CO CAPTURE AND STORAGE IN THE EU EMISSION TRADING …

CO2 CAPTURE AND STORAGE IN THE EU EMISSION TRADING SCHEME MONITORING AND REPORTING GUIDELINES FOR INCLUSION VIA ARTICLE 24 OF THE EU ETS DIRECTIVE

Report No. R312 BERR/Pub URN 07/1634

NOVEMBER 2007

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by Paul Zakkour Environmental Resources Management 8 Cavendish Square London W1G 0ER UK Tel: +44 (0) 20 7465 7200 Fax: +44 (0) 20 7465 7272

First published 2007 © Crown copyright 2007

The work described in this report was carried out under contract as part of the BERR Carbon Abatement Technologies Programme. The programme is managed by AEA Energy & Environment. The views and judgements expressed in this report are those of the contractor and do not necessarily reflect those of the BERR or AEA Energy &

Environment.

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CONTENTS

1. INTRODUCTION 1

1.1 Background to CCS Operations 1

1.2 Background to CCS in Emissions Trading 2

1.2.1 The International Emissions Trading Context 2

1.2.2 Background To The Treatment Of CCS In The EU ETS 6

1.2.3 Treatment Of CCS In Phase I Of The EU ETS 6

1.2.4 More Recent Developments 7

1.2.5 Rules For Inclusion Under Article 24 Of The EU ETS 8

1.2.6 The Need To Update The MRG’s For CCS 9

1.3 Aims, Objectives and Scope 9

1.4 Structure 10

2. DEVELOPING AN ACTIVITY OR INSTALLATION DEFINITION 11

2.1 Overview 11

2.2 Issues To Consider For CCS In The EU ETS Via Article 24 11

2.3 Defining Installation Boundaries For The Opt-In Under Article 24 12

2.4 Proposed Activity Definition For The Article 24 Opt-In 13

2.5 Modalities For The Opt-In and For Phase III 13

2.6 Considerations In The Context Of Broader Regulatory Developments 14

2.6.1 Recognising Non-Emissions From CCS In The EU ETS 14

2.6.2 Developing CCS Legislation In The European Union 14

3. DEVELOPING ACTIVITY/INSTALLATION SPECIFIC MONITORING AND REPORTING

GUIDELINES 15

3.1 Overview 15

3.2 General Issues To Consider For Including CCS In The EU ETS 15

3.2.1 Types Of Emission Included In The EU ETS 15

3.2.2 New Criteria For De-minimis and Minor Source Streams 16

3.2.3 Rules For Modifying Monitoring Methodologies 17

3.2.4 Cost Effectiveness Considerations 17

3.2.5 Approaches To Emissions Methodologies 18

3.2.6 Tiers Of Approaches 19

3.2.7 Information Requirements Of A Monitoring Plan 19

3.3 [1.] Guidelines For CO2 Capture 20

3.4 [2.] Activity Specific Guidelines For CO2 Transport 22

3.5 [3.] Activity Specific Guidelines For CO2 Injection and Storage 24

3.6 [4.] Enhanced Oil Recovery Projects Using Captured CO2 36

APPENDIX A : EMISSIONS SOURCES IN CCS PROJECTS 39

APPENDIX B : BIOMASS AND CCS 51

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1. INTRODUCTION This report has been prepared by Environmental Resources Management (ERM), over the period October 2006 to November 2007. The report outlines guidelines for monitoring and reporting of emissions from carbon dioxide (CO2) capture and storage (CCS) under the EU Emissions Trading Scheme (EU ETS)(1)(2). It has been completed for – and working in conjunction with – the UK Department for Business, Enterprise and Regulatory Reform (BERR) and the UK Department for Environment Food and Rural Affairs (Defra). Contributions in-kind were also received from BP in respect of certain specific issues posed by the Peterhead-Miller project, and elements therein regarding the enhanced oil recovery element of that project(3). Discussions and positions of various other key stakeholders in the project have also been considered, including the European Commission – DG Environment, Defra legal service, the European ad hoc group of CCS experts formed in 2004 specifically to consider CCS in the EU ETS(4), the UK Emissions Trading Group, and the CCS working group of the International Emissions Trading Association (IETA). The work represents part of ongoing efforts by the UK Government to create an enabling legal framework for CCS projects in the UK and the European Union. In particular the UK Government is committed to this effort as part of the support for proposed CCS projects that could be operational before the end of the EU ETS Phase II in 2012.

1.1 Background to CCS Operations In order to maintain the focus of this report, a comprehensive review of CCS technologies is not presented here. Useful background information can be found in a number of sources, such as:

• the Intergovernmental Panel on Climate Changes (IPCC) Special Report on Carbon Dioxide Capture and Storage (SRCCS) (5);

• publications from the IEA Greenhouse Gas Research & Development Programme;

• The BERR report: Developing Monitoring, Reporting and Verification Guidelines for CO2 Capture and Storage in the EU ETS (6).

• The 2006 IPCC Guidelines for National Greenhouse Gas Inventories, in particular Chapter 5, Volume 2 relating to Carbon Dioxide Transport, Injection and Geological Storage (7); and,

• Carbon Dioxide Capture and Storage in the Clean Development Mechanism published by the IEA GHG R&D Programme (8).

A summary of CCS technologies, potential and outlooks is provided below (Box 1.1).

(1) As laid out in Directive 2003/87/EC establishing a scheme for greenhouse gas emission allowance trading within the Community and amending Council Directive 96/61/EC.

(2) This report only considers geological storage of CO2, but not oceanic storage ie storage of CO2 directly in the water column. (3) The Peterhead-Miller project was subsequently suspended by BP, as of May 2007. (4) The BERR ad hoc group consists of around 30 experts made up from representatives of Member State government’s, European Commission, industry and academia with associated interests in carbon dioxide capture and storage. (5) 2006 IPCC Special Report on Carbon Dioxide Capture and Storage. Cambridge University Press. (6) DTI 2005. Developing Monitoring, Reporting and Verification Guidelines for CO2 Capture and Storage Under the EU ETS. Report

No. Coal R277, DTI/ Pub 05/583, prepared by ERM and DNV. (7 )IPCC 2006, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Prepared by the National

Greenhouse Gas Inventories Programme, Eggleston H.S., Buendia L., Miwa K., Ngara T. and Tanabe K. (eds).

Published: IGES, Japan. Available at: http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.htm. (8) Carbon Dioxide Capture and Storage in the Clean Development Mechanism Prepared by Zakkour, P. D., Cook, G, Solsbery, H.L,

Heidug, W. Marsh, P, and Garnett, A. ERM Ltd. Report Number 2007/TR2. IEA Greenhouse Gas R&D Programme, Cheltenahm, 2007

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1.2 Background to CCS in Emissions Trading 1.2.1 The International Emissions Trading Context

Parties to the United Nations Framework Convention on Climate Change (UNFCCC) are obliged to publish national inventories of anthropogenic emissions by sources and removals by sinks of greenhouse gases. These must be reported in accordance with IPCC National Greenhouse Gas Inventory Guidelines. Under the Kyoto Protocol to the UNFCCC, ratifying Parties with binding greenhouse gas reduction targets may trade in assigned amounts under the Protocol in order to meet their reduction targets (under Article 17). The accounting regime for monitoring and reporting compliance under the Protocol – and thus for International Emissions Trading under Article 17 – are the 1996 IPCC National Greenhouse Gas Inventory Guidelines, and the 2000 IPCC Good Practice Guidelines. Neither the 1996 or 2000 guidelines contain inventory methodologies for CCS activities. As such, there has been an absence of clarity on accounting rules for injected CO2 in national inventories. Consequently, Norway has reported CO2 injected in Sleipner as a memo item in its national inventory; the US has not reported injected CO2 as non-emitted in its national inventory.

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Box 1.1 Overview of CCS Technologies Notwithstanding this issue, the IPCC more recently published the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (the 2006 IPCC GLs), which do contain accounting procedures for CCS. These guidelines should form the basis for any emission accounting regime within Annex I countries upon approval by Government Parties (9), based on the following requirement:

Where CO2 emissions are captured from industrial processes or large combustion sources, emissions should be allocated to the sector generating the CO2 unless it can be shown that the CO2 is stored in properly monitored geological storage sites as set out in Chapter 5 of Volume 2 (10).

(9) This is presently outstanding and will not occur before 2009. (10) Volume 1, Section 8.2.1, pg 8.5.

CCS is a process consisting of the separation of CO2 from industrial and energy-related sources, transport to a storage location and long-term isolation from the atmosphere. Methods of CO2 capture include:

• Post-combustion capture, where the CO2 from flue gases exiting combustion or process plant is captured using solvent absorption technologies;

• Pre-combustion capture, where a syngas is generated using a steam reformer, which is then split into H2 and CO2 using solvent-based capture technologies; and,

• Oxyfuel combustion processes, where a relatively pure CO2 stream exits the combustion process, which can be directly compressed for transport and storage purposes with a minimum level of treatment;

Transportation in pipelines is the only likely cost-effective means of transporting the large volumes of CO2 associated with industrial scale CCS operations. Potential storage sites include:

• Depleted oil and gas reservoirs

• Operational oil and gas reservoirs

• Saline formations (deep brine bearing geological strata)

• Coal seams CCS is considered as an option in the portfolio of mitigation actions for stabilisation of atmospheric greenhouse gas (GHG) concentrations. The IPCC SRCCS concluded that: Available evidence suggests that, worldwide, it is likely there is a technical potential of at least about 2,000 GtCO2 of storage capacity in geological formations. In most scenarios for stabilization of atmospheric GHG concentrations between 450 and 750 ppmv CO2…CCS contributes 15-55% to the cumulative mitigation effort worldwide until 2100. The IPCC also conclude that: With appropriate site selection based on available sub-surface information, a monitoring program to detect problems, a regulatory system and the appropriate use of remediation methods to stop or control CO2 releases if they arise, the local health, safety and environment risks of geological storage would be comparable to the risks of current activities such as natural gas storage, enhanced oil recovery and deep underground disposal of acid gas. Observations from engineered and natural analogues as well as models suggest that the fraction retained in appropriately selected and managed geological reservoirs is very likely to exceed 99% over 100 years and likely to exceed 99% over 1,000 years. As such, CCS technologies should be considered as a key tool in the portfolio of climate change mitigation technologies available in the first part of the 21

st century.

CCS is a technology which reduces emissions at source, and thus abating emissions from entering the atmosphere and contributing towards climate change. Its recognition in the EU ETS should be on the basis that emission reductions from CCS are real, measurable and verifiable in a complete, consistent and transparent way.

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This implicitly means that non-emissions from source installations can only be claimed by national governments in their greenhouse gas inventories if they are enforcing the monitoring and reporting obligations outlined therein. Therefore, it follows on that these should form the basis for accounting for emissions from CO2 storage within the EU ETS. 2006 IPCC Guidelines for National Greenhouse Gas Inventories (Vol 2, Ch 5) The 2006 IPCC GLs, Volume 2, Chapter 5 on Carbon Dioxide Transport, Injection and Storage indicate that:

…the time of writing, the small number of monitored storage sites means that there is insufficient empirical evidence to produce emission factors that could be applied to geological storage reservoirs (11) .

It goes on to state that:

The suitability and efficacy of [different] monitoring technologies can be strongly influenced by the geology and potential emission pathways at individual storage sites, so the choice of individual monitoring requirements will need to be made on a site-by-site basis.

Consequently, the document advocates the use of a Tier 3 (12) (ie project specific monitoring) emissions monitoring process, with the objective:

…to support not only zero emissions estimates but also to detect leakage, even at low levels, if it occurs (13).

Within the 2006 IPCC GLs, a schematic is presented outlining the monitoring procedure for determining storage site emissions on a project-specific basis (Figure 1.1).

(11) Page 5.13 (12) The IPCC employs three tiers of reporting levels. Higher Tiers indicate increasing levels of accuracy in the data generated. Tier 1

generally involves the application of basic default emission factors at a national level. Tier 2 follows similar principles, would require

emissions factors to be adjusted to fit national circumstances. Tier 3 involves direct monitoring of emissions from each relevant source

category reported in national inventories. (13) Volume 2, Section 5.7.2. pg 5.17.

