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Department of Trade & Industry - DTI

Report

Offshore Benchmarking Supporting Documentation Genesis Job Number J-70004/A

March 06

http://www.genesisoilandgas.com

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CLIENT: DTI

PROJECT/JOB TITLE: Implementation of EU ETS

DOCUMENT TYPE: Report

DOCUMENT TITLE: Offshore Benchmarking Supporting Documentation

GENESIS JOB NUMBER: J-70004/A

DOCUMENT NO./ FILE NAME: J70004-A-A-RE-001-B1.doc

B1 15/3/06 Issued to Client IS R2 10/3/06 Issued to DTI for Review IS DS

Rev Date Description Issued By Checked By

Approved By

Client Approval

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DTI Offshore Benchmarking Supporting Documentation

Implementation of EU ETS

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Table of Contents

1 BACKGROUND AND SECTOR DESCRIPTION .......................................................... 9 1.1 DESCRIPTION OF UK INSTALLATIONS AND STRUCTURE OF SECTOR............................. 9 1.2 OIL AND GAS PRODUCTION.................................................................................... 11

1.2.1 Emissions from sector..............................................................................................................11 2 SECTOR STATUS IN THE EU ETS: CRITERIA FOR INCLUSION. ........................... 15

2.1 OFFSHORE SECTOR CRITERIA FOR ACCESS TO THE NER........................................ 15 2.2 NOTES ON UNITS OF POWER USED IN THE REPORT................................................. 15 2.3 LIKELY CHANGES IN SECTOR .................................................................................. 16

2.3.1 Known or likely known entrants and retirements ......................................................................16 3 TECHNOLOGY OPTIONS AND EMISSIONS FACTORS........................................... 19

3.1 OFFSHORE GAS AND DIESEL COMBUSTION............................................................. 20 3.2 FUEL CHARACTERISTICS........................................................................................ 22 3.3 BENCHMARKING.................................................................................................... 22 3.4 EMISSIONS FACTORS............................................................................................. 23

3.4.1 Accounting for Diesel Use .......................................................................................................25 3.4.2 Derivation of Efficiency...........................................................................................................26

3.5 UTILISATION.......................................................................................................... 27 3.6 FLARING ............................................................................................................... 28

4 CRITICAL REVIEW OF PHASE 1 BENCHMARKS.................................................... 30 4.1 DETAILED DESCRIPTION OF PHASE I BENCHMARKS .................................................. 30 4.2 SUMMARY OF APPLIED FACTORS ........................................................................... 31 4.3 COMPARISON TO BENCHMARKS USED IN OTHER CONTEXTS, NOTABLY OTHER MEMBER STATES (IF AVAILABLE)...................................................................................................... 31 4.4 STRENGTHS OF PHASE 1 NER BENCHMARKING SPREADSHEET ............................... 31 4.5 WEAKNESSES ....................................................................................................... 32

5 DISCUSSION AND SUGGESTED REVISIONS TO BENCHMARKS ......................... 33 5.1 SPECIFIC FORMULAE ............................................................................................. 33

5.1.1 Efficiency ................................................................................................................................34 5.1.2 Utilisation factor .....................................................................................................................34

5.2 RECOMMENDED CHANGES..................................................................................... 34 6 EVALUATION OF PROPOSED BENCHMARK ACCORDING TO AGREED CRITERIA 35

6.1 FEASIBILITY OF VERIFICATION OF UTILISATION ........................................................ 35 6.2 STANDARDISATION OF THE FUEL FACTOR ............................................................... 35 6.3 COMPARISON OF CO2 EMISSIONS .......................................................................... 35

7 REFERENCES ........................................................................................................... 36



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Table of Figures

Figure 1-1 Schematic of Typical Offshore Installation (UKOOA Website).............................. 9 Figure 1-2 Typical Offshore Production Systems (UKOOA Website) .................................. 10 Figure 1-3 Typical Subsea Development ............................................................................ 10 Figure 2-1 Allocations of CO2 from the Phase 1 NER ......................................................... 18 Figure 3-1 Energy Use on a Typical Platform..................................................................... 20 Figure 3-2 EU ETS Total Carbon Dioxide Emissions from Flaring on Offshore Facilities .... 21 Figure 3-3 Cumulative % Diesel Emissions (2003 EEMS) .................................................. 26 Figure 3-4 Ratio of Minimum and Maximum Emissions 1998 to 2004 ................................. 29 Figure 3-5 Ration of Average and Maximum Emissions...................................................... 29 Figure 5-1 Calculated Range of Molecular Weights ............................................................ 33

