Phase II Monitoring, Reporting and Verification for Offshore Facilities: “Frequently Asked Questions”

Department of Energy and Climate Change

January 2009

MRG2007 FAQ Version 1.0 January 2009

Table of Contents

General

M&R Plans

Activity Data

Emission factors, fuel compositions and net calorific values

Oxidation factor

Reporting

Verification

The Verification Opinion Statement (VOS)

The Registry

Annual Improvements Report

Greenhouse Gas Emissions Permits

Qualifying Installations and Combustion Plant

Permit Variations

General

  1. What and who is this Q and A for?

This Q and A is to assist operators to prepare for, and verifiers to carry out, the annual verification process for the EU Emissions Trading Scheme (EUETS).

Annual verification involves an independent review by an accredited verification body (the verifier) of the annual emissions determined by the operator. The verifier also checks that the monitoring and reporting has been performed in accordance with the requirements in the facility’s Greenhouse Gas Emissions Permit, the Phase II Monitoring and Reporting Plan (M&R Plan) and the Commission’s revised Monitoring and Reporting Decision (herewith referred to as MRG 2007).

This Q and A is intended to supplement the “Guidance on Annual Verification for the EU ETS (August, 2005), a Quick Reference Guide for Operators” which is available at:

Where this Q and A contradicts that guidance, operators and verifiers should use this Q and A as the basis for the Monitoring, Reporting and Verification for the Phase II Annual Emissions Report for Offshore Facilities.

  1. Who should I contact to answer further questions?

Any queries about monitoring, reporting and verification that are not addressed in this Q&A should be directed to:

or

(website:

Any queries in relation to verification body accreditation should be directed to the UK Accreditation Service (UKAS), via:

(website:

M&R Plans

  1. Some M&R Plans do not seem to be dated, so it’s difficult to ascertain which is the current and/or approved version. How can verifiers be sure which version is the most current?

The most recent approved version of the M&R Plan will have been used to draft Appendix 2 to the Permit, so the documents can be cross-checked. Where Appendix 2 does not reflect the M&R Plan, the operator should be able to provide documentary evidence relating to the approval of any differences in Appendix 2. Operators are required to incorporate changes to Appendix 2 in their M&R Plan, but there may be cases where the update of the M&R Plan is still outstanding. If in doubt, the DECC Environmental Management Team (EMT) will be able to confirm whether a variation to the Permit was requested that is not reflected in an amendment of the M&R Plan. If there has not been a formal request for a variation to the Permit, the original M&R Plan will still be valid, and EMT will be able to provide a copy of that Plan. If inconsistencies are noted and the operator cannot provide documentary evidence to explain the differences, clarification should be sought immediately from EMT, to avoid an unnecessary delay in the verification process. If inconsistencies are noted, it is important to remember that,for the purpose of verification, the M&R Plan has no legal status, and that the operators are being assessed against the obligations detailed in Appendix 2 to the Permit.

Activity Data

  1. What is the acceptable Activity Data Tier for flaring

All operators are expected to meet Tier 1 requirements (17.5%) for the reporting of 2008 flare emissions unless otherwise agreed with EMT. Many will have committed to meet Tier 2 (12.5%). All operators will be expected to meet Tier 2 requirements by the end of 2009.

  1. Do I need to report volumes in SI units (273.15 k and pressure conditions of 101.325 Pa)?

The offshore sector reports volumes in standard units defined at 15C and 1.01325 bar. However, if you are reporting gas volumes in EU ETS returns, these should be expressed in SI units to avoid confusion when compared against numbers reported by other EU ETS sectors. The CO2 emission factor used offshore is based on mass and there is no need, in calculating this factor, to change from the current use of standard units.

Guidance on conversion can be found at:

  1. Are there standard or default conversion factors for fuels, to convert from cubic metres to tonnes etc.?

Conversion factors for gas use on offshore facilities should be based on the fuel composition / density measurements, and it is inappropriate to use industry standard or default factors.

  1. Is it acceptable to base fuel gas usage and CO2 emissions calculations on equipment load data, rather than on metered fuel gas volumes?

Fuel gas use should be based on metered volumes. In some circumstances operators can use load / running hours: however, operators will need to demonstrate to the satisfaction of the verifier that the load / fuel usage curve has been calibrated under realistic operational conditions and remains valid, and that the running hours at each load are accurately recorded. Depending upon the quality of the data, this methodology could be used for both Tier 2 and Tier 3 reporting.

Emission factors, fuel compositions and net calorific values

  1. Can calculations be carried out using an emission factor based on tCO2/t fuel, rather than tCO2/TJ?

Yes. The UKOOA EEMS methodology uses a factor based on tCO2/t fuel, and this sort of emission factor is therefore standard practice for offshore facilities. Section 4.2.2.1.6of the M&R Decision confirms that:

‘An operator may use an emission factor for a fuel expressed as carbon content (tCO2/t) rather than tCO2/TJ for combustion emissions if he demonstrates to the competent authority that this leads to a permanently higher accuracy. In this case the operator shall nevertheless periodically determine the energy content to meet his reporting requirements as specified in section 5 of this Annex’.