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Figure 1.1. Monitoring procedure - 2006 IPCC GHG guidelines The process outlined involves the development of an assurance-based scheme to demonstrate good storage site selection, evaluation of risks of containment loss, demonstration of a bespoke (or “adequate”) monitoring plan, adaptive learning principles, and monitoring and reporting. As such, it creates a de facto approvals process for appropriate CO2 storage site selection, risk assessment, and monitoring design, and thus the basis for claiming non-emissions as described above. The 2006 IPCC GLs provide further details on the series of methodological steps that need to be undertaken in compiling the inventory, including: 1. Identify and document all geological storage operations in the jurisdiction 2. Determine whether an adequate geological site characterization report has been produced for

each storage site, including: a. Identify and characterise potential leakage pathways such as faults and pre-existing

wells b. Quantify the hydrogeological properties of the storage system c. Include enough data to compile a geological Earth model of the site and surrounding

zone

3. Determine whether the operator has assessed the potential for leakage at the storage site, including:

a. Including likely timing and flux of any fugitive emissions b. Demonstration that leakage is not expected c. Short-term simulations to predict site behaviour during and beyond the injection

(decades) d. Long-term simulations to predict the fate of CO2 over centuries to millennia e. Sensitivity analysis f. Design of the monitoring programme

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g. Update with new data and operational changes

4. Determine whether each site has a suitable monitoring plan. This includes: a. Measurement of background fluxes at the storage site and potential emission points in

the surrounding zone b. Continuous measurement of the mass of CO2 injected c. Monitoring to determine emission from the injection system d. Monitoring to measure fluxes through the seabed or ground surface, including wells and

springs e. Post injection monitoring f. Incorporation of improved monitoring techniques g. Periodic verification

5. Collect and verify annual emissions from each site (and perform history matching). The procedures outlined under Step 4 provides an international standard by which storage site monitoring methodologies should be developed. In terms of operationalising the 2006 IPCC GLs, efforts were undertaken during 2006 to develop these in guidelines for the Clean Development Mechanism (CDM) project-based emissions trading scheme (14). This work developed the high-level IPCC procedure into a formalised methodological approach which can be applied to a specific storage site in order to arrive at an appropriate monitoring plan. Given that governments may only record non-emitted CO2 in their national inventories for CCS if it can be shown that the CO2 is stored in properly monitored geological storage sites as set out in Chapter 5 of Volume 2, then these must form the basis for monitoring and reporting emissions from CCS in the EU ETS. The work undertaken for the CDM, therefore, is used in this report as the basis for developing monitoring and reporting guidelines for storage sites in the EU ETS, as outlined below (Section 3.5). 1.2.2 Background To The Treatment Of CCS In The EU ETS

The key criterion for including CCS operations in the EU ETS is that captured and transferred CO2 from qualifying installations in the scheme to CO2 storage sites is recognised and counted as CO2 that is not emitted (and subsequently therefore absolves the obligation on the installation operator to surrender EUAs equal to the amount not emitted – in exactly same way as described above for the 2006 IPCC GLs). In order for this to be achieved, appropriate monitoring and reporting guidelines need to be approved which can establish a “chain of custody” for the CO2 from source to storage, providing the basis for accounting of any emissions of the captured CO2 across the CCS chain, and subsequent allocation of the responsibility to make such emissions. In the absence of such guidelines, captured CO2 could simply be exported off-site from the installation and vented elsewhere, ultimately impacting on the environmental integrity of the scheme. 1.2.3 Treatment Of CCS In Phase I Of The EU ETS

In January 2004, the European Commission (EC) published guidelines for monitoring and reporting of greenhouse gas emissions from qualifying installations in the EU ETS (15) (MRGs). No specific guidance was provided in the MRGs for monitoring and reporting of potential emissions from CCS,

(14) IEA Greenhouse Gas R&D Programme. Carbon Dioxide Capture and Storage in the Clean Development Mechanism: Possible

Approaches to CDM Methodology Issues. ERM/Shell, April 2007. (15) Decision 2004/156/EC establishing guidelines for monitoring and reporting of greenhouse gas emissions pursuant to Directive

2003/87/EC (the EU ETS).

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although Member States were invited to submit proposals for interim MRGs for consideration by the Commission (Box 1.2).

Box 1.2. Key Text From Decision 2004/156/EC In response, in 2004 the UK DTI commissioned ERM and DNV to develop monitoring and reporting guidelines under the guidance of an ad hoc group of experts, based on this remit (16). These guidelines suggested that a yet-to-be established permitting regime for transport and storage could provide the basis for creating a chain of custody for the CO2 from capture to storage. Under such a regime, the permit would require transport and storage site operators to monitor and report any emissions across the chain from transport and injection back to the exporting installations, who would then have to reconcile these against the amount debited as transferred offsite. For storage sites, the guidelines proposed that the permitting regime would lay down requirements for the operator to make good any emissions from leaking storage sites by purchasing fungible emissions trading commodities (EU Allowances [EUAs], Certified Emission Reductions or Emission Reduction Units) equal to any monitored and reported emissions from the storage site; this would absolve liability on the exporting installation operator to surrender EUAs equal to any amounts leaked from the storage site, and place the obligation directly on the operator responsible for storing CO2. This consideration was essential in order to account for the potential temporal disconnect between when the CO2 was captured and the point in time when it may be re-emitted from the storage site (see Appendix A).

1.2.4 More Recent Developments

In early 2006 the EC began a stakeholder driven process – via the European Climate Change Programme Work Group III (ECCP WGIII) – to assess the role of CCS in meeting EU climate change mitigation commitments. The Group recommended that recognition of CCS in the EU ETS was an important need in facilitating deployment of the technology (17). In parallel, the EC undertook work to refine the MRG for application in Phase II of the EU ETS, based on the experience acquired during Phase I. Subsequently, the Commission published

(16) DTI 2005. Developing Monitoring, Reporting and Verification Guidelines for CO2 Capture and Storage Under the EU ETS. op cit. (17) Final Report of Working Group III: Carbon Capture and Geological Storage. The 2nd European Climate Change Programme. 1st

June 2006

4.2.2.1.3 CO2 capture and storage The Commission is stimulating research into the capture and storage of CO2. This research will be important for the development and adoption of guidelines on the monitoring and reporting of CO2 capture and storage, where covered under the Directive, in accordance with the procedure referred to in Article 23(2) of the Directive. Such guidelines will take into account the methodologies developed under the UNFCCC. Member States interested in the development of such guidelines are invited to submit their research findings to the Commission in order to promote the timely adoption of such guidelines. Before such guidelines are adopted, Member States may submit to the Commission interim guidelines for the monitoring and reporting of the capture and storage of CO2 where covered under the Directive. Subject to the approval of the Commission, in accordance with the procedures referred to in Article 23(2) of the Directive, the capture and storage of CO2 may be subtracted from the calculated level of emissions from installations covered under the Directive in accordance with those interim guidelines.

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Decision 2007/589/EC (18) document outlining MRGs for application in Phase II. In this Decision, the previous route for inclusion of CCS in the EU ETS outlined in Section 4.2.2.1.3 (Box 1.2) had been replaced in preference for inclusion of CCS in the EU ETS via Article 24 of the EU ETS Directive (Box 1.3).

Box 1.3. Key text of the preamble of Decision 2007/589/EC 1.2.5 Rules For Inclusion Under Article 24 Of The EU ETS

Article 24 outlines the rules and procedures by which Member States may unilaterally include other activities, installations or greenhouse gases in addition to those listed in Annex I of the Directive from 2008 ie for Phase II of the EU ETS.

Box 1.4. Key elements of Article 24 of the EU ETS Directive Thus, in order for CCS to be included in the EU ETS, the UK Government will need to:

• State its intention to include CCS operations in its Phase II National Allocation Plan (NAP): This has been undertaken as outlined in Section 4.3.2 of the UK’s draft NAP (19). In addition, Defra wrote to Commissioner Dimas stating its intention to opt-in BP/Scottish & Southern Energy’s Peterhead-Miller (DF1) project, and potentially other CCS projects within Phase II (20);

• Define the activity/installation type that it wishes to opt-in: this will form the legal basis for the inclusion of CCS operations, and define the subsequent scope of the MRGs;

(18) Commission Decision of 18 July 2007 2007/589/EC establishing guidelines for the monitoring and reporting of greenhouse gas

emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council (notified under document number C(2007)

3416) Available at:: http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32007D0589:EN:NOT

(19) See: Defra (2007) EU Emissions Trading Scheme: Approved Phase II National Allocation Plan 2008-2012. Available at:

http://www.defra.gov.uk/environment/climatechange/trading/eu/phase2/pdf/nap-phase2.pdf (accessed April 2007)

(20) Letter from Ian Pearson, UK Environment & Climate Change Minister to Commissioner Stavros Dimas. Unpublished. Although the

DF1 project was cancelled in May 2007.

Paragraph 24 of the preamble (24) Recognition of activities relating to carbon capture and storage is not provided for in this Decision, but will depend on an amendment of Directive 2003/87/EC or by the inclusion of those activities pursuant to Article 24 of that Directive.

Procedures for unilateral inclusion of additional activities and gases 1. From 2008, Member States may apply emission allowance trading in accordance with this Directive to activities, installations and greenhouse gases which are not listed in Annex I, provided that inclusion of such activities, installations and greenhouse gases is approved by the Commission in accordance with the procedure referred to in Article 23(2) [the comitology procedure], taking into account all relevant criteria, in particular effects on the internal market, potential distortions of competition, the environmental integrity of the scheme and reliability of the planned monitoring and reporting system. […] 2. Allocations made to installations carrying out such activities shall be specified in the national allocation plan referred to in Article 9. 3. The Commission may, on its own initiative, or shall, on request by a Member State, adopt monitoring and reporting guidelines for emissions from activities, installations and greenhouse gases which are not listed in Annex I in accordance with the procedure referred to in Article 23(2), if monitoring and reporting of these emissions can be carried out with sufficient accuracy. 4. In the event that such measures are introduced, reviews carried out pursuant to Article 30 shall also consider whether Annex I should be amended to include emissions from these activities in a harmonised way throughout the Community.

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• Define the activity/installation type monitoring and reporting guidelines: based on the activity definition(s) developed above;

• Evaluate and outline any potential effects on the internal market: None are presently envisaged. Such effects will be examined by the EC as part of the Impact Assessment of the ongoing CCS policy development process;

• Evaluate and outline any potential distortions of competition: This is also unlikely, and this will largely be determined by the CCS policy developed by the Commission;

• State any potential effects the proposal could have on the environmental integrity of the scheme: Impacts on the environmental integrity of the scheme arising from CCS projects will be largely dependent on the efficacy of the attendant monitoring and reporting guidelines in so much as these define the boundaries within which emission sources must be monitored, in their efficacy to detect potential emissions of CO2 across the CCS chain, and how responsibility for making good those emission is allocated.

• Develop monitoring and reporting guidelines applicable to the installation/activity type(s) opted-in. This is the main focus of this report.

Precise modalities for inclusion of CCS projects in the UK in respect of allocation, opt-out (for incumbents, assuming that site would be closed for a time to retrofit the CO2 capture equipment) and subsequent re-opt-in of incumbents (perhaps under a new installation category), permit arrangements etc will also need to be elaborated. 1.2.6 The Need To Update The MRG’s For CCS

Although the previous work by ERM and DNV outlined MRGs applicable for CCS, the modalities presented in that study were based upon the transfer provisions laid down in the Phase I MRGs (Decision 2004/156/EC). Based on the permitting approach outlined in this study, the need to elaborate MRGs for the storage site was excluded. However, thinking on this matter has moved on since that time, and alternative approaches are under consideration for regulating pipelines and storage sites, based around their inclusion in the EU ETS. Given the new route for inclusion via Article 24, appropriate MRGs need to be elaborated to cover all parts of the CCS chain including CO2 storage sites. 1.3 Aims, Objectives and Scope The aim of this report is to outline appropriate monitoring and reporting guidelines applicable to CCS activities via the Article 24 opt-in route. It also includes consideration of specific monitoring and reporting issues presented by storage sites and enhanced oil recovery (EOR) operations, which were absent from the previous study. In order to achieve this aim, the report objectives are:

• To outline the activity/installation definition(s) that may be opted-in under Article 24 of the ETS Directive;

• To identify general issues posed by CCS to the application of Decision 2007/589/EC;

• To defines activity/installation monitoring and reporting guidelines for all elements of a CCS operation, including EOR;

The document does not:

• provide monitoring and reporting guidelines applicable to a specific installation. These must be developed based on the methodological approach outlined herein.

• provide any indicative assessments of the overall precision of the methodologies outlined, as many of the technologies outlined herein are novel in nature. These will need to be determined on a case by case basis when applying the methodology outlined.

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The report draws on the findings of previous research undertaken on this subject by ERM and DNV (21), and the reader is advised to read this report in conjunction with the findings presented here. 1.4 Structure The report is structured in the following way:

• Section 2 – outlines possible options for an activity/installation definition that may be opted-in under Article 24 of the ETS Directive;

• Section 3 – outlines activity/installation specific guidelines, based on the definition outlined in Section 2;

• Appendices – consider other issues posed by the modalities for inclusion of CCS in the EU ETS.

(21) DTI 2005. Developing Monitoring, Reporting and Verification Guidelines for CO2 Capture and Storage Under the EU ETS.op cit.

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2. DEVELOPING AN ACTIVITY OR INSTALLATION DEFINITION

2.1 Overview As outlined above (Section 1.2), in order for CCS operations to be opted-in and recognised in the EU ETS, appropriate activity/installation definition(s) must be outlined. In order to develop a definition of a CCS activity, it is important to consider firstly the emission sources that might be included within the definition of the CCS activity, and subsequently, how these emission sources determine the boundary of the CCS activity. These two elements form the basis for developing an activity definition suitable for CCS. Based on these criteria, this section presents:

⇒ the issues posed by Article 24 opt-in;

⇒ based on the emission sources, the installation boundary for a CCS activity;

⇒ a proposed definition of a CCS activity, and

⇒ issues for consideration beyond Phase II of the EU ETS. The emission sources – including potential emission sources – across a CCS chain, and their relevance in the context of EU ETS accounting rules are described in Appendix A.