Table of Tables

Table 1-1 Historic Emissions from the Offshore Industry..................................................... 11 Table 1-2 Phase 1 Incumbents ........................................................................................... 13 Table 2-1 Phase 1 NER Applications from the Offshore Industry ........................................ 17 Table 3-1 Typical Distribution of Electrical Power demand on an Offshore Platform ........... 19 Table 3-2 Phase 1 plant thermal efficiencies used in benchmark calculation ...................... 23 Table 3-3 CO2 Emission Factor Comparisons (Dry Gas)..................................................... 24 Table 4-1 Calculation of Allocation for New Combustion Installations ................................. 30 Table 4-2 Calculation of Allocation for Existing Combustion Installations............................ 30 Table 4-3 Calculation of Allocation for Existing Combustion Installations............................ 31 Table 4-4 Summary of Phase 1 NER Emission Factors...................................................... 31 Table 5-1 Summary of Offshore Fuel Gas Properties.......................................................... 33



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ABBREVIATIONS

API American Petroleum Institute BOE Barrel of Oil Equivalent BTU British Thermal Unit CNS Central North Sea CO2 Carbon Dioxide DEFRA Department for Environment, Food and Rural Affairs DTI Department of Trade and Industry EEMS Environmental Emissions Monitoring System EPA Environmental Protection Agency EU European Union EU ETS European Union Emission Trading Scheme FPSO Floating Production Storage and Offloading (vessel) GHG Greenhouse Gas GCV Gross Calorific Value (higher heating value) HHV Higher Heating Value IPCC Intergovernmental Panel on Climate Change kW Kilowatt LHV Lower Heating Value MJ Mega joules MOL Main Oil Line MW Megawatts Mwt Molecular weight NCV Net Calorific Value (lower heating value) NER New Entrants Reserve Nm3 Normal cubic metre NNS Northern North Sea OSPAR Oslo Paris Commission Pa Pascal Psia Pounds per square inch, absolute SCF Standard Cubic Feet SI The International System of Units Sm3 Standard cubic metre SNS Southern North Sea STP Standard Temperature and Pressure UKCS United Kingdom Continental Shelf UK ETS United Kingdom Emission Trading Scheme UKAS United Kingdom Accreditation Service UKOOA United Kingdom Offshore Operators Association VOC Volatile Organic Compounds (excluding methane) WBCSD World Business Council for Sustainable Development



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Genesis Oil & Gas Consultants Ltd Date: Mar 06 File name: J70004-A-A-RE-001-B1.doc Revision: B1

1 BACKGROUND AND SECTOR DESCRIPTION

1.1 Description of UK installations and structure of sector The offshore sector of the EU ETS comprises offshore facilities and onshore reception terminals involved in the processing of oil, condensate and gas. This report addresses benchmarking for the offshore oil and gas facilities within the offshore sector of the EU ETS, situated in the United Kingdom’s Continental Shelf (UKCS) and for which the Department of Trade and Industry is the competent authority. This report does not address benchmarking for the onshore terminals. Offshore oil and gas reserves are processed in offshore production facilities (platforms) that can also include accommodation modules for staff. Most oil and gas production platforms in the UKCS rest on steel supports known as jackets pinned to the sea floor with steel piles. A small number of platforms are fabricated from concrete. Above it are prefabricated units or modules providing accommodation and housing various facilities including gas turbine generating sets. Towering above the modules are the drilling rig derrick (two on some platforms), the flare stack in some designs (also frequently cantilevered outwards) and service cranes. Horizontal surfaces are taken up by store areas, drilling pipe deck and the vital helicopter pad. (Figure 1-1). Water depths vary from around 20m to 140m.

