline aquifers with the approaches required in modelling, monitoring, reporting, economics, and operational strategies. Four main case studies were chosen; The Goldeneye (UK North Sea), Cranfield (Texas, USA), SACROC (Texas, USA) and Otway (Australia).
- The use of depleted reservoirs for CO2 storage can offer advantages because the geological characteristics that are important to CO2 storage have been pre-determined.
- There is strong evidence for secure containment if a rigorous risk assessment and characterisation has been conducted.
- Evidence from these case studies has shown that CO2 storage does not have a detrimental impact on adjacent oil and gas fields.
- AZMI (Above Zone Monitoring Interval i.e. a formation above the reservoir and caprock) pressure monitoring has proved to be an effective tool for tracking CO2 in heterogeneous and complex reservoirs (e.g. Cranfield). AZMI is an active area of research and development.
- Monitoring approaches should take into consideration the background geochemical reactions in aquifers that might be prone to ingress from brine or CO2 above a storage reservoir. Simplistic approaches may not be effective and could lead to flawed inferences without an adequate understanding of natural variation in groundwater geochemistry.
- Risks associated with increasing pressure are predominantly and most commonly mitigated by keeping pressures below pre-production levels.
- Case study evidence suggests oil and CO2 miscibility might improve storage estimates by up to 3% whereas residual gas and CO2 miscibility could reduce capacity by up to 6%.
- At Goldeneye proprietary CO2-resistant cements could be utilised if they can be shown as superior to ‘normal’ Portland cement but have not yet been thoroughly tested in terms of their compatibility.
- An in depth understanding of potential risks is essential to allow for balanced cost-benefit modifications and improved costs analysis.
Fault zones are widely recognised as being important to the secure long term storage of CO2 as they could provide a leakage pathway out of the target reservoir. Fault characterisation within reservoirs, especially where they extend into caprock, and other overlying formations, needs to be thoroughly understood as part of any risk assessment for CO2 storage. The aim of this study is to review what is known about the permeability of fault zones in order to highlight under what circumstances faults may impact overall storage integrity.
The behaviour of fault zones in relation to sub-surface fluid migration is important to many industries and consequently has been comprehensively documented in the literature. CO2 operations involve the injection and pressurization of reservoirs usually resulting in changes to the state of in-situ stresses which may modify fault properties. Instability could lead to slippage along pre-existing faults or fracture systems, which may be associated with seismicity. In addition, the movement of faults, and the generation of factures within the damage zone adjacent to the core, may create conduits that lead to the leakage of fluids to the surrounding overburden or even to the surface.
In 2015 IEAGHG published a study reviewing the geomechanical stability of faults during pressure build up which provided a helpful background to the behaviour of faults in stress regimes relevant to CO2 storage. This study is designed to build upon the previous work and provide a significantly broader review of the current state of fault zone permeability and also to investigate what mitigation options may be available to CO2 storage operations if leakage was to occur.
CCS requires the secure retention of CO2 in geological formations over 1000’s of years. To achieve this, characterisation of target injection formations, and their structural features including faults, is essential to ensure leakage does not occur.
Faults can either act as barriers to fluids, or as conduits for migration. Consequently, the properties of faults that dissect or form a boundary with potential CO2 reservoirs, need to be determined.
- The significance of faults has long been recognised in the petroleum, mining and geothermal industries, but CO2 storage is less mature and more experience and research related to faults would be beneficial.
- The objective of this study was to review recent research on the permeability (a measure of the ability of rocks to transmit fluids) of faults in CO2 storage, particularly how different geological processes can either cause faults to help retain fluids within a reservoir, or lead to migration along or across faults. It builds upon an earlier study which looked at the role of geomechanical stress on faults.
- There is widespread experience of working with faults and fractures and provided there is sufficient characterisation of their properties they should not restrict storage development.
- If fault zones are present they need to be carefully characterised to ensure the development of an effective containment assessment and to inform the development of operational constraints and monitoring plans.
- A number of mitigation measures have been proposed to counter potential leakage. These include hydraulic barriers, biofilms and reactive cement grout. Changing subsurface pressure has been seen to be effective: there is strong evidence of the reduction in flow of a natural hydrocarbon seep caused by depletion of an offshore oil reservoir hydraulically linked to the seeps.