2.2 Issues To Consider For CCS In The EU ETS Via Article 24 The present wording of the proposition under Article 24 poses two main complexities in so much as: 1. It is unclear how to define CCS as a new activity type when it involves a range of installation

types (CO2 source, CO2 capture, transport, injection, storage), and therefore whether these need to be separate installations in their own right. In addition, the CO2 source plant may already be qualifying installations under the EU ETS, and/or where the geological storage project involves an offshore oil and/or gas installation, this may also be a qualifying installation (22). Therefore, CCS could involve deployment at incumbent installations in the EU ETS.

2. Consequently, this makes it rather unclear how an appropriate activity definition could be developed for CCS that is able to cross-cut existing activity/installation types. The current design of Annex I of Directive 2003/87/EC involves defining Activity Types, with particular installations types nominated thereunder (see Annex I of Directive 2003/87/EC).

Notwithstanding these issues, there is not sufficient time prior to the beginning of Phase II of the EU ETS in which to amend the present Directive. As such there is a need for a practical solution to accommodate CCS operations post-2007. Therefore the following assumptions have been used as the basis for resolving these complexities:

• Any incumbent installation planning to employ CCS might need to be opted-out then opt it back in under the newly defined activity type. This is likely to be the most practical option so that greater clarity is achieved around the boundaries of the qualifying installation (as opposed to an installation operating with two permits);

• That inclusion via Article 24 route in Phase II will be based on a new activity type covering the following installations:

o the installation where CO2 is generated, captured and subsequently transferred from;

(22) By virtue of the presence of a Combustion Installation >20MW net rated thermal capacity and a flare installation.

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o the installation receiving transferred CO2 and transporting it to a storage installation (a pipeline); and,

o the installation receiving CO2 from a pipeline and injecting it into a storage site (including facilities undertaking EOR operations), including the subsurface geological elements of the storage site.

These assumptions are consistent with the outcome of discussions between ERM, DTI, Defra and the EC and various legal advisors during the scoping phase of the project. Based on these assumptions, Appendix A presents a review the various emission sources across a CCS chain. The emissions sources defined therein provides the basis for establishing the description of the opt-in activity, and subsequently, the monitoring and reporting requirements linked to that activity described below.

2.3 Defining Installation Boundaries For The Opt-In Under Article 24

Decision 2007/589/EC outlining the revised EU ETS MRGs for Phase II requires that (23):

The monitoring and reporting process for an installation shall include all emissions from all emission sources and/or source streams belonging to activities listed in Annex I to Directive 2003/87/EC, carried out at the installation, of greenhouse gases specified in relation to those activities, as well as from activities and greenhouse gases included by a Member State pursuant Article 24 of Directive 2003/87/EC.

All emissions sources within these boundaries are to be identified, described, and monitored and reported including specifying the monitoring methodology and frequency in accordance with the approved monitoring plan for the installation. Taking into consideration the various emissions sources and approaches identified in Appendix A, boundaries of the opted-in installations can be considered to encompass:

• The installation generating the CO2, based on qualifying criteria laid down in Annex I of Directive 2003/87/EC, including the capture technology applied at a qualifying installation;

• Pipelines installations transporting captured CO2 from qualifying installations, including emissions from any booster stations employed on the pipeline;

• Injection and storage installations receiving CO2 from pipeline(s); and including the above ground installation, well(s), the subsurface storage complex covering inter alia:

o the target formations, o the caprock, other surrounding strata, and spill-points in the reservoirs or the

formation beyond the CO2 plume in open reservoirs etc.

• This also includes any emissions associated with breakthrough CO2 in enhanced hydrocarbon recovery activities.

This forms the basis for defining the opted-in installation(s) under Article 24 of Directive 2003/87/EC. The proposed activity and installation definitions relevant to CCS are outlined below.

(23) Decision 2007/589/EC. Section 4.1.

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2.4 Proposed Activity Definition For The Article 24 Opt-In

Based on the assumptions and emissions sources described above (Section 2.2 – 2.3), the following elements are considered to form part of a complete CCS activity: CO2 Capture and Storage Activities CO2 capture and storage activities involving processes consisting of the separation of CO2 from industrial and energy-related sources, transport to a storage location and long-term isolation from the atmosphere. This activity involves the following types of installations:

CO2 capture installations: Installations undertaking the generation, capture, compression and transfer of CO2 to an installation suitable for transporting CO2. This may consist of any installation included in Annex I of Directive 2003/87/EC employing CO2 capture technologies (eg pre-combustion; post-combustion; oxyfuel) to separate CO2 streams from process or combustion off-gases. CO2 transport installations: Installations receiving CO2 from a capture installation that is designed for the purpose of transporting CO2 to a storage installation. This may consist of pipeline(s) carrying CO2, booster stations used to raise compression along the pipeline, and any other auxiliary plant linked to the pipeline. Mobile tankers are not included in this opt-in. CO2 storage installations: Installations for the purpose of long-term storage of CO2 for the purpose of isolating it from the atmosphere. This may consist of above ground engineering components linked to CO2 injection operations (compressors, combustion installations etc.), wells (observation, injection, producing), the geological CO2 storage site, and the CO2 storage complex. This may also include hydrocarbon production facilities and fields utilising CO2 injection for enhanced oil recovery (miscible CO2 flooding).

2.5 Modalities For The Opt-In and For Phase III For Phase III of the EU ETS, it is likely to be more effective to transfer the opted-in activity as separate installation in the EU ETS in their own right in the following way:

• Source and capture: the addition of a capture plant to an incumbent installation would be considered as a simple plant modification, and would be caught under the existing obligations in Directive 2003/87/EC as a “…directly associated activity with a technical connection with the activities...” and thus would not require any opt-in. Allocation of allowances to this installation would be on the same basis as for other incumbent installations in the same sector not employing CO2 capture;

• Transportation: pipelines carrying CO2 for the purpose of storage be considered as a new type of installation in the EU ETS, and allocated zero allowances. This would create a monitoring and reporting obligation for the operator under Article 6 of Directive 2003/87/EC, and also a requirement to surrender allowances equal to monitored and reported emissions in each calendar year, in accordance with the Greenhouse Gas Permit issued under Articles 6(2)(e) of Directive 2003/87/EC.

• Injection and storage: again these would be considered as a separate installation in the EU ETS, be given a zero allocation, and would face the same obligations as outlined for transportation above. This would also include installations employing EOR.

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2.6 Considerations In The Context Of Broader Regulatory Developments

2.6.1 Recognising Non-Emissions From CCS In The EU ETS

As outlined in the previous section, the 2006 IPCC GLs provides the basis upon which emissions from CCS should not be allocated to the source emitting installation. This means that non-emitted CO2 can only be recognised as such in national inventories if it is exported to a storage site that is monitored in accordance with the 2006 IPCC GLs. As a consequence, the guidelines thus present a de facto basis upon which developing a regulatory/permitting regime for CO2 storage sites.

2.6.2 Developing CCS Legislation In The European Union

The European Commission has prepared a draft Directive for CCS. The legislation focuses on the regulation of storage site operations to protect human health and the environment from the potential hazards posed by capturing, transporting or storing CO2. As such, the draft Directive contains provisions regarding site selection and monitoring, and attendant technical Annexes to support the enforcement of the legislation. These are based on operationalising the 2006 IPCC GLs, Chapter 5, Volume 2. The monitoring and reporting guidelines proposed within this opt-in serve to complement the provisions proposed by the European Commission in the draft Directive. Notwithstanding the monitoring obligations laid out therein have been prepared consistent with the procedure outlined here, and cognizant of the 2006 IPCC GLs.

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3. DEVELOPING ACTIVITY/INSTALLATION SPECIFIC MONITORING

AND REPORTING GUIDELINES

3.1 Overview

Based on the activity definition outlined previously (Section 2.4), there is a need to develop activity specific monitoring and reporting guidelines for the installation(s) identified within the opt-in activity description. In this context, it will be necessary to split the guidelines between the different installations making up the new activity as follows:

• CO2 generation and capture;

• CO2 transportation;

• CO2 storage;

• Enhanced oil recovery. Prior to the outlining of the specific guidelines, there are several general issues linked to EU ETS MRGs that need to be taken into consideration specific for application of the guidelines to CCS activities.

3.2 General Issues To Consider For Including CCS In The EU ETS

There are several new terms and definitions contained in the revised MRGs for Phase II of the EU ETS (Decision 2007/589/EC) which will need careful consideration with respect to developing activity specific guidelines for CCS installations. Key factors to take into account include:

⇒ Emission types included in the EU ETS. Presently The MRGs only deal with combustion and process emissions, which may not be applicable to CCS operations and could require new definitions to be developed;

⇒ New criteria for minor and de minims source streams. New rules allow monitoring to be waived for very minor source streams, which may be in conflict with the MRG approach for CCS, where source streams will by definition intentionally small or non-existent;

⇒ The potential to apply new ‘fall-back’ approaches. This is designed to reduce the monitoring burden on small emitters, but could conflict with the need for reasonably intensive monitoring of potentially not emitting streams;

⇒ Rules for modifying monitoring methodologies. It will be important to maintain flexibility in storage site monitoring plan design, taking into consideration the embryonic and iterative nature of the technologies;

⇒ Cost effectiveness considerations. There will be a need to ensure that monitoring plans for storage sites do not impose excessive costs on operators.

These points are discussed in greater detail below.

3.2.1 Types Of Emission Included In The EU ETS

Presently the EU ETS MRGs cover the inclusion of the following types of emissions:

• “emission source” means a separately identifiable part (point or process) of an installation from which relevant greenhouse gases are emitted;

• “combustion emissions” means greenhouse gas emissions occurring during the exothermic reaction of a fuel with oxygen;

• “process emissions” means greenhouse gas emissions other than combustion emissions occurring as a result of intentional and unintentional reactions between substances or their

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transformation, including the chemical or electrolytic reduction of metal ores, the thermal decomposition of substances, and the formation of substances for use as product or feedstock;

Certain emissions that may occur across the CCS chain – such as venting from the pipeline, fugitive leaks from compressors, or leakage from the storage site – do not conceivably fall into any of these categories, although Decision 2007/589/EC does require monitoring of emissions during start-up, shut-down and emergency situations (24), so a requirement to monitor these emissions sources is in essence captured thereunder. Therefore, in order for these types of emissions to be accounted for, it may be appropriate to define the following types of emissions in the MRGs included in the opt-in:

⇒ “vented emissions” means greenhouse gas emissions from intentional or unintentional release of captured CO2 due to routine or emergency operations.

⇒ “fugitive emissions” means greenhouse gas emissions from routine chronic or sporadic unintentional releases of captured CO2 as a result of leaking valves, flanges, seals etc.

⇒ “leakage emissions” means greenhouse gas emissions from intentional or unintentional release of captured CO2 from a geological CO2 storage site to the atmosphere.

This would capture all the relevant emissions types from the new categories of emissions source points potentially arising across a CCS chain, as outlined in the Section 2 of this report. Alternatively, the definition of “process emissions” could be modified in the opt-in to include the emission sources described above (venting, fugitives, leakage).

3.2.2 New Criteria For De-minimis and Minor Source Streams

The Decision 2007/589/EC also includes provisions for the following types of source streams:

• “De-minimis source streams” means a group of minor source streams selected by the operator and jointly emitting 1 ktonnes of fossil CO2 or less per year or that contribute less than 2% (up to a total maximum contribution of 20kt of fossil CO2 per year) of total annual emissions of fossil CO2 of that installation before subtraction of transferred CO2, whichever is the highest in terms of absolute emissions;

• “Minor source streams” means those source streams selected by the operator to jointly emit 5kt of fossil CO2 or less per year or to contribute less than 10% (up to a total maximum contribution of 100kt of fossil CO2 per year), to the total annual emissions of fossil CO2 of an installation before subtraction of transferred CO2, whichever is the highest in terms of absolute emissions.

For source streams identified as falling within these categories the operator may, subject to approval by the competent authority, select as a minimum the Tier 1 level for the variables used to calculate emissions from minor source streams and apply approaches for monitoring and reporting using his own no-tier estimation method for de-minimis source streams (25). In other words, more relaxed monitoring requirements may be applied to these streams. Whilst this serves to ease the monitoring burden on operators, for CCS the focus of emissions monitoring is on potential emission sources, and these may be large for example for a pipeline rupture. Thus, this derogation should not provide the basis for reducing monitoring requirements across CO2 transport, injection and storage which are likely to be handling very large CO2 inventories.

(24) Section 4.1, para 4. (25) Revised EU ETS MRGs op cit.. Section 5..2, pg. 21.

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3.2.3 Rules For Modifying Monitoring Methodologies

Under the Decision 2007/589/EC, the following rules apply to changes in a methodology (26):

The monitoring methodology shall be changed if this improves the accuracy of the reported data, unless this is technically not feasible or would lead to unreasonably high costs. A substantial change to the monitoring methodology as part of the monitoring plan shall be subject to the approval of the competent authority if it concerns:

− a change of the categorisation of the installation as laid down in table 1,

− a change between the calculation based or the measurement based methodology used to determine emissions,

− an increase of the accuracy of the activity data or other parameters (where applicable) which implies a different tier level,

All other changes and proposed changes in monitoring methodology or the underlying data sets shall be notified to the competent authority without undue delay after the operator has become aware of it or could in all reasonableness have become aware of it, unless otherwise specified in the monitoring plan.