Figure 1-1 Schematic of Typical Offshore Installation (UKOOA Website)

Note that although this is a graphical representation of a typical platform it does give a reasonable indication of the cramped nature of offshore facilities.




Other types of fixed structures are used offshore with Figure 1-2 showing the range and relative size of typical installations. In addition, the UKCS contains a number of floating installations used to process hydrocarbons. Typically, these are involved in one or all of the production, storage and export of the hydrocarbons. The most common of these are referred to as Floating Production Storage and Offloading installations (FPSO).

Figure 1-2 Typical Offshore Production Systems (UKOOA Website)

Several platforms may have to be installed to exploit the larger fields, but where the capacity of an existing platform permits, subsea collecting systems linked to it by pipelines have been developed. This type of development is increasingly used as smaller fields are developed and are referred to as subsea tie backs. Figure 1-3 is an example of a subsea tie back showing the Nuggets field as a tie back to the existing Alwyn North platform.

Figure 1-3 Typical Subsea Development

With the variability in size of offshore facilities comes varied complexity in the combustion installations from small, unmanned installations in the Southern North Sea generating




kilowatts (kW) of power to much larger manned facilities in the Northern North Sea that can generate over 100 megawatts of electrical power (MWe). In all, there are approximately 90 offshore installations captured within the EU ETS.

1.2 Oil and Gas Production Simplistically, the offshore industry can be divided into two categories:

• Producers of oil with associated gas • Producers of gas with some associated condensate (a lighter type of oil that

condenses out during the processing of the gas) In general, oil and gas facilities in the Southern North Sea (SNS) are gas producers with very small amounts of condensate, whilst those in the Northern North Sea (NNS) are oil producers and those in the Central North Sea (CNS) can be a mix of combinations of gas, condensate and oil. The differentiation in reservoir conditions and produced hydrocarbon properties is important because it dictates energy use (it takes more energy to produce oil than it does to produce gas) and affects emissions. Gas fields tend to produce a gas with a lower molecular weight with similar properties to the natural gas used onshore whereas the gas on an oil producer tend to have a higher proportion of heavier molecular weight hydrocarbons. Regardless of the source, other contaminants can be present including carbon dioxide, nitrogen and sulphur compounds. (see for instance, Table 5-1 in Section 5)

1.2.1 Emissions from sector Emissions of carbon dioxide from the offshore industry (Table 1-1) account for approximately 6% of the total UK EU ETS Phase 1 emissions. The inclusion of flaring in Phase 2 will increase this to approximately 7% based on no change to the Phase 1 CAP. The majority of the emissions in Phase 1 arose from the use of fuel gas in turbines and engines with a smaller amount arising from the use of diesel in engines and gas and diesel in heaters and boilers. Phase 2 will include emissions from flaring. Table 1-2 summarises historic emissions from offshore incumbents and shows that flaring represents approximately 20% of the total carbon dioxide emitted. Note that the reported emissions of carbon dioxide include native CO2 in the fuel gas.

Table 1-1 Historic Emissions from the Offshore Industry. 1998 1999 2000 2001 2002 2003 2004

Phase 1† 13,028,495 13,251,235 13,854,463 14,402,453 14,666,040 14,317,648 14,188,543 Flaring‡ 4,982,483 5,249,237 4,486,887 4,263,953 4,092,269 3,522,737 3,594,531 Totals‡ 18,012,976 18,502,471 18,343,350 18,668,407 18,760,311 17,842,388 17,785,078

Notes †Phase 1 NAP Historic Data. ‡Includes unverified data A full list of Phase 1 incumbents is provided in Table 1-2.