Operators should note that they are still required to report the Net Calorific Value of the fuels in the Annual Emissions Report (see Question 19 below).

  1. Is it acceptable to use the fuel gas emission factor detailed on the DEFRA website?

As offshore fuel gas compositions vary from facility to facility, and can also change over time, it is considered inappropriate to use an industry standard or default Tier 2 emission factor. The default Tier 2 emission factors, taken from the UK Greenhouse Gas Inventory (and listed on the Defra website), are therefore considered to be inappropriate for calculating emissions from offshore facilities, as they could lead to erroneous reporting of emissions.

Offshore facilities were required to have implemented Tier 3 emission factors by the end of Phase I of the EU ETS, and are therefore required to use Tier 3 emission factors for the reporting of 2008 emissions. This requires sampling and analysis of the fuel gas to determine site-specific emissions factors (see Question 10 below).

  1. What is an acceptable sampling and analysis frequency for measuring the fuel gas composition?

Facilities using the recommended Tier 3 emission factor must, as a minimum requirement, collect and analyse representative samples of the fuel gas stream(s) every calendar quarter. It is recommended that is if there is evidence of a fluctuating fuel gas composition (e.g. fuel switched from different sources), or in response to any significant change that is considered likely to affect the fuel gas composition (e.g. bringing on a new field), samples should be collected and analysed more frequently.

The requirement is for a minimum of four samples per annum spread equally throughout the calendar year. In some instances this may not be feasible (such as during unplannedshutdowns) and sampling may be missed or delayed. In these cases the operator should inform EMTby email as soon as they are aware that the sample has not been taken; informing EMTof the reason for the delay/omission and providing justificationfor any temporary variation tothe requirement for quarterly sampling.

Note that some verifiers have requested evidence that quarterly sampling is sufficient to meet the uncertainty requirements of the EU ETS, i.e. to demonstrate that changes in the gas composition have not significantly change the derived CO2 factor. In response to this, DECC has agreed to develop a spreadsheet that operatorscan complete and submit to EMT with the annual returns. Pending completion of the spreadsheet, operators should continue to sample in line with the requirements detailed in the Appendix 2 to the Permit, and it can be assumed that EMT is satisfied that the gas composition is sufficiently constant to ensure that the sampling frequency is appropriate to meet the uncertainty requirement

The requirement to use laboratories accredited to EN ISO 17025:2005 has been changed to a preference rather than a statutory obligation, but the operator must demonstrate to the competent authority that the laboratory meets equivalent requirements to those set out in EN ISO 17025:2005. Whether it is a statutory obligation will be confirmed in Appendix 2 to the Permit

  1. If it is necessary to collect a gas sample using a 'gas sampling cylinder’, is there any defined standard for these gas cylinders (in terms of their make, design, etc.) and are there standard procedures relating to how the sample must be obtained?

Suppliers of gas sampling cylinders can be found by searching the Internet. Any cylinders used should comply with Directive 1999/36/EC, the Transportable Pressure Equipment Directive (also known as the TPED), implemented in the UK as The Carriage of Dangerous Goods and Use of Transportable Pressure Equipment Regulations 2004.

Operators should be able to obtain advice from their analytical laboratory on the choice of sampling cylinder and, if necessary, guidance and training relating to sample collection. There is also an ISO standard which gives general advice on sampling (ISO 10715). In some cases, the analytical laboratory may require the operator to use the laboratory’s sample cylinders, and may insist upon collection by the laboratory’s staff.

  1. Is the expectation that operators should use the results of the fuel gas sampling and analyses to update emission factors?

Operators must base the emission factors on a representative fuel gas composition. This can be handled in a number of ways (for example):

  1. Use the standard, or reference, composition each year, comparing the results of the analyses with the standard composition on an annual basis to confirm that there is no significant difference. Existing industry tools (such as the EEMS database) can handle this method, and it is a pragmatic approach. However, it will be necessary to change this approach if there is a confirmed significant change in the fuel gas composition that would result in a material misstatement of reported emissions of carbon dioxide.
  2. Retrospectively calculate the emission factor based on the average composition determined during the year. This will not be ideal for operators who routinely calculate and report emissions on a monthly or quarterly basis, as the total emissions would have to be recalculated and adjusted at the end of each year when the average composition data is available.
  3. Update the emission factor quarterly on the basis of each set of analyses, and apply that emission factor until the results of the next quarterly sampling and analysis exercise are available. Existing industry tools (such as the current version of the EEMS database) may not be able to handle this approach.

The EMT recommended approach is that operators should use an annual average composition, checked and amended if appropriate for each calendar year, providing this would not result in a material misstatement of reported emissions of carbon dioxide, and that this can be demonstrated to the satisfaction of the verifier.

  1. Can the fuel gas composition be applied annually in arrears?

This is acceptable, providing there is no significant change in the fuel gas composition that would result in a material misstatement of reported emissions of carbon dioxide. If there such a change, then the updated composition should be used from the date that the change in operation occurred or the change is the fuel gas composition is recorded. The results of subsequent analyses should then be used to calculate a new annual average composition and emission factor.