As outlined in Section 3.5 of this report where the monitoring methodology for storage sites is described, there is a need to adopt an iterative approach for storage site monitoring, based around the principle of “adaptive learning”. This is because after injection commences, there may be a need to adapt a monitoring plan as the understanding of the subsurface behaviour of the CO2 plume evolves. The main consideration is, therefore, that sufficient flexibility is provided for operators who need to adapt their monitoring plan for a storage site.

3.2.4 Cost Effectiveness Considerations

Decision 2007/589/EC includes provisions for cost effectiveness as follows (27):

Cost effectiveness. In selecting a monitoring methodology, the improvements from greater accuracy shall be balanced against the additional costs. Hence, monitoring and reporting of emissions shall aim for the highest achievable accuracy, unless this is technically not feasible or will lead to unreasonably high costs. The monitoring methodology itself shall describe the instructions to the operator in a logical and simple manner, avoiding duplication of effort and taking into account the existing systems in place at the installation.

They also include a definition of unreasonable costs as follows:

• “Unreasonable costs” means costs of a measure disproportionate to its overall benefits as established by the competent authority. In respect to the choice of tier levels the benefit may correspond to the value of the allowances corresponding to an improvement of the level of accuracy, or for measures increasing the quality of reported emissions but without direct impact on accuracy, a fraction exceeding an indicative threshold of 1% of the average value of the allowances allocated to the installation for the previous trading period. For installations without this history, data from representative installations carrying out the same or comparable activities are used as reference and scaled according to their capacity.

There will be a need to ensure that monitoring plans for storage sites do not impose excessive costs on operators. This is a particularly prudent consideration given that, in theory, a very

(26) Revised EU ETS MRGs op cit.. Section 4.3, pg. 19. (27) Revised MRGs, Section 3, pg. 16

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detailed monitoring plan could be developed for the storage site involving highly expensive methods such as intensive 4D-seismic etc. However, intensive monitoring approaches are unlikely to prove cost effective and as such there is probably a need for an operator to outline his rationale based around cost-effectiveness considerations for any selected approach for a storage site monitoring plan.

3.2.5 Approaches To Emissions Methodologies

Two different approaches for monitoring emissions from qualifying installations are allowed for under Annex IV of Directive 2003/87/EC, as follows (28):

• a calculation based methodology, determining emissions from source streams based on activity data obtained by means of measurement systems and additional parameters from laboratory analyses or standard factors

• a measurement based methodology, determining emissions from an emission source by means of continuous measurement of the concentration of the relevant greenhouse gas in the flue gas flow and of the flue gas flow.

In addition the MRGs outline that

The operator may propose to use a measurement based methodology if he can demonstrate that:

− it reliably results in a more accurate value of annual emissions of the installation than an alternative calculation based methodology avoiding unreasonable costs; and

− the comparison between measurement and calculation based methodology is based on an identical sets of emission sources and source streams.

A discussion of the most appropriate approaches for CCS is provided in the previous report by ERM (29), and the reader is referred to that report for a detailed discussion of these issues. In this report it was concluded that:

…in weighing up the options of:

i) trying to apply emissions factors to all the different elements of a CCS chain in light of the breadth of uncertainties posed by the calculation/emissions factor based approach, with

ii) the potential inequity of the measurement/mass balance approach, and the potential issues it presents over liability for fugitive emissions,

it was concluded by the ad hoc group that the latter would prove more appropriate and acceptable in the near term.

These considerations excluded approaches to monitoring potential emissions from storage sites as this was excluded from the MRGs in the approach adopted in that report. Measurement-based methodologies are the only technology that may be applied to estimate emissions from CO2 from storage sites, although estimates must be used in conjunction with a calculation method in order to provide a final figure for estimated CO2 emissions.

(28) Revised MRGs. Section 4.2, pg. 17 (29) DTI 2005. Developing Monitoring, Reporting and Verification Guidelines for CO2 Capture and Storage Under the EU ETS.op cit.

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3.2.6 Tiers Of Approaches

The MRGs also prescribe different Tiers of Approaches (Tiers 1 - 4) applicable to monitoring and reporting, with higher tiers reflecting increasing levels of accuracy. Considering the novel nature of CCS technologies, only the highest level of accuracy is prescribed in the proposed MRGs for CCS in order to ensure the accuracy of the data collected is robust, and also to improve the learning of CCS monitoring techniques. This is in accordance with the 2006 IPCC GLs, which prescribe Tier 3 approaches for CO2 injection and storage (although not for transport; see Appendix A).

3.2.7 Information Requirements Of A Monitoring Plan

Following application of the appropriate methodology to the appropriate installation, Decision 2007/589/EC requires the following information to be set out in the monitoring plan: (1) the description of the installation and activities carried out by the installation to be

monitored;

(2) information on responsibilities for monitoring and reporting within the installation;

(3) a list of emissions sources and source streams to be monitored for each activity carried out within the installation;

(4) a description of the calculation based methodology or measurement based methodology to be used;

(5) a list and description of the tiers for activity data, emission factors, oxidation and conversion factors for each of the source streams to be monitored;

(6) a description of the measurement systems, and the specification and exact location of the measurement instruments to be used for each of the source streams to be monitored;

(7) evidence demonstrating compliance with the uncertainty thresholds for activity data and other parameters (where applicable) for the applied tiers for each source stream;

(8) if applicable, a description of the approach to be used for the sampling of fuel and materials for the determination of net calorific value, carbon content, emission factors, oxidation and conversion factor and biomass content for each of the and source streams;

(9) a description of the intended sources or analytical approaches for the determination of the net calorific values, carbon content, emission factor, oxidation factor, conversion factor or biomass fraction for each of the source streams;

(10) if applicable, a list and description of non-accredited laboratories and relevant analytical procedures including a list of all relevant quality assurance measures eg inter-laboratory comparisons as described in section 13.5.2;

(11) if applicable, a description of continuous emission measurement systems to be used for the monitoring of an emission source, ie the points of measurement, frequency of measurements, equipment used, calibration procedures, data collection and storage procedures and the approach for corroborating calculation and the reporting of activity data, emission factors and alike;

(12) if applicable, where the so-called “fall-back approach” (section 5.3) is applied: a comprehensive description of the approach and the uncertainty analysis, if not already covered by items a) to k) of this list;

(13) a description of the procedures for data acquisition and handling activities and control activities as well as a description of the activities (see section 11.1-3);

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(14) where applicable, information on relevant links with activities undertaken under the Community eco-management and audit scheme (EMAS) and other environmental management systems (eg ISO14001:2004), in particular on procedures and controls with relevance to greenhouse gas emissions monitoring and reporting.

These elements will all need to be developed on a site-specific basis following implementation of the monitoring methodologies for the installation generating and capturing the CO2, the pipeline installation transporting the CO2, and the injection and storage facility, including site-specific elements relating to EOR operations. Activity specific guidelines for each are outlined below.

3.3 [1.] Guidelines For CO2 Capture

[1.] 0.General Provisions Subject to approval by the competent authority, operators of CO2 installations may subtract from the calculated emissions of the installation any CO2 which is not emitted from the installation but transferred out as a substance at a level of purity in accordance with international and European Community standards (e.g. the London Protocol) to a CO2 transport installation. Operators must provide evidence that the transport installation is transferring the CO2 to a recognised CO2 storage installation, permitted in accordance with relevant European Community and national law. The subtraction for the installation should be mirrored by a respective reduction in emissions reported for the sector generating the emissions within the Member State’s National Inventory submission to the Secretariat of the United Nations Framework Convention on Climate Change. Where there is a cross-border transfer of CO2, this should be reflected in the both the exporting and importing country’s national greenhouse gas inventory. Countries adopting the 2006 IPCC Guidelines for National Greenhouse Gas Inventories may report emissions from CO2 transport, injection and storage under Category 1 C.

[1.]1. Boundaries and Completeness Criteria Installations listed in Annex I to Directive 2003/87/EC employing CO2 capture technologies to capture and transfer CO2 must identify the emission sources to be monitored as part of the monitoring plan, in accordance with the relevant Annex [of Decision 2007/589/EC]. The monitoring and reporting plan must clearly state those emission sources that will be subject to CO2 capture, and all other emission sources within the installation boundary. The quality of information provided in terms of completeness, consistency, transparency, accuracy, cost effectiveness and materiality should be consistent with the overall risk management procedures laid out in Annex I [of Decision 2007/589/EC]. The operator of the installation should use the appropriate activity, emissions factor and oxidation factor data Tier to monitor greenhouse gas emissions, according to the size of the installation, as set out in [Decision 2007/589/EC]. Additional emission sources associated with the CO2 capture facility must be determined as outlined below.

[1.]2. Determination of CO2 Emissions Specific emissions sources for the relevant installation type must be determined in accordance with the appropriate procedures outlined for the qualifying installation in Annexes II-XI [in Decision 2007/589/EC].

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Additional emissions sources of CO2presented by the capture process include:

a) Energy related combustion

− from emissions stack(s) as a result of inefficiencies and imperfections in capture of CO2 in the flue gas stream;

b) Fugitive and vented emission

− Emissions from solvent stripping operations, including imperfect stripping of the solvent;

− Leaking seals on blowing equipment required to force the flue gas into the adsorption tank (pre- and post-combustion capture);

− Leaking seals on solvent stripping tanks;

− Fractures or ruptures on pipework;

− Leaking seals on compression equipment at the pipeline head;

[1.]2.1. CALCULATION OF CO2 EMISSIONS

[1.]2.1.1. Generation of CO2 From Combustion CO2 generated by combustion shall be calculated in accordance with Annex II [of Decision 2007/589/EC].

[1.]2.1.2. Process Emissions The amount of CO2 generated by an installation from process emissions should be calculated using the appropriate methodology set out in the relevant Annex (II-XI) [of the Decision 2007/589/EC].

[1.]2.1.3. Fugitive and Vented Emissions Fugitive emissions from the emission sources identified for the CO2 generation and capture should be calculated using a mass balance approach. The mass balance is calculated by subtracting the mass of captured CO2 transferred from the installation from the calculated emissions generated outlined in sections 2.1.1. and 2.1.2. The mass balance approach is based on the following equation:

CO2 emissions [tCO2] = T CO2 – E CO2 Where;

- T CO2 [tCO2]: the mass of CO2 generated at the installation, calculated in accordance with Section 2.1.1 and Section 2.1.2.

- E CO2 [tCO2]: the total mass of CO2 exported to the pipeline installation, calculated using the following equation:

CO2 export [E tCO2] = Activity data [k m³] * CO2 content [t/k m³]

a) Activity data Tier 4: Activity data is the metered volume of CO2 transferred across the installation boundary in thousands of cubic metres (k m³). Transfer of CO2 across the installation boundary into the CO2 pipeline should be measured using appropriate metering devices, designed to custody transfer standard.

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The metering process should provide data on the volume of CO2 transferred with a maximum uncertainty in the range 1.5%, in line with requirements laid down for the transfer of CO2 in Section 5.7 of Annex I [of Decision 2007/589/EC]. All measurements should be made in accordance with the standards outlined for Measurement Based Methodologies in Section 6 of Annex I [of Decision 2007/589/EC]. b) CO2 content CO2 content should be measured in tonnes per thousand cubic metres (t/k m³). Average concentrations of CO2 transferred at the installation boundary should be measured using either:

− Continuous infrared gas analysis probe

− Gas sampling and analysis conducted at a laboratory in accordance with the provisions of section 13 of Annex I [of Decision 2007/589/EC]

− An approach agreed with the competent authority based on the available information sources (eg fuel supplier information or internationally accepted standards)

The approach employed should be agreed with the competent authority prior to commencing transfer of CO2. Levels of impurities present in the transferred CO2 stream should be in accordance with EU and international standards. The combined approach should provide data with an overall maximum uncertainty of less than 3%.

3.4 [2.] Activity Specific Guidelines For CO2 Transport

[2.]1. Boundaries and Completeness Criteria All combustion, process, vented and fugitive emission sources across a CO2 pipeline transportation system must be monitored and reported, including any emissions associated with gas-fired booster stations along the pipeline network. Emissions from gas-fired booster stations should be monitored and reported in accordance with Annex II [of Decision 2007/589/EC]. Where gas-fired booster stations have a rated input exceeding 20 MW, these should be included as part of the pipeline installation and excluded as a separate qualifying installation under Annex I of Directive 2003/87/EC. The quality of information provided in terms of completeness, consistency, transparency, accuracy, cost effectiveness and materiality should be consistent with the overall risk management procedures laid out in Annex I [of Decision 2007/589/EC]. The operator of the installation should use the appropriate activity, emissions factor and oxidation factor data Tier to monitor greenhouse gas emissions, according to the size of the installation, as set out in Annex I [of Decision 2007/589/EC]. Countries adopting the 2006 IPCC Guidelines for National Greenhouse Gas Inventories may report emissions from CO2 transport under Category 1 C Additional emission sources associated with the CO2 transport pipeline installation must be determined as outlined below.

[2.]2. Determination of CO2 Emissions Emissions sources of CO2presented by the pipeline transportation include:

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a) Energy related combustion

− Gas-fired turbines for power compressors

− Emergency/standby generators b) Fugitive and vented emissions

− Leaks due to pipeline fractures or ruptures

− Leaking seals on pipeline joints and pipeline booster stations

− Vented emissions from pipeline maintenance, repair or blowdown under routine or emergency conditions

− Vented or fugitive emissions from temporary intermediate storage facilities

[2.]2.1. Calculation of CO2 Emissions

[2.]2.1.1. Generation of CO2 From Combustion Combustion emissions shall be calculated in accordance with Annex II [of Decision 2007/589/EC].