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Table 1-2 Phase 1 Incumbents

Operator Host Installation AH001 Triton FPSO Amerada Hess Ltd

Uisge Gorm Forties Alpha Forties Bravo Forties Charlie

Apache North Sea Limited

Forties Delta BG Group Armada

Douglas BHP Billiton Petroleum Limited Oil Storage Installation (OSI) Andrew Bruce Clair Cleeton ETAP CPF Everest North Foinaven FPSO Harding Lomond Magnus Miller Ravenspurn North

BP Exploration Operating Company

Schiehallion Britannia Operator Limited Britannia Centrica Storage Ltd Rough 47/3B

Alba FSU Alba Northern Captain FPSO ChevronTexaco Upstream Europe

Captain Platform Complex Banff CNR International (UK) Limited Maersk Curlew

Operator Host Installation Murchison Ninian Central Ninian Northern

Ninian Southern Balmoral CNR International (UK) Limited

(formerly Eni UK Limited) Tiffany Judy LOGGS McCulloch Murdoch

ConocoPhillips (UK) Limited

Viking Hydrocarbon Resources Ltd Morecambe CPC

Global Producer III Gryphon Alpha Kerr-McGee North Sea (UK)

Limited Janice Alpha Heather Alpha Lundin Britain Limited Thistle Alpha Brae Alpha Brae Bravo Marathon Oil UK Ltd East Brae Beryl Alpha Beryl Bravo Mobil North Sea Limited Thames Alpha Buzzard Nexen Petroleum (UK) Limited Scott

Paladin Resources plc Montrose Alpha Indefatigable 23A Leman 27A Perenco UK Limited

Perenco UK Limited Trent Anasuria Shell UK Ltd

Auk Alpha



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Operator Host Installation Brent Bravo Brent Charlie Brent Delta Cormorant Alpha Dunlin Alpha Eider Alpha Fulmar Alpha Gannet Alpha Leman Alpha Nelson North Cormorant Pierce (Hawene Brim) Sean Shearwater Sole Pit Clipper

Tern Alpha Beatrice Alpha Bleo Holm Buchan Alpha Claymore Alpha Clyde Alpha Northern Producer (Galley) Piper Bravo Saltire Alpha (2005 only)

Talisman Energy (UK) Limited

Tartan Alpha Alwyn North Total E&P UK PLC Elgin PUQ

Tullow Oil PLC Hewett 48/29A Tuscan Energy Ardmore (2005 only) Venture Production Company Kittiwake Alpha




2 SECTOR STATUS IN THE EU ETS: CRITERIA FOR INCLUSION. The offshore sector is captured within the EU ETS as a Combustion Process defined in Annex I to the Directive and under Schedule 1 of the UK’s Greenhouse Gas Emissions Trading Scheme Regulations 2005 as follows: “1.1 Activities of combustion installations with a rated thermal input exceeding 20 megawatts (i.e. 20MWth)(excluding hazardous or municipal waste installations).” Flaring has been included within the definition of a combustion process for Phase II but was not covered during Phase 1.

2.1 Offshore Sector Criteria for Access to the NER For the UK offshore oil and gas industry, access to the NER is provided for projects that result in the installation of new, qualifying combustion installations or lead to a quantified enhanced recovery of the UK’s offshore oil and gas reserves. Typical qualifying combustion installations can include:

• Combustion installations on new offshore facilities such as platforms and FPSOs that exceed 20MW(th);

• The installation of additional combustion units onto an existing facility; • Increased use of existing combustion installations (by increasing the power output

within the existing installation’s capacity) in order to process hydrocarbons arising from increased production either from existing or new field developments provided that the increase in power enhances oil and gas recovery through, for instance, the addition of gas lift facilities or water injection for optimum reservoir management.

This latter definition means that increased use of existing combustion installations for reasons other than enhanced recovery of reserves, such as injection of produced water to meet OSPAR 2001/1 requirements1, may not qualify for access to the NER. Access to the NER requires evidence of a commitment to new projects such as the submission to the DTI of an Environmental Statement under the Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999.

2.2 Notes on Units of Power Used in the Report Alternators are generally referred to by their electrical output in MWe. For example a `3 MW’ alternator will produce 3 MWe at the output terminals. By contrast a `3 MW’ compressor will absorb 3 MW of power on the input shaft – ie MWshaft. So for the commonly used Gas Turbine powered Alternator, the overall efficiency from `fuel in’ to `electrical power out’ should take into account the cascaded efficiency of the thermal efficiency of the gas turbine, the mechanical losses in couplings or gearboxes, and the electrical efficiency of the alternator.