The use of CO2 for enhanced oil recovery (EOR) is a well established commercial practice in the United States where it has been used for over 40 years. There is widespread potential for CO2-EOR in other mature petroleum producing regions. If CO2-EOR could be implemented it would offer an economic stimulus to develop CO2 storage. There are, however, a number of barriers, not least the installation of infrastructure and modifications that would be necessary to supply CO2 and inject it into target reservoirs. This study has looked at the challenges faced by the prospect of CO2-EOR in three regions: the North Sea; Russia; and the Gulf Cooperation Council (GCC) states which is a regional political organisation comprising Bahrain, Kuwait, Oman, Qatar, Saudi Arabia, and the United Arab Emirates. In addition to the technical challenges the study included two hypothetical examples, one based on the North Sea and the other in a GCC state, to explore what economic conditions would be necessary for CO2-EOR to be implemented. The most significant factor that influences of CO2-EOR uptake is the prevailing price of oil. The injection rate, capital expenditure (CAPEX), operational costs (OPEX) and tax incentives are of secondary importance. Despite the challenges posed by this form of EOR there is growing interest in its use in Saudi Arabia where and Saudi Aramco launched the Uthmaniyah CO2 EOR demonstration project in July 2015. There are also plans for CO2-EOR in China for a potential project offshore Guangdong Province.
- Approximately 95% of all CO2 EOR activity takes place in the U.S., and in 2010, CO2 EOR projects were producing approximately 300,000 barrels of oil per day, close to 4% of total U.S. oil production. To achieve this quantity of oil, approximately 60Mt of CO2, is injected annually into oil fields.
- Investment in CO2 EOR is highly constrained by the volatility of the price of oil. For EOR projects to remain profitable over their operational life the cost of supplied CO2 supplied needs to fluctuate.
- Offshore production relies on fewer deviated wells with less spatial coverage of producing areas which is less advantageous for CO2 EOR compared with onshore 5 or 9 spot closely-spaced injection and production well configurations commonly used in North America. This configuration provides a higher density and control for EOR operations.
- Experience with CO2 EOR shows that the projected incremental recovery ranges from 7% to 23% of Original Oil in Place (OOIP). Estimates for CO2 EOR recovery rates for the North Sea range from 4 – 18%.
- Based on previous estimates of suitable fields, and a 3 barrel/tonne of CO2 recovery rate, the estimated incremental oil potential for the Norwegian sector could be 3,535 M barrels that would require 1,180 M tonnes of CO2. In the UK sector an additional 2,520 M barrels could be recovered with 840 M tonnes of CO2.
- The main factors that currently inhibit investment in offshore CO2 EOR are the upfront investment costs, loss of oil production during work-overs and lack of significant CO2 volumes.
A study recently completed for the Carbon Sequestration Leadership Forum (CSLF) has just been published. This review was undertaken by the CO2 Storage team of the British Geological Survey (BGS) on behalf of UK Department of Energy and Climate Change and the Korean Clean Energy Ministry who jointly funded the work. The project was managed by the IEAGHG.
BGS conducted a survey of several countries to establish the level of national CO2 storage assessment that has been achieved. All of the 15 countries who responded had completed national CSLF-methodology ‘theoretical’ storage capacity assessments. These initial estimates were sufficient to allow policymakers to make informed decisions about priorities for follow-up actions. The most commonly reported barriers to progressing national assessments of CO2 storage capacity were:
- Data availability, either due to sparsity or absence of data, or data that is available but proprietary and so inaccessible.
- Data quality, often due to the age of the available data.
- Lack of industrial support.
- Absence of political and regulatory support.
Methodologies for estimating storage capacity varied widely in approach and showed continuous development in terms of sophistication and techniques. Significant challenges have been created in some countries by undertaking partial assessments using widely differing methodologies which prevented assessments from being made for the country as a whole.
The survey did illuminated areas where improvements or initiatives could improve storage estimates. Several key recommendations have been proposed including: increasing levels of assessment detail in a step-wise manner, with appropriate decision points; where storage potential exists, policy support should ensure that there is a long-term vision for reducing greenhouse gas emissions which may include deployment of CCS; and the creation of a national body to drive CCS forward.
National assessments have been achieved in a few countries relatively rapidly by using publically available data collated in national data repositories. Most countries take between five to ten years. Efficient progress tends to occur when national or regional geological survey organisations are involved. Access to relevant data, often related to hydrocarbon exploration and development has also facilitated storage estimates.
Developing a strategy for prioritisation of the most favourable sites has been identified as a crucial step in developing a targeted and efficient approach to storage assessments. Clarity on uncertainties that remain in the data is also critical to the assessment. The study recommended that the establishment of a national-level database of potential sites is a good stepping-stone to detailed site surveys and flow simulations. This approach helps to identify ‘sweet spots’ for potential storage operators. Simple volumetric estimates are a strong first stage in a national storage assessment. Flow simulations providing dynamic capacity estimates are needed to fully understand the potential CO2 storage capacity. New data will almost certainly be required to meet this increased level of understanding. However, the lack of modern data should not prevent storage assessments from being undertaken. Legacy data can be used to provide an adequate national assessment and highlight areas where new data should be acquired.