[2.]2.1.2. Fugitive and Vented Emissions Fugitive and vented emissions from the emission sources identified for CO2 transportation should be calculated using a mass balance approach. The mass balance is calculated by subtracting the mass of captured CO2 received by the pipeline installation from the generating installation from the mass of CO2 transferred to the injection and storage installation. The mass balance approach to calculating fugitive and vented emissions from a CO2 pipeline is based on the following equation:

CO2 emissions [tCO2] = E CO2 – I CO2 Where;

- E CO2 [tCO2]: mass of CO2 received by the pipeline operator from the generating installation

- I CO2 [tCO2]: the total mass of CO2 transferred from the pipeline installation to the injection and storage installation

These should be calculated using the following formula:

CO2 export/import [E/I tCO2] = Activity data [k m³] * CO2 content [t/k m³] The mass of CO2 received by the pipeline operator from the generating installation should be measured in accordance with the procedure laid down for CO2 capture installations. Vented and fugitive emissions from any intermediate (sub-surface) storage facilities should be carried out in accordance with the procedure for CO2 injection and storage. a) Activity data Tier 4: Activity data is the metered volume of CO2 transferred across the installation boundary in thousands of cubic metres (k m³). Transfer of CO2 across the installation boundary to the CO2 injection and storage operator should be measured using appropriate metering devices, designed to custody transfer standard.

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The metering process should provide data on the mass of CO2 transferred with a maximum uncertainty in the range 1.5%, in line with requirements laid down for the transfer of CO2 in Section 5.7 of Annex I [of Decision 2007/589/EC]. All measurements should be made in accordance with the standards outlined for Measurement Based Methodologies in section 6 of Annex I [of Decision 2007/589/EC]. b) CO2 content CO2 content should be measured in tonnes per thousand cubic metres (t/k m³). Average concentrations of CO2 transferred at the installation boundary should be measured using either:



− An approach agreed with the competent authority based on either information sources (eg fuel supplier information or internationally accepted standards)


3.5 [3.] Activity Specific Guidelines For CO2 Injection and Storage

[3.]1. Boundaries and Completeness Criteria Delineating boundaries for sub-surface geological CO2 storage sites is a specialist subject area and should only be undertaken by personnel with relevant expertise in sub-surface process modelling and risk assessment. Boundaries for a sub-surface CO2 geological storage complex should include the injected CO2 plume (ie the storage site) and adjoining elements of the engineered (wells) and non-engineered system (caprock, overburden, faults, fissures etc). The complex boundaries shall also be considered to include other secondary containment features in the geosphere (eg other overlying reservoir seal pairs which could trap upward migrating CO2). Rigorous processes should be employed in the first instance to identify all components of the sub-surface storage complex in order to determine potential emission pathways linked to the target formations. This shall be achieved through the development of a site characterisation report. Application of appropriate assessment procedures should be undertaken to assess the risks of activation of potential emission pathways, as described below. The application of rigorous quality assurance and quality control procedures (QA/QC) should be applied in each step of the monitoring scheme design. Above ground installations shall also be considered to fall within the overall CO2 storage site installation. Countries adopting the 2006 IPCC Guidelines for National Greenhouse Gas Inventories may report emissions from CO2 injection and storage under Category 1 C.

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[3.]2. Determination of CO2 Emissions Potential vented and fugitive CO2 emissions sources for above ground installations linked to the CO2 injection and storage activities can include:

− Holding tanks (for temporary storage of CO2);

− Compressor stations

− Turbines or other combustion installations for power generation Potential fugitive and leakage emission sources (or pathways) from sub-surface CO2 geological storage complexes include:

− Direct leakage pathways created by wells or mining (operational or abandoned wells, well blow-outs, future mining activities)

− Natural leakage and migration pathways (that may lead to emissions over time). These include through a low permeability caprock, via a spill point in synclinal structures, through a degraded caprock, via dissolution of CO2 into formation fluids and subsequent flow out of the target storage complex, via natural or induced faults/fractures.

The exact nature and risk of fugitive or leakage emissions from these potential emission pathways should be characterised and determined prior to commencing injection using the procedure outlined below. This provides the basis for the design of the monitoring plan for a specific geological CO2 sub-surface storage site as outlined below. Additional initially uncharacterised and undetermined emission sources may be activated following the commencement of injection operations, and these emission sources will also need to be identified, characterised, monitored and reported as part of the monitoring plan. A key component in the design of the methodology will be the rigorous application of appropriate quality assurance and quality control procedures (QA/QC). QA/QC will serve to minimise the risk of selecting poor storage sites, and also the implementation of inappropriate monitoring plan. These are outlined below. Regulatory controls on site selection and operation should provide the basis for minimising the risk of these emissions pathways being activated for a specific project in accordance with relevant international, European Community and national legislation.

[3.]2.1. Calculation of CO2 Emissions

[3.]2.1.1. Generation of CO2 From Combustion Combustion emissions from above ground installations shall be calculated in accordance with Annex II [of Decision 2007/589/EC].

[3.]2.1.2. Fugitive and Vented Emissions (above ground installations) Fugitive and vented emissions from the emission sources for above ground installations should be calculated using a mass balance approach. The mass balance is calculated by subtracting the mass of captured CO2 received from the pipeline installation from measured mass of CO2 injected into the storage installation. The mass balance approach to calculating fugitive and vented emissions from above ground installations is based on the following equation:

CO2 emissions [tCO2] = E CO2 – In CO2

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Where;

- E CO2 [tCO2]: mass of CO2 received from the pipeline operator by the injection and storage operator

- In CO2 [tCO2]: the total mass of CO2 injected into the geological storage installation These should be calculated using the following formula:

CO2 import/injected [I/In tCO2] = Activity data [k m³] * CO2 content [t/k m³] The mass of CO2 received by the injection and storage operator from the pipeline installation should be measured in accordance with the procedure laid down for CO2 capture and pipeline installations. a) Activity data Tier 4: Activity data is the metered volume of CO2 transferred across the installation boundary in thousands of cubic metres (k m³). Transfer of CO2 across the installation boundary to the CO2 injection and storage operator should be measured using appropriate metering devices, designed to custody transfer standard. The metering process should provide data on the mass of CO2 transferred with a maximum uncertainty in the range 1.5%, in line with requirements laid down for the transfer of CO2 in Section 5.7 of Annex I [of Decision 2007/589/EC]. All measurements should be made in accordance with the standards outlined for Measurement Based Methodologies in section 6 of Annex I [of Decision 2007/589/EC]. b) CO2 content CO2 content should be measured in tonnes per thousand cubic metres (t/k m³). Average concentrations of CO2 transferred at the installation boundary should be measured using either:



− An approach agreed with the competent authority based on either information sources (eg fuel supplier information or internationally accepted standards)


[3.]2.1.3. Leakage Emissions (from the sub-surface geological storage site)

a) Developing a CO2 storage site monitoring plan Data on vented and leakage emission flux rates from the subsurface storage complex should be collected through direct monitoring of the sub-surface geological CO2 storage complex, based on the following objectives of the monitoring plan:

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• To detect the presence, location and migration paths of CO2 in the subsurface in order to provide assurance regarding the permanence of storage; and,

• To detect the leakage of CO2 migrating from the primary CO2 containment complex, and potentially re-emerging at the surface ie atmospheric release of CO2.

The heterogeneity of the sub-surface means that a bespoke approach will be required based on the particular characteristics of an individual site, covering the site specific potential risk of CO2 leakage, the number and size of potential pathways and therefore the potential magnitude of leakage events, and the sensitivity of receptors in the zone surrounding the storage site. In order to arrive at an appropriate monitoring plan for a sub-surface geological CO2 storage complex, a step-wise procedure following:

− Site characterisation

− Simulation modelling

− Risk assessment

− Monitoring plan design and technologies Must be followed. An appropriate approach is summarised below (Figure 3.1), and the key steps are elaborated thereafter.

Figure 3.1. Key Steps In Designing a CO2 Storage Site Monitoring Plan Step 1 - Literature and Data review The preliminary step in identifying a CO2 storage site is the collection and collation of various subsurface literature and data sources. These data and literature can be used to identify potential

1. Literature & data review

2. Build static Earth model

3. Performance assessment

3.1 Assess leakage risk

4. Define monitoring plan

STEP

Data catalogue (geology, geophysics,

old wells, other uses)

Agreed/qualified/verified static geological

Earth models inc. rational behind

decisions/choices – define project

boundary

Source sink matching; injection plan;

numerical simulations; plume behaviour;

ultimate fate; trapping mechs; flux rates

across boundary, secondary

containments; leakage pathway; hydro-

geology; biosphere

Identify potential pathways/

emission sources

EU ETS monitoring plan

QA/QC

QA/QC

QA/QC

QA/QC

DOCUMENTATION

28

storage formations in the province under study. Potential storage formations (30) will be sedimentary structures that indicate the presence of potential CO2 trapping mechanisms (physical / structural trapping; mineral trapping; hydrodynamic trapping etc) at sufficient depth (generally >800m, although this will partially be temperature dependent). This will be based on the following types of sub-surface information:

• Geology (stratigraphy, petrology, mineralogy, faults, folding, heterogeneity etc);

• Geochemistry (dissolution rates, mineralisation rates);

• Geomechanics (permeability, fracture pressure);

• Hydrogeology;

• Temperature (phase state);

• Pressure (phase state);

• Vertical and lateral sealing (physical trapping);

• Caprock integrity (basal unit information such as pore size, capillary entry pressure, facies change etc.)

• Presence of man-made “bridges” (wells, mine shafts etc) Key data sources might include:

• Geological maps;

• Regional geological reports;

• Well core analysis data;

• Well logs;

• Reservoir fluid analysis;

• Injection tests;

• Geomechanical tests;

• Seismic reports and data;

• Other province level data (e.g. regional seismicity) etc. Suitable quality data of this type will assist in provisional screening of potential storage sites, and to assess the quality of trapping mechanisms present in the reservoir. Initial environmental, health and safety considerations will also need to be made at this stage, as these may preclude certain storage locations. Economic considerations will also need to be taken into account in terms of any effects on other users of the surface or sub-surface. Where insufficient geological and geophysical data is available, then additional exploration activities may be necessary, involving acquisition of new seismic data, and/or the drilling of exploration wells, injection testing etc. Step 2 – Build static Earth model(s) (scenarios) Using the data collected in Step 1, 3-D static geological Earth model(s) shall be built using computer reservoir simulators. The static geological Earth model(s) shall serve to characterise the potential storage complex in terms of:

• Geological structure of the physical trap;

• Geomechanical properties of the reservoir;

• Geochemical properties of the reservoir;

• Presence of any faults or fractures;

• Fault/fracture sealing;

(30) It is probably more sensible to think in terms of storage complexes, a paradigm that includes consideration of the surrounding

strata, and helps to frame ideas around potential migration pathways and secondary containment formations.

29

• Pore space volume;

• Porosity etc. The building of a 3-D static geological Earth model combines the parameters described in Step 1 into a set of unified models of the geological reservoir and surrounding domains. In practice, there will be degree of uncertainty about each of the parameters used to build the model, and a range of scenarios for each parameter should be contained in the model, and appropriate confidence limits attached. All rationale and assumptions used to build the model must be appropriately documented, and should ideally be agreed through expert panel decision-making (subject to appropriate QA/QC; see below) before proceeding to Step 3. Where agreement on the rationale and confidence assumptions cannot be reached, there may be a need to acquire additional data to improve data resolution etc ie return to Step 1. Step 3 – Undertake performance assessment Dynamic modelling shall involve the running a variety of time-step simulations of CO2 injection into the 3-D static geological Earth model(s) in the reservoir simulator constructed under Step 2. Factors to consider will include:

• Injection rates and CO2 properties (based on source characteristics);

• The efficacy of coupled process modelling (ie the way various single effects in the simulator(s) interact);

• Reactive processes (ie the way reactions of the injected CO2 with in situ minerals feedback in the model);

• The reservoir simulator used (multiple simulators may serve to validate certain findings);

• Short and long-term simulations (to establish CO2 fate and behaviour over decades and millennia)

The dynamic modelling should be able to provide insight to:

• The nature of CO2 flow in the reservoir;

• Storage capacity and pressure gradients in the primary containment complex;

• The risk of fracturing the storage formation(s) and caprock;

• The point when overspill may occur (in physical traps);

• The rate of migration (in open-ended reservoirs);

• Fracture sealing rates;

• Changes in formation(s) fluid chemistry and subsequent reactions (eg pH change, mineral formation, and inclusion of reactive modelling to assess affects);

Multiple simulations shall be undertaken, based on altering parameters in the static geological Earth model(s), and changing rate functions and assumptions in the dynamic modelling exercise (sensitivity analysis). Step 3.1 - Risk assessment A key component of the dynamic modelling exercise will be to assess the potential risks (likelihood and consequences) posed by the storage operation, based on the scenarios generated in the modelling exercise. Application of appropriate simulation techniques and scenarios should allow provisional understanding of the:

• Potential leakage pathways;

30

• Potential magnitude of leakage events (flux rates);