1 OSPAR 2001/1. In 2001, the Oslo Paris commission (OSPAR) set binding environmental targets for discharges of oil to sea commencing in 2006. To meet the targets the offshore industry will need to increase re-injection of produced water; the additional power for which does not qualify for access to the NER.




However, the case when the gas turbine directly drives a pump or compressor is slightly different and for such mechanical drive the efficiency of the gas turbine (or diesel) will be the thermal efficiency of the combustion plant itself. (i.e. shaft power presented by the turbine to the pump vs. thermal energy in to the turbine) There could easily be a 5-10% discrepancy in CO2 emissions if this distinction is not clearly reflected in any CO2 calculation spreadsheet. An example here would be the well known Solar Mars turbine (nominal 15,000 horsepower), which has a `heat rate’ (thermal energy in) of 10595 kJ/kWh for mechanical drive, compared to an overall heat rate of 11090 kJ/kWe-hour as an electrical alternator set. However, the rules for access to the NER do not allow for this distinction in the spreadsheet so, throughout this report MW is used to represent both MWe and MWshaft. However, the derived efficiencies do contain a small element to account for losses in electrical generation.

2.3 Likely changes in sector The major change to the sector is the inclusion of flaring in Phase 2. No other major changes to the sector are anticipated. Table 1-1 showed that the inclusion of flaring will increase the offshore sector’s contribution to EU ETS reportable CO2 emissions by roughly 20%.

2.3.1 Known or likely known entrants and retirements In all the DTI has received some 33 applications for access to the NER during Phase 1. These range in size from two new build offshore facilities, Clair and Buzzard requesting annual carbon dioxide allocations of over 200,000t to small increases of under 10,000t due to the tie back of new fields. A list of the new entrants is provided below in Table 2-1 along with their provisional NER allocations. Two of these projects are due to commence production in 2007. There have been two retirements from the offshore sector in 2006; Talisman’s Saltire installation which fell below the 20MW(th) threshold and Tuscan Energy’s Ardmore field which decommissioned in 2005. In addition, Maersk’s (ex KMG) Global Producer III will decommission in late 2006. No additional retirements are anticipated in Phase 1. Current estimates are that as many as 17 offshore installations may decommission in Phase 2 though it should be stressed that this represents a moving target will actual decommissioning dependant upon the future price of oil and whether or not new hydrocarbon fields will be discovered in the vicinity of the existing infrastructure. As yet there is very little data on the likely number and size of applicants for access to the NER in Phase 2: however, given the current price of oil there is no reason to believe that there will be a significant reduction in Phase 1 levels of applications. Continued development of marginal oil and gas fields in the UKCS is likely to mean as many as ten applications per annum; none of these are anticipated to be in support of major new facilities such as Clair or Buzzard though Maersk’s GPIII will commence production from the Donan/Dumbarton field in late 2007/early 2008. Given the lead times for offshore developments it is likely that the majority of applications will be submitted during 2007/2008 with first oil anticipated 2008 to 2010.




Table 2-1 Phase 1 NER Applications from the Offshore Industry

Operator Host Installation NER Provisional Allocation (tCO2)

Amerada Hess Ltd Triton FPSO 69,017 Apache North Sea Limited Forties Alpha 183,383 Apache North Sea Limited Forties Charlie 250,629 BHP Billiton Petroleum Limited Douglas† 383,884 BP Exploration Operating Company Andrew† 21,513 BP Exploration Operating Company Bruce LPBC† 80,050 BP Exploration Operating Company Clair 474,677 BP Exploration Operating Company Cleeton† 15,178 BP Exploration Operating Company Schiehallion† 26,103 Britannia Operator Limited Britannia 68,068 CNR International (UK) Limited Balmoral ConocoPhillips (UK) Limited Murdoch Eclipse Energy Ormonde 216,273 Kerr-McGee North Sea (UK) Limited Global Producer III Kerr-McGee North Sea (UK) Limited Janice Alpha Lundin Britain Limited Heather Alpha 155,121 Marathon Oil UK Ltd Brae Alpha 28,695 Mobil North Sea Limited Thames Alpha 39,031 Mobil North Sea Limited Thames Alpha 41,887 Nexen Petroleum UK Ltd Buzzard 432,907 Paladin Resources plc Montrose Alpha 28,590 Perenco UK Limited Leman 27A Perenco UK Limited Trent 215,798 Shell UK Ltd Pierce (Haewene Brim) 151,529 Shell UK Ltd Sean† Shell UK Ltd Shearwater† Shell UK Ltd Sole Pit Clipper† 19,103 Shell UK Ltd Sole Pit Clipper† 7,829 Talisman Energy (UK) Limited Piper Bravo 85,807 Total E&P UK PLC Alwyn North 72,438 Total E&P UK PLC Elgin PUQ 19,257 Total E&P UK PLC Elgin PUQ 21,002 Venture Production Company Kittiwake Alpha 8,539