Leading countries in the field of national assessments such as the USA, Norway and the UK have expertise not only in the ability to produce these assessments but also the data management that will be necessary. International co-operation built on this experience is an obvious route to improve and enhance national assessments.
Many regions of the world with offshore continental shelf areas offer significant potential for large-scale CO2 storage. These regions often have depleted oil and gas fields, deep saline aquifers or other permeable formations which are suitable for injected CO2. The gas must be safely stored and retained within predefined reservoirs but should any seepages occur they need to be detected so that mitigation measures can be implemented. It is also important to be able to verify the pattern of CO2 migration within reservoirs by comparison with predictive models. IEAGHG contracted a consortium of leading UK research institutes, led by the British Geological Survey, to review monitoring techniques currently available for CO2 geological storage. The National Oceanography Centre, Plymouth Marine Laboratory, and the University of Southampton added their expertise to the study.
A range of monitoring techniques are available for CO2 geological storage offshore, both deep-focussed (providing surveillance of the reservoir and deeper overburden) and shallow-focussed (providing surveillance of the near seabed, seabed and water-column). Deep-focussed operational monitoring systems have been deployed for a number of years at the offshore Norwegian storage sites Sleipner and Snøhvit. The efficacy of key technologies are starting to emerge. Research based on 3D seismic surveys have been highly effective for tracking CO2 plume development in Sleipner and Snøhvit reservoirs. In the Snøhvit field a combination of 3D seismic and downhole pressure / temperature measurments at Snøhvit has demonstrated the benefit of complementary techniques. This monitoring programme led to a switch in the injection strategy into an alternative reservoir. Assessment of the results from both deep-focussed and shallow-focussed monitoring activities from Sleipner and Snøhvit indicates that many elements of the European storage requirements have been met at these large-scale sites which were both initiated before the CCS Directive was introduced.
Shallow-focussed monitoring systems are being developed and demonstrated. New marine sensor and existing underwater platform technology such as Automated Underwater Vehicles (AUVs) and mini-Remotely Operated Vehicles (Mini-ROVs) enable deployment and observation over large areas at potentially relatively low cost. Seafloor and ocean monitoring technologies can detect both dissolved phase CO2 and precursor fluids (using chemical analysis) and gas phase CO2.
Controlled release experimental sites such as QICS (Quantifying and Monitoring Potential Ecosystem Impacts of Geological Carbon Storage) have proved to be useful test-beds for shallow seismic techniques and acoustic detection systems. They can also reveal how CO2 migrates through, and is partially retained by, unconsolidated sediments.
Developments in geophysical techniques, such as the P-Cable seismic system, have generated higher resolution 3D images of the overburden. Successful integration of these shallow subsurface technologies, with the seabed monitoring data, can help to build a better understanding of shallow migration processes. Search areas could be narrowed down by the integration of information from deeper-focussed monitoring such as 3D seismics, which can identify migration pathways, with shallow surface monitoring such as acoustic detection.There has been significant progress in demonstrating monitoring of offshore CO2 geological storage sites, and this report compiles and reviews the developments to-date. The report reference is, “Review of Offshore Monitoring for CCS Project, 2015/05, July, 2015”.
Image 1: Remotely operated underwater vehicle (ROV) (courtesy of Statoil ASA).
Image 2: Schematic of the QICS experiment (copyright Plymouth Marine Laboratory)
Faults are known to act as low permeability sealing zones but can also act as conduits allowing the flow of fluids across and up the structure. This project was commissioned to review fault properties and how they might be influenced by fluids including CO2 in solution. The report explains the significance of fault structures, the nature of deformation and how this influences permeability. It also reviews classic and some experimental methods to assess fault properties.
Reactivation of faults can be assessed using both analytical and numerical approaches, but assessment is usually based on the Mohr-Coulomb failure criterion. This method can be used to determine the critical injection pressure. Numerical modelling can provide predictions of fault stability at different scales and incorporate different parameters such as the geometry of different faults. Numerical methods can be effective for identifying leakage potential and seal failure especially where dilatancy and stress dependent permeability changes occur.
Experimental tests on minerals and rock samples exposed to CO2 tentatively indicate that the coefficient of friction is not radically changed, however, this conclusion is based on limited exposure to CO2.
There is limited observational data on stress regimes and direct pore pressure measurements from core samples from cap rocks and fault zones. Acquisition of key data can enhance stress regime modelling and fault behavior. The next stage of research is to review real fault permeability through reservoir formations and cap rocks. A new study will be commissioned during 2015.