• Potential receptors for seeped CO2;

• Critical parameters affecting potential leakage (eg maximum reservoir pressure, maximum injection rate, sensitivity to various assumptions in the static geological Earth model(s) etc.);

These data can be used to assess the overall risk-profile of the project, and influence the framework of risk management measures and ultimately the decision as to whether to commence with the project. The data and outputs generated will also be used to inform an environmental, social, and health & safety impact assessment (ESHIA). Step 4 - Design monitoring plan Dynamic modelling shall serve to illustrate the following key facets of the storage site:

• CO2 trapping mechanisms and rates (including spill points and lateral and vertical seals);

• CO2 migration rates through the formation(s) (to illustrate when the CO2 might reach the planned vertical and lateral edges of the defined CO2 containment complex);

• Potential weak points in the overall containment system, and potential sealing mechanisms;

• Secondary containment systems in the overall storage complex; These form the basis for the design of a monitoring plan that is able to detect the modelled/predicted leakage (most likely and worst case) of CO2 migrating from the target CO2 containment complex, and potentially re-emerging at the surface. Other elements of the monitoring plan may also include:

• Technologies which can provide a wide areal spread in order to capture information on any previously undetected potential leakage pathways (eg airborne remote sensing technologies); and,

• Technologies that can detect the presence, location and migration paths of CO2 in the subsurface in order to provide assurance regarding the permanence of storage (eg seismic, well bore logs, gravity surveys etc);

In addition, continuous or intermittent monitoring of the following items must also be included:

• Fugitive emissions of CO2 at the injection facility;

• CO2 mass flow at injection wellheads;

• CO2 pressure at injection wellheads;

• Chemical analysis of the injected material; and,

• Reservoir temperature pressure (needed to determine CO2 phase behaviour and state); Step 5 – Application of Quality Assurance and Quality Control

Each of the Steps 1 - 4 must be subject to appropriate quality control by the following in order of importance: (1) The CO2 storage site developer and operator;

(2) The member state competent authority; and,

(3) Any other relevant institutions as prescribed in relevant European Community and international

law.

A schematic QA/QC procedure is provided below (Figure 3.2).

31

Figure 3.2 QA/QC procedure for storage site selection and monitoring plan

b) Elaboration of the monitoring programme in the Monitoring Plan The precise choice of technology employed should be based on best practice available at the time, and subject to change going forward (see below regarding operational activities).

Does the literature and data review suggest that the target

formation would represent a good CO2 storage site?

Does the static model for storage and leakage include a sufficient range of scenarios for sub-surface

characterisation?

Step 1 Acquire more data

Find new site

Step 2

No

Yes

Build static model

Remodel and/or clarify rationale. Include new

scenarios

Does the dynamic model for storage and leakage include a sufficient range of scenarios, including

coupled and reactive processes?

Step 3

No

Yes

Build dynamic model

No

Remodel and/or clarify rationale/assumptions. Include

extra scenarios

Yes

Define potential environmental flux rates

Are significant environmental, health & safety impacts possible at the maximum modelled flux rate? Is maximum flux rate higher than

can be effectively remediated? Are

dangerous flux rates below detection levels?

Does the monitoring plan demonstrate a priori

that the monitoring plan can detect the

modelled seepage rates developed in Step 3?

Can all pathways be effectively monitored?

Risk Assessment

Define monitoring plan

Yes

Find alternative site

- Outline Monitoring Plan

No

Refine monitoring plan. Include new

technologies.

No

Step 4

Step 3.1

Yes

32

As a minimum, project proponents should demonstrate in the Monitoring Plan, that all the technologies outlined in Annex 1 of Volume 2, Chapter 5 of the 2006 IPCC Guidelines for National Greenhouse Gas Inventories have been considered, and justification of selection [or not] of each shall be provided. Additional technologies are likely to emerge in the intervening period between the publication of IPCC Inventory Guidelines, and project proponents should consider additional sources of best practice, such the IEA GHG R&D Programme monitoring tool (31). The final monitoring plan shall outline specific details regarding:

• Technology employed (32);

• Technologies excluded (non-exhaustive);

• Justification for technology choices;

• Monitoring locations and spatial sampling rationale;

• Frequency of application and temporal sampling rationale; Project proponents should also provide an indicative assessment of the efficacy of the monitoring plan proposed, including assumed detection levels and evaluation of “important” or “significant” threshold levels in various sub-surface zones and domains. Final agreement of the provisional monitoring plan shall be made through discussion with the competent authority. c) Modifying the Monitoring Plan during and post-injection Even with the most rigorous of static and dynamic geological Earth model(s) design and analysis, and rigorous performance and risk assessment, deviations from predicted behaviour during and post-injection can be expected. As such, it will important to adopt an adaptive learning process

based around iterations of the procedure: model → predict → monitor → update → [repeat] etc. As such the following additional steps are added to the sequence outlined above (Figure 3.3).

(31) Available here: www.co2captureandstorage.info/co2monitoringtool (32) In this context, specific notation for different monitoring technologies should be developed in order to assist PDD development..

33

Figure 3.3. Key Steps In Updating a CO2 Storage Site Monitoring Plan Step 6 - Collect monitoring data This shall involve the collection and collation of the data collected from implementing the Monitoring Plan agreed with the competent authority. Step 7 - History-match History-matching shall involve the comparison of observed results from the implementing the Monitoring Plan with the behaviour predicted in performance assessment undertaken in Step 3. Appraisal and comparison of monitored behaviour shall allow new assumptions to be developed about the characteristics of the sub-surface, based on the new data received. These shall be used to re-calibrate the static geological Earth model(s), including new rationale, assumptions etc. Step 8 - Re-calibrate static Earth model(s) The static Earth model(s) shall be re-calibrated based in the results of history matching. Step 9 - Re-assess performance New leakage scenarios and flux rates shall be generated in the performance assessment, based on the recalibrated geological Earth model(s) prepared in Step 8.

6. Monitor storage site

7. History match

8. Re-calibrate Earth model

9. Re-assess performance

10. Re-assess leakage risk

STEP

Data from monitoring plan.

History match assessment of observed and predicted from Step 3 above.

Verification report

Include new rationale and assumptions identified from monitoring data. Develop

recalibrated Earth model.

Re-run dynamic model in

updated Earth model. Include

new functions (if available)

Re-appraise leakage risk with any

new results from Step 9.

QA/QC

QA/QC

QA/QC

QA/QC

11. Re-design monitoring plan

Include new technologies, monitoring

locations, frequencies.

Gain re-approval of monitoring plan

QA/QC

DOCUMENTATION

34

Step 10 - Re-assess risks The new scenarios produced in Step 9 shall be used to re-assess the previously prepared risk assessment. Review of the risk assessment with the competent authority shall be conducted in appraise any new risks identified. Step 11- Re-design monitoring plan The re-running of the performance assessment will generate new insights into the sub-surface characteristics of the storage containment complex and behaviour of the injected CO2. Consequently, where new CO2 sources, pathways and flux rates are identified, the monitoring plan may need to be adjusted according. This could serve to provide better resolution of observation, and better detection of migration and or potential leakage. Step 12 - Reapply QA/QC Relevant parts of the QA/QC process outlined above shall be re-applied. In addition, other QA/QC requirements will be presented at this phase of a project, as outlined below (Figure 3.4).

Figure 3.4. Additional QA/QC procedure for ongoing injection recalibration

Does the monitoring data agree with the

performance assessment?

History match

History match

Yes

No

Is there convergence between predicted

and observed behaviour?

Update dynamic (and static)

model, monitoring plan (ongoing

frequency, sensitivity, techniques,

locations)

Yes

No

- Consider ramping-down / cease monitoring

- Consider terms for liability transfer

No

Consider options for remediation and assurance

of safe storage

Yes

Site closure

Post-injection monitoring

Does the predicted behaviour suggest secure storage over a very long period of

time?

35

QA/QC shall also involve indicatively verifying that the mass of CO2 captured does not exceed the mass of CO2 stored (according to injection records and detected from seismic surveys etc) plus the reported fugitive emissions in the inventory year. This is in accordance with the 2006 IPCC Guidelines for National Greenhouse Gas Inventories.

[3.]2.1.3.1. Calculating CO2 Leakage Emissions From Storage Sites

The procedure outlined in Section [3.] 2.1.3 provides the basis for detecting leakage emissions from CO2 storage sites. If application of the monitoring plan provides evidence of leakage, leakage emissions from the geological CO2 storage sites should be calculated using the following formula:

CO2 emissions [tCO2] = F CO2 * T Where;

- F CO2 [tCO2/day]: flux rate of the CO2 leak estimated following the procedure outlined below.

- T [days]: is the length of time over which the leak is estimated to have been occurring or occurred.

a) Determining flux rate A stepwise procedure for determining the flux rate of the leak should be employed as follows: Step 1 – Identify and characterise the emissions source(s) (leak) Where application of the monitoring plan indicates the presence of a CO2 leak from the storage site, then more rigorous investigation should be undertaken to identify and characterise the source of the leak, including identification of the likely emission pathway(s). Emissions pathways may consist of:

• Direct leakage: through operational or abandoned wells or from well blow outs;

• Natural leakage and migration: through the pore system, in the absence of effective sealing strata, via a spill point through overfilling of the reservoir, through a degraded caprock, dissolution into pore fluids; via natural or induced faults or fractures.

The emission source should be fully described and characterised in respect of the nature of the leak and probable causes. Step 2 – Estimate the flux rate of the emission source(s) (leak) The flux rate of the leak should be estimated using methods appropriate for the emission source identified under step 1. These might require the application of a range of techniques including inter alia:

− direct metering in well-bores (for leaks contained within the well casing);

− acoustic imaging techniques to provide areal assessment of potential sites of leakage;

− use of submersibles vehicles (offshore) to identify and characterise bubbles or a CO2 plume on the sea-bed; or

− soil gas meters (onshore), corrected to account for background fluxes. This could also involve the use of other proxy measures and a range of novel techniques which may be developed on a case-by-case basis, depending on the nature of the emission source identified in Step 1. For all methods employed to determine the flux rate of an emission source, the operator must document the following in the emissions report:

36

− the rationale for the choice of method employed, and

− an assessment of the accuracy of the data collected with a description of the major sources of uncertainty in the estimates.

Flux rates should be reported in tCO2 per day. In estimating flux rates, account should be taken of both gaseous and dissolved CO2 i.e. different phase states of CO2. b) Determining the duration The duration of the leak in days should be determined from the date when the leak was first detected, back dated to one of the following reference points:

− The last date when the monitoring plan showed no evidence of leakage from the determined emission source. This maybe up to one calendar year, based on the submission of annual monitoring reports, or,

− The date of commencement of CO2 injection, when there is no available evidence to show that no leakage was detected, or,

− Other evidence which may be used to provide an estimate of the start date of leak.

3.6 [4.] Enhanced Oil Recovery Projects Using Captured CO2

[4.]0. General Provisions Installations undertaking enhanced oil recovery (EOR) using injected CO2 will present additional emission sources relative to standard CO2 storage operations. This arises as a consequence of the injected CO2 breaking through with the produced hydrocarbons. Operators undertaking CO2 storage operations in conjunction with the use of miscible CO2 flooding of an oil reservoir for the purpose of enhanced oil recovery (EOR) should therefore include the following the provisions in determining a monitoring and reporting plan. These provisions shall be undertaken in addition to those outlined for CO2 injection and storage [Section [3.]].

[4.]1. Determination of Emission Sources Key emissions sources for CO2 EOR operations include:

− the oil-gas separation units and gas recycling plant, where fugitive emissions of CO2 could occur;

− the flare stack, where emissions might occur due to the application of continuous positive purge systems (thus capturing the fugitive losses from the oil-gas separation plant) and under blowdown conditions during depressurisation of the oil production installation;

− the onsite power plant, where the power plant is using indigenous field gas to power operations, which will be co-mingled with the injected CO2.

− a dedicated CO2 purge system, which may be necessary as routing high concentration CO2 gases into a flare system will extinguish the flare.

These emission sources are summarised below (Figure 3.5)

37

*Note: fugitive emissions of CO2 and hydrocarbon gas mixtures will in nearly all cases be caught in the gas

containment system and released via the flare/purge safety system, as opposed to vented to atmosphere.

Figure 3.5. Emission Sources for EOR Operations Operators should identify all emissions sources linked to the EOR activity and list them combustion and fugitive and vented emissions sources. The operator should determine whether identified emission sources fall within the scope of activities listed within Annex I of Directive 2003/87/EC. These could include the onsite power plant used to generate power for oil production operations, and the flare stack used to combust waste and purge gases from production operations.

[4.]2. Calculation of CO2 Emissions

[4.]2.1. Generation of CO2 From Combustion Combustion emissions shall be calculated in accordance with Annex II [of Decision 2007/589/EC]. In order to ensure that the relevant concentrations of CO2 are used for the calculation of emissions for these sources, all calculations should apply Tier 3 activity data requirements as laid down in Annex II [of Decision 2007/589/EC].