Notes. † UK ETS Opt out from EU ETS in 2005 and 2006 The known total Phase 1 allocation for the offshore industry from the NER to date is 3.3 million tCO2 which drops to 3 million tCO2 when those installations that are in the UK ETS, and have opted out of the EU ETS, are excluded. The annual demand on the NER is shown in Figure 2-1. Note that the large increase from 2006 to 2007 is mainly due to the entry of the UK ETS opt out combustion installations following closure of the UK scheme in 2006. To improve clarity, Figure 2-1 does not include a legend, however, the colours represent individual facilities.




Figure 2-1 Allocations of CO2 from the Phase 1 NER

0

500000

1000000

1500000

2000000

2500000

2005 2006 2007

Year

tCO

2




3 TECHNOLOGY OPTIONS AND EMISSIONS FACTORS The major users of power on offshore installations are:

• Compression and pumping systems used to transport hydrocarbons such as the main oil line (MOL) pumps, crude export pumps and gas compression and export.

• Pumps used to inject water into subsurface strata either for the purposes of increasing the recovery of hydrocarbons (enhanced oil recovery) or as a means of minimising the discharge of hydrocarbons to sea as required under OSPAR 2001/1.

• Platform drilling. Table 3-1 and Figure 3-1, summarise power use on a typical medium sized offshore facility. Note that not all platforms undertake drilling activities. This information is taken from Genesis internal data on typical power use offshore.

Table 3-1 Typical Distribution of Electrical Power demand on an Offshore Platform Power (kW) Description Continuous Intermittent

Main Oil Line (MOL) Pumps 1800 3200 Drilling - 3160 Separation 382 - Compression 5000 600 Gas dehydration 350 - Water injection 2500 - Seawater lift pumps 380 190 Seawater treatment 50 50 Fresh water - 80 Electrochlorinator 250 - Fuel gas 150 - Cooling medium 160 - Heating medium 150 - Relief system 25 25 Closed drains 20 - Instrument air 360 180 Fuel oil 50 - Chemical injection 100 150 Miscellaneous 2000 1000 Total 13727 8635

The majority of this power is delivered at source via dedicated turbines and engines, predominantly operating using fuel gas produced on the platform or fuel gas imported from a nearby facility. Some facilities use fuel gas to produce electricity which in turn is used to drive the pumps and compressors. The fact that the gas used on the facility is also produced there means that, in general, its characteristics do not match the compositions found onshore in typical natural gas from the grid. This is discussed further below.