  1. I have some source streams on my installation that are de minimis and used infrequently do I need to account for these in my annual returns

Some installations hold small quantities of gas, such as cylinders of propane, that are used infrequently offshore and contribute a small fraction of the overall emissions of CO2. Where no monitoring methodology is specifiedfor a de minimis source, verifiers should check that the emissions havebeen calculated on a fair and reasonable basis that does not lead tomaterial error, and they should recommend that the operator confirm theirchosen approach with the regulator.

Operators are therefore expected to include these sources within their M&R plan and to calculate emissions from them on a fair and reasonable basis. In the case of the propane cylinders this may be estimated based to content (in tonnes) divided by the likely replacement frequency (in years). Notwithstanding this, where these sources have not been included as a Schedule 1 activity, verifiers should note this in the improvements section of the verification report, and should consider whether it affects materiality of the data.

Verifiers do not need to recommend improvements to sources listed asde minimis. Instead, efforts should focus on recommendingimprovements to the monitoring of larger emission sources on a site.

  1. Is the expectation that operators should use the results of the flare gas sampling and analyses to update emission factors?

The situation for flare gas is similar to that described above for fuel gas but complicated by the potential variation in the source of gas and, therefore, its composition. In addition, each platform will have its own flare profile which may also vary from year to year.

In general, gas to flare arises from three main sources:

  • Pilot & Purge
  • Operational/plant Trips
  • Emergency shutdown/process trips

In many cases fuel gas is used for pilot and purge and therefore the gas composition will be known; however for operational trips and shutdowns it may not be possible to measure the gas composition. In these cases it is acceptable to use data based on the condition of the processing plant and/or source prior to flaring, combined with process modeling to determine the relevant CO2 factor. Whichever method is used, operators should submit information on their proposed approach to EMT for approval.

Additional information on approaches to flare gas measurement can be found in the flare consent application documentation at:

  1. Can modeling be used in place of a flare gas meter to determine activity data?

The Department’s preference is for the installation of flare gas meters but it is accepted that, for some installations, these may not meet the required turndown or that it may not be physically possible and/or cost effective to install and maintain a flare gas meter. In these instances, it is acceptable to adopt a flare gas measurement system based on monitoring of process operating conditions and control element positions, provided this can be shown to achieve an acceptable degree of uncertainty in flare reporting. In some cases, operators have adopted both approaches.

  1. What are the requirements for maintenance and calibration of gas chromatographs offshore?

Gas chromatographs (GCs) are often installed offshore for fiscal gas quality measurement, and the requirements for maintenance and calibration of fiscal measurement systems are described in the DECC Measurement Guidelines. There are no specific or additional maintenance and/or calibration requirements for offshore GCs that are also used for EU ETS reporting, but operators will be expected to have complied with the requirements prescribed in the DECC Measurement Guidelines. All records of relevant maintenance and calibrations should be made available to the verifier during the verification process.

  1. Do online analysers and GCs for top tier reporting require calibration by a BS EN ISO/IEC 17025:2005 (ISO 17025) accredited company, as well as the use of ISO17025 accredited reference gases?

Both requirements are considered to be reasonable and appropriate, to satisfy Section 7.2 of the Commission’s M&R Decision. However, operators can make a case for alternative arrangements if current practices do not involve the use of accredited companies or gases. If the operator has not made a case for alternative arrangements, and either the company or the gases used to perform the calibration are not ISO 17025accredited, this should be noted in the Verification Opinion Statement (VOS), and highlighted as a potential improvement. It does not, however, mean that the monitoring undertaken will not have met the requirements of the current tier, and should bedropped to a lower tier and use a standard, or reference, emission factor. Providing that the use of an online analyser satisfies the requirements of the DECC Measurement Guidelines, and the lack of accreditation is unlikely to have led to a material error, the verifier should issue a ‘Verified With Comments’ VOS. If the requirements of the DECC Measurement Guidelines are not being met, the verifier should advise the operator to bring this to the immediate attention of EMT, with a view to resolving the issues before the 31stMarch deadline for submission of the verified Annual Emissions Report.

  1. Why are operators required to determine the Net Calorific Value of the fuel gas?

The Net Calorific Value (NCV) is not required to calculate the emissions, providing the EEMS methodology is used. However, the NCV of the fuel still needs to be determined and included in the Annual Emissions Report, to comply with the requirements of the EU Monitoring and Reporting Decision set out below.

“Emission factors are based on the carbon content of fuels or input materials and expressed as tCO2/TJ (combustion emissions), or tCO2/t or tCO2/m3 (process emissions). Emission factors and provisions for the development of activity-specific emission factors are given in sections 8 and 10 of this Annex. An operator may use an emission factor for a fuel expressed as carbon content (tCO2/t) rather than tCO2/TJ for combustion emissions if he demonstrates to the competent authority that this leads to a permanently higher accuracy. In this case the operator shall nevertheless periodically determine the energy content to meet his reporting requirements as specified in section 5 of this Annex.”