[4.]2.2. Fugitive and Vented Emissions Where the EOR operation requires the application of a dedicated CO2 purge vent as a replacement or in conjunction with a flare system, emissions from this source should be calculated in accordance those laid down for Flares in Annex II [of Decision 2007/589/EC]. Where other fugitive emissions sources may occur absent of being routed to the purge vent or flare stack, these should be calculated using a mass balance approach. Operators should outline relevant approaches to calculate other fugitive emissions sources, cognizant of the linkages between fugitive emissions on equipment and other emission sources

Oil reservoir

Injected CO2 stream Produced oil

Oil-gas separators

Onsite power plant

CHX + CO2

Flare stack

CHX + CO2

CO2 purge system

CO2 + CHX

CO2 recycle CO2 + CHX

TO ATMOSPHERE

Fugitive emissions*

CO2 + CHX

Breakthrough CO2 plus

other hydrocarbon

gases (CHX+CO2)

38

present on a production platform (e.g. the flare, purge vent, onsite power plant sources) and also taking into account the amount CO2 re-injected into the storage site. Approaches developed should be consistent with the mass balance approach given below:

CO2 emissions [tCO2] = E CO2 – I CO2 Where;

- E CO2 [tCO2]: mass of CO2 produced in association with oil, measured at the oil and gas separation stage

- I CO2 [tCO2]: the total mass of CO2 emitted via other emission sources or re-injected into the geological storage installation

These should be calculated in accordance with the procedures described above.

39

Appendix A: Emissions Sources in CCS Projects

A.1 Emission Sources Across a CCS Chain

Capture, transportation, injection and storage of CO2 as part of a CCS chain presents a number of opportunities for both the operational, accidental and background emissions of CO2. These can all be broadly categorised as fugitive emissions, in accordance with IPCC 1996 Guidelines on National Inventories (33). The use of energy-intensive equipment and processes for CCS, such as capture, compression and injection, also presents opportunities for direct and indirect emissions of CO2 to occur. Emissions sources across a CCS chain have been summarised by Haefeli et al (34) as shown below (Figure A1.1).

Figure A1.1. Potential Sources Emissions To Be Monitored Across a CCS Chain (Source: Haefeli et al (2003))

Depending on the accounting rules of the relevant emissions trading scheme – in this case the EU ETS – some or all of these emission sources may need to be monitored and reported. The different sources of CO2 emission that could occur across a CCS chain, and their relevance to CCS accounting rules, are reviewed in greater detail below. This includes a detailed discussion of specific issues presented by enhanced oil recovery (EOR) using CO2.

A.1.1 Direct Emissions (Fuel Combustion)

Direct emissions refer to emission sources across the chain arsing from the primary combustion of fossil fuels as part of the activity. Emission sources include:

(33) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories. IPCC (1996) (34) Haefeli, S., Bosi, M., Philibert, C. Carbon dioxide capture and storage issues – accounting and baselines under the United Nations

Framework Convention on Climate Change (UNFCCC). International Energy Agency, Paris, 2004.

40

⇒ Emissions from the installation generating the CO2 due to imperfect capture of the CO2 or planned or emergency shutdown of the CO2 capture plant;

⇒ Energy required to power CO2 capture facilities;

⇒ Emissions from gas-fired booster stations along the CO2 transport pipeline;

⇒ Emissions from any combustion installations generating power at the injection facility; Careful consideration is needed regarding whether all of these emission sources fall within the scope of the EU ETS monitoring and reporting requirements, as discussed below. CO2 generated from biomass combustion CO2 emissions from the combustion of biomass are considered to have a zero-emission factor in emissions accounting protocols (35). On this basis, it is arguable that emissions of CO2 from biomass combustion which are captured and stored should give rise to negative emissions (ie emissions below zero). This issue is discussed in greater detail in Appendix B. The energy penalty for CO2 capture Application of CO2 capture technologies presents a significant auxiliary energy penalty on the installation employing the plant, resulting in higher specific CO2 emissions generated per unit output of the installation relative to a standard configuration. Primarily, this is a result of:

⇒ the use of electrical power for fans, pumps, compressors etc and other mechanical drives associated with the CO2 capture plant;

⇒ energy requirements for oxygen production (eg for cryogenic air separation) in oxyfuel systems;

⇒ the use of steam for solvent regeneration in pre- and post-combustion capture systems; and,

⇒ energy used in pipeline head compressors. Additional emissions generated as a consequence of these operations will be accounted for in the EU ETS through the application of the appropriate monitoring and reporting guidelines applicable to the installation, without the need for additional considerations (36). Essentially, the key issue associated with the energy penalty in the EU ETS is one of allocation. Assuming that allocation will be made on the basis of a comparable installation not employing CO2 capture, then there is no risk of ‘over-rewarding’ the installation by taking into account these extra emissions in its allocation baseline. Working on the basis that the overwhelming amount of these emissions will be captured and stored, and thus not emitted and recognised as such in the EU ETS, then there are no issues presented by the energy penalty under the EU ETS. Treatment of intermediate booster facilities on pipelines There remains some ambiguity about whether intermediate compression stations would be considered to part of a CCS activity/installation under the terms described above. There are several competing views on the matter as follows: 1. That a booster facility is technically connected to a single CCS installation (or a separate

pipeline installation) and therefore its emissions should be included as part of the installations inventory. No additional allocation would be given to cover booster station emissions as, in principle, CCS is near zero-emission technology and no additional allowances should be allocated to the technology; and/or,

(35) Including the IPCC 1996 Greenhouse Gas Inventory Guidelines, and the existing and revised EU ETS monitoring and reporting

guidelines. (36) Assuming that for an incumbent installation retrofitting CCS, a new permit would be issued for the modified installation, the MRGs

would be amended accordingly.

41

2. That a booster facility be treated as installation in its own right if it exceeds the 20MW rated thermal input threshold in Annex I of Directive 2003/87/EC, or be totally excluded from the accounting regime if it is below this threshold; and/or,

3. An alternative might be that smaller booster stations (<20MW) are included as per point 1. with or without an allocation, whilst larger (>20MW) plant are included in their own right as separate combustion installations. However, this would be difficult to implement in practice due to the creation of a perverse incentive to build larger turbines in order to gain an allowance allocation.

In the previous study by ERM and DNV on inclusion of CCS in the EU ETS, it was concluded that emissions from any gas powered booster stations on the pipeline would not be reconciled with the exporting installation (ie be excluded from its emissions inventory), unless they were qualifying EU ETS installations in their own right (ie as combustion installations with a rated thermal input greater than 20MW). However, considering the full chain of activities may be opted-in as one or several separate installations via Article 24, then there is probably a need to consider emissions from such installations in a different way, based in the installation definition provided for in the ETS Directive (Box A1.1).

Box A1.1. Definition of an Installation Under Directive 2003/87/EC As the booster station would be a directly associated activity with a technical connection to the transporting installation (ie the pipeline), and they could have an effect on emissions, then it seems emissions from this source would need to be included in the overall scheme inventory. The question on whether these installations would or would not receive additional allocation remains open-ended, and is a matter of policy which may be best resolved through stakeholder consultation. One issue to consider on this matter is that compression facilities at a combustion installation employing CCS would not receive any additional allocation, and thus providing extra allowances for booster stations may incentivise operators to move the compression facility at the pipeline head outside of the combustion installation in order to receive an allocation (37). Further considerations on this matter also include that:

⇒ it may be effective to provide zero allocation to booster stations along the pipeline such that it could conceivably incentivise operators to capture additional emissions from these sources; and,

⇒ these concerns would become largely irrelevant under a allowance auctioning system.

A.1.2 Fugitive Emissions (Venting and Leaks)

Emissions of CO2 could occur as part of routine operational activities involved with CCS. Reasons might include:

⇒ leaks in CO2 capture system;

⇒ emissions from solvent stripping operations, including imperfect stripping of the solvent;

(37) Which may not be the optimal design for the plant in terms of configuration and efficient use of energy, although this could

conceivably be caught under future IPPC permitting considerations.

Article 3 Definitions ‘installation’ means a stationary technical unit where one or more activities listed in Annex I are carried out and any other directly associated activities which have a technical connection with the activities carried out on that site and which could have an effect on emissions and pollution;

42

⇒ pipeline maintenance, repair or blowdown;

⇒ venting due to overpressure in the pipeline or at the storage site installation due to injectivity problems or routine shutdowns, and;

⇒ inefficiencies and imperfections in CO2 capture and reinjection at the extraction wellhead in EOR activities.

Other sources of emissions across the chain could include background emissions due to:

⇒ leaking seals on blowing equipment required to force the flue gas into the absorption tank;

⇒ leaking seals on solvent stripping tanks;

⇒ leaking seals on compression equipment at the pipeline head;

⇒ pipeline fracture or rupturing;

⇒ leaking seals on pipeline joints and pipeline booster stations;

⇒ leaking seals on injection wellhead compressors, and;

⇒ leakage from improperly sealed injection wellheads. All of these emission sources should be monitored and accounted for within the EU ETS. Leaks from CO2 pipelines The 2006 IPCC GLs outline an emissions factor based approach for calculating CO2 emissions from CO2 pipelines. Whilst such an approach may be appropriate for compiling national greenhouse gas inventories linked to CCS operations, it is not appropriate for application in the EU ETS MRGs. This is because it would essentially impose a default penalty on operators, and would not be able to account for actual emissions above or below the emission factor used. This could actually result in emissions from pipelines not being correctly accounted for, and could potentially fail to pick up on vented emissions from pipelines. As such, a direct measurement method is required to ensure more accurate, installation-specific, estimates of vented and fugitive emissions from CO2 pipelines. Leakage from storage reservoirs Storage of CO2 in subsurface geological formations presents potential opportunities for leakage to occur through a range of CO2 leakage pathways. The 2006 IPCC GLs, Volume 2, Chapter 5, identify the following potential emission pathways from geological reservoirs:

• Direct leakage: operational or abandoned wells, well blow outs, future mining

• Natural leakage and migration: through the pore system, in the absence of the caprock, via a spill point through overfilling of the reservoir, through a degraded caprock, dissolution into pore fluids;, via induced faults or fractures.

• Other fugitive emissions: displacement of other formation fluids (eg CH4) (38) Natural analogues have demonstrated the ability of geological reservoirs to retain CO2 indefinitely or very long periods of time. The capacity for long-term storage depends strongly on the specific characteristics (primarily the trapping mechanisms present) of the storage reservoir into which the CO2 is being injected. Although short-term leakage could occur in some storage sites during early phases of injection due to changing parameters in the reservoir such as pressure most experts believe that properly selected reservoirs could store CO2 securely for very long periods of time. In this context, the IPCC SRCCS concluded that:

(38) This issue only becomes relevant in the EU ETS if CH4 is brought into the scope of the scheme.

43

Observations from engineered and natural analogues as well as models suggest that the fraction retained in appropriately selected and managed geological reservoirs is very likely to exceed 99% over 100 years and is likely to exceed 99% over 1,000 years. (SPM, Point 25, pg. 14)

As such, it is probably most effective to consider that CO2 injected into geological storage sites is not emitted, and will not be emitted in the future, rather than trying to account for these emissions in some form of present day value (eg through application some kind of default or discounting approach which ring-fences a fixed amount of emissions that are not recognised as emissions reduced in order to provide for a contingency in the event of future possible leakage). It is particularly challenging in a policy context to try and apply a generic default or discount factor as there is no clear basis upon which to develop such a factor. Indeed, the IPCC SRCCS suggests that:

Today, no standard methodology prescribes how a site must be characterized. Instead, selections about site characterization data will be made on a site-specific basis, choosing those data sets that will be most valuable in the particular geological setting. (Chapter 5, Section 5.4.1.1, pg. 225)

Implying that it will not be possible to use generic default factors applicable to all storage sites. Moreover, the IPCC SRCCS also implies that the possibility of leakage is in fact a function of appropriate site selection and management, rather than any standard rate function. Therefore, assuming the implementation of an effective regulatory scheme governing site selection and management, then this consideration should be the basis for including CCS in the EU ETS (39). Notwithstanding this conclusion, there remains a challenge in determining how the applicable timeframes in the EU ETS (eg annual accounting and reconciliation; five year periods) are can be aligned with the time frames associated with the potential for CO2 leakage to occur (100’s to 1000’s of years;).

(39) In this context, the EC is presently drafting regulatory proposals for the selection, operation, closure and after-care considerations

for geological CO2 storage sites in the EU.

44

Figure A1.2. Milestones in a CCS Chain Under Emissions Trading Schemes The most practicable solution for accounting for this temporal disjoint with the EU ETS will be to combine:

• effective regulatory controls on site selection and operation within the EU;

• effective monitoring of CO2 storage sites under the EU ETS via appropriate monitoring and reporting guidelines, with annual reporting in order to account for any leakage occurring, and

• any emissions arising from storage site leakage must be estimated and reconciled against any quantities of CO2 calculated as non-emitted by the source installation.

Storage site boundaries Identification of the potential leakage pathways for a particular CO2 storage site – as described above – forms the basis for delimiting the boundaries for a CO2 storage site. The nature and location of these pathways will vary from site to site, and therefore must be determined on a project specific basis, based on the individual characteristics of the storage site in question. They are also dependent on how the storage site will behave over time as a consequence of filling with injected CO2, which can only be predicted through computer reservoir simulation modelling. The objective of modelling is to predict how injected CO2 will behave over time, and also how the containing elements of the storage site might react to the injection of CO2. It should also establish the ultimate maximum lateral and vertical boundaries of the of the injected CO2 plume upon cessation of injection.