Figure 3-1 Energy Use on a Typical Platform

Main Oil Line (MOL) Pumps22%

Drilling14%

Separation2%

Compression25%

Gas dehydration2%

Water injection11%

Miscellaneous 13%

Seawater lift pumps3%

Cooling medium

Electrochlorinator

Instrument air2%

Chemical injection

Heating medium

Fuel gas

3.1 Offshore Gas and Diesel Combustion Gas is the predominant fuel used offshore with over 90% of fuel based emissions of carbon dioxide arising from the use of gas (EEMS 2003)2. The majority of this gas comes from the processing of the hydrocarbons on the facility though, in some cases, fuel gas may be supplemented, or wholly arise from, gas imported from nearby facilities. The gas is of varying quality which depends on where in the process the gas is taken from and the nature of the hydrocarbons being processed. Typically, diesel consumption offshore contributes less than 8% to total emissions of carbon dioxide with flaring contributing roughly 20% and fuel gas making up the remaining 72% (EEMS 2003). Routine diesel consumption is typically in smaller engines driving, for instance, fire water pumps and crane engines. Diesel is also used in “black starts” and during maintenance periods. Black starts occur when, for whatever reason, the process trips and goes into failsafe mode. Under these circumstances, production stops and there is no available fuel gas: essential services switch to diesel and, in order to produce the gas needed to operate the large turbines, the process must be brought back on line using diesel. Once sufficient gas has been produced the major combustion installations are switched back to fuel gas. On some installations there is little or no fuel gas and no infrastructure to import gas, in these circumstances diesel may be the only available fuel.

2 The environmental emissions monitoring system (EEMS) is a methodology developed by the offshore industry for reporting emissions and discharges from offshore operations. It has been in use since the mid 1990’s and since then has undergone a number of revisions to improve upon the accuracy of emissions factors.




Hydrocarbon gas is a valuable commodity, and as such, where economics (usually) allow, gas is recovered and piped to market. However, a flare system is needed to allow the offshore process to operate safely – ie gas can be relieved to flare if the process system encounters an upset and needs to stay within allowable operating parameters such as pressure, and releases process gas to the flare to relieve this overpressure. Gas to flare can come from a number of sources, and in order to ensure safe operation of the process, fuel gas is used to maintain a pilot light on the flare(s) and is also often used to purge vessels and flare stacks to ensure no ingress of air (therefore minimising the risk of an explosive mix of gas and air forming). Typically purge gas is also collected and sent to flare. These two flows are known as pilot & purge. A third routine source of flare gas is from stripping gas. This is the use of gas to increase the recovery of oil from water using a counter current flow in a column. Routine flaring is generally low in oil and gas operations and is consistent with safe operation of facility, possible exceptions are on facilities that have no economic gas export route. In addition to routine flaring, and as discussed above, when there is a trip in the process, the system is designed to failsafe by depressurising. The consequence of this is that significant quantities of gas can be sent to flare over short time periods. In extreme cases, this may include the safe disposal by flare of gas in the pipelines. Non routine flaring can therefore be the major source of flaring offshore. Figure 3-2 summarises the total emissions of carbon dioxide from flaring between 1998 and 2004, respectively. Flaring from offshore facilities in the UKCS is controlled via the DTI’s flare consent regime. This sets caps on flaring from individual facilities and requires improvements to be introduced to further reduce flaring. The decline in flaring shown in Figure 3-2 is, in part, due the flare consent scheme. Current guidance is that there will be no access to the NER for flaring during Phase 2. Figure 3-2 EU ETS Total Carbon Dioxide Emissions from Flaring on Offshore Facilities

3000000

3500000

4000000

4500000

5000000

5500000

1998 1998 1999 2000 2001 2002 2003 2004

Year

Tota

l Car

bon

Dio

xide

(t)




3.2 Fuel Characteristics During the processing of hydrocarbons the first step is the separation of oil from the associated water and gas (in the first stage separator). Further separation occurs in the second stage separator and from gas dehydration. Ideally, the gas used for fuel will be export quality gas from the last stage of processing but at times the gas used can come from the 1st or 2nd stage separators or elsewhere in the process. The situation is further complicated by the fact that different wells can produce a fuel gas of different composition. The potential variable nature of the produced gas is accommodated in the development of site specific emissions factors, including one for carbon dioxide, used offshore for reporting overall emissions to the DTI within the Monitoring and Reporting framework. This is discussed in more detail below. Flare gas composition can be very variable depending upon where in the process the gas to flare originates. For this reason, process modelling is often used to infer gas composition from, for instance, valve position and operating conditions.