Carbon capture and storage (CCS) has the potential to significantly contribute to greenhouse gas emissions reductions. In this regard, development of cluster structures offers the potential for cost reduction through sharing of infrastructure and organisational and regulatory efforts.
The main objectives of this study are to identify gaps, risks and challenges related to CCS clusters, to compare their business models and to reveal factors for successful development and suitable locations for future clusters.
The approach for this work consists of an extensive review of the literature on CCS clusters. The existing information was sufficient to review 12 clusters with different levels of maturity in detail and to discuss a number of others at a more general level.
Based on an analysis of gaps, risks and challenges of clusters (both technical and commercial), the study develops criteria for the selection of future cluster locations and recommendations for increasing the likelihood of successful cluster implementation.
Following are the key messages from the report:
- The most successful clusters remain those based on the use of CO2 for enhanced oil recovery (EOR) application in the US.
- Clustering may slightly reduce costs but the savings are insufficient to fill the cost-revenue gap, so clusters will likely require substantial, i.e. 50% or more, government support. There is large value in the (shared) pre-investment in pipelines and storage in order to generate the confidence needed for investment decisions on capture facilities. Further cost savings can arise from sharing organisational costs and from tying specialist services.
- The main risks for clusters are of commercial nature and include e.g. collapse of the CO2 price, loss of key partners and/or customers, availability of low-cost alternative EOR methods but also major pipeline accident and failure to gain permits.
- A major obstacle in early years is maintaining a core organisation which is able to carry a CCS cluster project forwards.
- new methods to attract international investment in CCS capacity are necessary to exploit the full low cost potential of the best cluster locations.
- Promising future cluster locations include e.g. Mexico, Indonesia, Russia, former Soviet Union states and China.
- Workshops could help exploring more systematic development of business plans for CCS clusters with emphasis on customers and revenues.
The Report documents the experience of 45 test injection projects from around the world, ranging in scale from a few hundred tonnes of CO2 to approximately 70,000 tonnes, with the objective of assisting countries or organisations wishing to embark on their first CO2 injection test. The majority of small scale projects have been undertaken in North America, with Australia and Japan, China and the European Union each having undertaken one or two small scale projects. Half of the projects are based on injection into sandstone reservoirs, although a significant 28% involve injection into coals. Only two test sites injected into basalt, the rest were carbonate reservoirs. Most projects injected less than 10,000 tonnes of CO2, with less than one-quarter of the projects injecting more than 10,000 tonnes. The depth of injection ranges from approximately 300m to over 4,000m but averages around 1,200m. The time taken from making the preliminary decision to undertake a project to injection of the first molecule of CO2 is variable but averages approximately three years.
Data sheets were compiled for each of the projects and a comprehensive summary database was developed as a prelude to the analysis of the similarities and differences between projects. A generic (industry-type) flow chart shows the development path that many projects have adopted, commencing with the development of the concept to final completion.
These small scale projects were undertaken for a variety of reasons. First and foremost they have provided valuable real world experience of CCS operations, to industry, government and researchers at a modest cost. They also provide an opportunity for stakeholders, including the broader community, NGOs and other interested groups to be able to visit projects and see operations at first hand. These demonstration projects provide clear evidence that governments and industry are pro-actively implementing measures to decrease CO2 emissions. They also provide opportunities to test new technologies, for example the detection of leakage, and to develop modelling capabilities.
Reservoir simulations are an important element of these injection pilots. They are used to design injection tests, predict plume and pressure behaviour and design an appropriate monitoring and verification scheme. Simulations can build confidence in the CO2 storage process by demonstrating that projects are thoroughly researched, well designed, and properly operated. In most published cases, the models provided a reasonable simulation of the CO2 storage process, particularly in the prediction of the pressure response during injection.
The report includes details of monitoring at different sites. Monitoring techniques are used primarily to monitor the pattern and progress of injected CO2 and identify any unexpected events that were recognised in a risk assessment. Deep saline aquifer storage more commonly utilises geophysical techniques, particularly seismic, to understand the areal distribution of the injected CO2. In cases where storage has been tested in depleted hydrocarbon fields, enhanced oil recovery (EOR) and enhanced coal bed methane (ECBM) sites, there is a much greater degree of understanding of geological conditions and most projects that fall into this category did not require extensive additional monitoring techniques. Geochemical monitoring was the dominant type of technique used to understand the performance of CO2 in depleted hydrocarbon fields or its behaviour in enhanced recovery processes (EOR and ECBM).
This valuable catalogue of small-scale test sites has revealed the extent of technology development and research related to CO2 injection and monitoring. These demonstration projects not only show that CO2 storage can be successfully achieved but they also lay the foundation for full-scale commercial CCS across the world.