Milestones in a CCS project

Number of years 1 10 100

5 year

periods of the

EU ETS

Project based mechanisms

e.g.CDM crediting periods of

7-10 years

Detailed storage site

assessment: every 10

years+?

Handling of long-term liability for a

storage site by a host government.

Transfer of liability or end of

licensing period

50-500 years?

Possibility of seepage of CO2 back to

the atmosphere over

geological timescales?

1 year

surrender EUAs annually under the

EU ETS.

The EU ETS Compliance year

Calendar / Compliance Year Previous year Current Compliance Year Following Year

Month Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr

1 Jan

Compliance

year begins

28 Feb

EUAs must be

issued by this

deadline

30 Apr

Surrender EUAs

for previous

compliance year

31 Dec

Compliance

year ends

31 Mar

Deadline for verification

of Monitoring Report for

previous year

31 Mar

Deadline for verification

of Monitoring Report for

current year

30 Apr

Surrender EUAs

for previous

compliance year

The reconciliation period

for trading to comply in a

prior year is 1-30 April in

the following year.

45

Thus, a key objective in developing MRGs for CO2 storage sites is the establishment of a common procedure for defining potential leakage pathways, and arriving at the description of the storage site boundaries. The potential leakage pathways – as well as forward modelled estimates of the maximum lateral and vertical extent of the injected plume of CO2 – will form the basis for the defining the below-ground monitoring scheme applicable to the storage site. The storage site boundary must also include all above-ground elements that could lead to CO2 emissions.

A.1.3 Indirect Emissions (from bought-in power)

These relate to those emissions created by a CCS chain, but actually occur outside its immediate boundaries. Principally these relate to any imported electricity used for the activity, or the emission sources that the activity might create or displace. These might include:

• indirect CO2 emissions associated with bought-in electricity or steam used for capture, transport or injection of CO2;

• indirect CO2 emissions associated with the energy used in manufacture of CO2 stripping agents;

These emission sources are not considered relevant under EU ETS accounting rules for the following reasons:

• Where the components of CCS scheme are powered by bought-in electricity, this electricity is likely to have been generated at another qualifying installation included under the EU ETS eg an incumbent combustion installation. Its inclusion in the proposed methodology for an installation using CCS would represent ‘double counting’ of emissions in the EU ETS. This is consistent with the requirements of Draft Phase II MRGs, which states that:

Emissions associated with the production of heat or electricity imported from other installations shall not be assigned to the importing installation. (Section 4.2, pg. 17).

The CO2 emissions associated with the manufacture of CO2 stripping agents is not considered relevant under EU ETS rules. Moreover, it is likely that these agents will have been manufactured at a site qualifying as an installation under the EU ETS (such as a large chemicals manufacturing plant), and therefore, could also represent double counting.

A.1.4 Emissions of Breakthrough CO2 in Enhanced Oil Recovery

Installations undertaking enhanced oil recovery (EOR) using injected CO2 will present additional emission pathways and sources relative to standard CO2 storage operations. This arises as a consequence of the injected CO2 breaking through with the produced hydrocarbons. In principle, operators will separate out the breakthrough CO2 and reinject it with incoming captured CO2 from the pipeline. However, there will remain opportunities for emissions of to breakthrough CO2 occur across the system through a variety of different pathways. Key emissions sources for CO2 EOR operations include:

⇒ the oil-gas separation units and gas recycling plant, where fugitive emissions of CO2 could occur;

46

⇒ the flare stack, where emissions might occur due to the application of continuous positive purge systems (thus capturing the fugitive losses from the oil-gas separation plant) and under blowdown conditions during depressurisation of the oil production installation;

⇒ the onsite power plant, where the power plant is using indigenous field gas to power operations, which will be co-mingled with the injected CO2.

⇒ a dedicated CO2 purge system, which may be necessary as routing high concentration CO2 gases into a flare system will extinguish the flare.

A potentially further complicating factor for EOR operations is that injected CO2 will breakthrough mixed with indigenous reservoir CO2. In such cases, it is important to consider whether the indigenous reservoir CO2 constitutes a “regulated” emission under the EU ETS, or whether there is need to account separately for the indigenous CO2 compared with the breakthrough CO2.

Figure A1.3. Emission Pathways for EOR Operations *Note: fugitive emissions of CO2 and hydrocarbon gas mixtures will in nearly all cases be caught in the gas containment system and released via

the flare/purge safety system, as opposed to vented to atmosphere.

The additional emission pathways will all need to be included in a monitoring and reporting scheme for CCS activities involving EOR. However, notwithstanding such a conclusion, there are several factors that need to be taken into consideration, as follows:

⇒ The onsite power plant at oil production installations (certainly for offshore installations on the UK continental shelf) are incumbent qualifying installations under Annex I Energy Activities – Combustion installations of Directive 2003/87/EC;

⇒ Flares are also captured under Energy Activities – Combustion installations in Annex I for Phase II of the EU ETS;

⇒ Conceivably, a dedicated CO2 purge source could also be captured in Annex I on the same basis as the flare, albeit with a need to clarify the definition of a flare or flare gas to also recognise non-combusted and/or vented emission sources;

⇒ For occupational health and safety reasons, all offshore platforms have a gas containment system with a positive purge system incorporated to prevent the accumulation of hydrocarbon

Oil reservoir

Injected CO2 stream Produced oil

Oil-gas separators

Onsite power plant

CHX + CO2

Flare stack

CHX + CO2

CO2 purge system

CO2 + CHX

CO2 recycle CO2 + CHX

TO ATMOSPHERE

Fugitive emissions*

CO2 + CHX

Breakthrough CO2 plus

other hydrocarbon

gases (CHX+CO2)

47

gases which pose an explosion risk on the platform. For this reason, any fugitive emissions across the gas handling system will be routed to the flare or gas purge system, and thus do not represent an additional emission source on the installation.

Based on these conditions, a brief example of how emissions accounting for an installation employing EOR could work in practice, based on the BP Miller platform, is outlined below. EOR accounting in practice The Miller field is owned and operated by BP, and forms the cornerstone of the planned DF1 project, where CO2 from the Peterhead power plant will be captured and exported offshore via a pipeline to the Miller field. The exported CO2 will primarily be stored in conjunction with EOR operations. At Miller, the onsite power is provided by three duty gas-turbine power generation plants plus a peak load lopping turbine. The total installed capacity is approximately 3 x 100MW net rated input and 1 x 20 MW rated thermal input respectively. All turbines are presently powered by field gas arriving on the platform in association with produced oil (associated gas). Field gas from Miller already contains around 25% CO2, which is naturally occurring in the reservoir. All turbines are qualifying installations under Annex I of Directive 2003/87/EC Energy activities – Combustion installations, and therefore emissions from these units are all included under the EU ETS. The turbines give rise to around 160,000-200,000 tCO2/yr (40), which makes it a Category B installation under EU ETS Monitoring and Reporting Guidelines minimum requirement rules. This has consequences for the way emissions from the turbine are calculated as described below (Box A1.2).

Box A1.2. Current accounting of emissions from the power plant on the Miller platform The Miller platform also operates gas flare for safety reasons, which combusts around 45,000-120,000m3 of purge gas/yr, giving rise to 50,000-100,000 tCO2/yr in flare gas emissions. This also means that it falls within Category B under the EU ETS Monitoring and Reporting tier system, and is subject to the same monitoring and reporting procedure as described above (Box A1.2). Upon commencement of the CO2 EOR flood, the platform will continue to operate the same gas management regime. It is anticipated that breakthrough CO2 will be received at the platform for the first time approximately 3 years after commencing the CO2 flood. Following this, a continued upward trend in the volume of breakthrough CO2 is anticipated, leading to an increasing ratio of CO2 to indigenous field gas (from the initial base of 25% naturally occurring in the field gas). After a period of time, the field gas will contain too high a fraction of CO2 to be combustible, at which point, gas for field power will be imported, and all the produced field gas will be reinjected into the reservoir (Figure A1.4). Fugitive emissions, routine platform blowdown, and emergency releases

(40) Based on UK National Allocation Plan data.

As the both the Miller power plant and flare qualify as Category B minimum requirement rules, emissions are calculated using Tier 2a/2b activity data and/or emission factor approaches. This means that the gas is not directly analysed for monitoring and reporting purposes, but emissions are calculated based on the country specific net calorific values or supplier data (the latter is not relevant in this context). Consequently, the 25% CO2 content of the field gas is unlikely to be presently picked-up in the current Miller CO2 emissions accounting regime, and therefore, for all intents and purposes, does not constitute regulated CO2 in the EU ETS. In order to recognise the breakthrough CO2 in the power plant emissions, it is likely that a Tier 3 minimum requirements activity data and emissions factors will need to be applied. Tier 3 requires installations to directly sample fuel and determine its net calorific value, carbon content and emission factor according to standardised methods (see Section 13 of Annex I of the draft EU ETS MRGs for Phase II).

48

will continue to route the field gas to the flare or CO2 purge system, and therefore also continue to be monitored and reported under the EU ETS.

Figure A1.4. Field gas composition over time at Miller (illustrative) Under this gas management regime, all emissions of breakthrough CO2 will be effectively captured within the scope of the EU ETS as combustion emissions from either the onsite power plant or the flare stack. As a consequence, no new emissions sources are presented by breakthrough CO2, and therefore the environmental integrity of the scheme will be maintained ie no additional emission sources need to be included in the monitoring and reporting plan for the Miller platform specific to the EOR operation. Furthermore, as these emission sources are already in essence accounting for indigenous reservoir CO2 – albeit with some potential gaps associated with the way gas analysis is applied – then no additional complications arise regarding the split between “regulated” and indigenous CO2 ie the indigenous CO2 is already regulated as part of these emission sources. Notwithstanding this conclusion, a number of additional elements will need to be incorporated in the monitoring and reporting guidelines to ensure effective accounting of emissions of breakthrough CO2, as follows:

• Dedicated CO2 purge vent: any new CO2 purge vent will need to be monitored and reported under the EU ETS to ensure this emission source is accounted for in the monitoring and reporting protocol. For simplification, it is probably fair to consider a CO2 purge vent in the same way as a flare. In this context it is useful to note that the Norwegian Regulations Relating to Measurement of Petroleum for Fiscal Purposes and for Calculation of CO2-tax (The Measurement Regulations), 1 November 2001, NPD define “flare gas” as:

0%

50%

100%

Cessation of indigenous

gas use

Fie

ld g

as c

ompo

sitio

n (%

) USE STORAGE

CHX

injected

Indigenous CO2

Injected (breakthrough) CO2

Indigenous CHX

0 30 Time (years)

Breakthrough CO2 first

detected

Breakthrough CO2 to

onsite power plant

All breakthrough

CO2.

No indigenous

gas.

All reinjected

49

Flare gas: Natural gas burnt off or vented to the atmosphere.

This definition provides coverage for both venting and flaring operations, and could be adopted as the basis for including any vent streams on the same basis as flares. Presently the Phase II Monitoring and Reporting Guidelines do not include any definition for flares or flare gas.

Gas analysis: in order to ensure trueness in the monitoring and reporting of emissions from EOR operations it will be necessary to apply Tier 3 minimum requirements for activity data and emission factor. This will ensure that field gas used in combustion installations (both the power plants and flare or vent systems) accurately records the quantities of breakthrough CO2 emitted to atmosphere from these sources.

50

51

Appendix B: Biomass and CCS

In respect of CO2 generated from biomass combustion, the 2006 IPCC GLs, Volume 2, Chapter 5 suggests that:

Negative emissions may arise from the capture and compression system if CO2 generated by biomass combustion is captured. This is a correct procedure and negative emissions should be reported as such.

This implies that captured and stored CO2 generated from biomass combustion could be reported as a negative emission. As such, governments adopting the 2006 IPCC GLs to report national greenhouse gas emissions would be positioned to benefit from the application of CCS from biomass emissions (41). Notwithstanding this possibility, it is unclear how such benefits could be passed on to business through the EU ETS. This is because under the EU ETS, the maximum benefit for an installation in the scheme is realised when emissions equal zero, rather than any additional benefits being available for going below zero (ie negative emissions). In order for the benefit to accrue to the installation, there would need to be a credit system in place that could monetise negative emissions (eg through allocation of allowances back to operators). Whilst this is conceivable, it would present additional accounting problems in so much as a baseline would need to be established in order to account for the energy penalty associated with CCS. In dealing with similar issues posed by the Transferred CO2 provisions in Decision 2007/589/EC (42), the following is applied:

In instances, in which part of the transferred CO2 was generated from biomass, or whenever an installation is only partially covered by Directive 2003/87/EC, the operator shall subtract only the respective fraction of mass of transferred CO2 which originates from fossil fuels and materials in activities covered by the Directive.

This implies that negative emissions linked to transfer (and by extension, storage) of emissions of CO2 from biomass combustion cannot be credited under the EU ETS at present.

(41) In other words, governments of countries where CO2 generated from biomass combustion is being captured and stored could report

these a non-emissions in accordance with 2006 IPCCGHG Inventory Guidelines, and thus report negative emissions from such

activities. Consequently, national governments could potentially trade Assigned Amount Units during the Kyoto compliance period on

the back of the related negative emission reductions. The 2006 IPCCGHG Inventory Guidelines have not yet been formally approved by

Parties to the UNFCCC and Kyoto Protocol. (42) Section 5.7

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