3.3 Benchmarking Benchmarking installations offshore is not a straightforward exercise. Typically within an industrial sector, benchmarking can be based on, for instance, energy used per unit of product exported or, because in the case of the oil industry this is an energy product, energy used per barrel of oil equivalent (boe) of hydrocarbon exported where boe is a means of comparing oil with gas based on their energy content. Such comparisons are of limited use in the offshore industry because, as shown in Table 1-1, the major energy users are: export pumps and gas compression requirements which can be related to the distance to the market place (how far the facility is from the coast); and means of facilitating recovery of hydrocarbons such as the use of gas lift and/or water injection, which can be related to the nature of the reservoir. These examples highlight the fact that energy use offshore is driven not so much by the delivery of a unit of product but by reservoir properties, production levels and distance from the shore. These variables are very much site specific. For instance, energy input may be required to extract the oil from the reservoir and this could be in the form of gas lift (pumping gas down into the production riser) to reduce the density of the oil and/or the injection of water at the periphery of the reservoir to “flush” the oil out. Equally, a nearby oil reservoir may be sitting under a significant gas cap (this will provide natural pressure to push the oil out) and require no additional energy for extraction: however, eventually this too may require artificial lift to extract the oil as the pressure in the cap decreases. This example highlights two problems that arise when trying to benchmark the offshore industry. First, similar installations with closely matched oil and gas production may have completely different emissions profiles. Second, in general, an installation’s emissions rise with falling production as more work has to be done to extract the oil and gas. Future offshore developments are increasingly likely to use more energy to produce oil and gas reserves than has historically been the case due to the fact that the large, relatively easily accessible fields have already been developed. Despite this, since overall production has fallen, emissions from the offshore industry have fallen from peak historic levels. Benchmarking for the offshore sector is therefore based on efficiency of the combustion process with Table 3-2, summarising the efficiencies used in Phase 1 for existing and new combustion installations. Currently, there is little data on actual “in service” efficiencies for the turbines and engines used offshore. Some data is available from the small number of PPC permit application received by the DTI to date, from NAP applications and from




discussions with operators. The data in Table 3-2 was derived from a combination of these sources. Closer to Phase 2, more information will become available as the industry comes wholly under the PPC regulations. Table 3-2 Phase 1 plant thermal efficiencies used in benchmark calculation

Equipment Existing New

Turbines 0.24 0.35

Engines 0.24 0.35

Heaters 0.80 0.85

3.4 Emissions factors Given the variability of fuel gas compositions offshore the United Kingdom Offshore Operators Associated (UKOOA) developed a methodology for determining carbon dioxide (CO2) emissions based upon site specific fuel gas characteristics. The results from this process have been reported to the DTI via the Environmental Emissions Monitoring System (EEMS) since the mid 1990s and uses emissions factors expressed as tonnes of pollutant (CO2) per tone of fuel consumed. The methodology for determining the CO2 emission factor has been reviewed and updated on a regular basis such that there is a high confidence in the accuracy of the factor. The factor is based on a compositional analysis of the fuel gas determined either from gas analysis or from process modelling. In a recent study, UKOOA (UKOOA 2004) showed that the “EEMS” factor gave a truer result than use of, for instance net calorific value (NCV), for a range of fuel gas compositions used by offshore facilities in the UKCS. As can be seen (Table 3-3) errors as high as 18% can arise from use of the UK/EU ETS or IPPC default factors. Note that Table 3-3 has been reproduced “as is” from the UKOOA report. The UKOOA report concludes that the results of the study demonstrate the inadequacy of default emissions factors in the calculation of CO2 emissions from fuel gas. These default factors may be based on fuel volume, mass or energy, but unless the gas composition is taken into account the results are inaccurate. Default factors under-predict emissions by over 22% in the selected examples. However, using the UKCS mean (simplified) fuel gas compositions, the UK ETS and IPCC default factors showed an average error of 2.1 and 5.9% respectively. The American Petroleum Institute (API) carbon mass method is highly accurate and consistent as it derives the emissions from fundamental calculations of carbon content (from gas composition data) and gas mass consumption. If the quantities consumed are in units of volume, the gas composition data allows for accurate conversion to mass. Unlike other schemes, there is no reliance on empirical relationships or average values.




Table 3-3 CO2 Emission Factor Comparisons (Dry Gas)

Hypothetical Gas Compositions 1 2 3 4 5 6

Higher Heating Value MW/t 13.71 9.47 10.87 11.92 14.86 12.25

Lower Heating Value MW/t 12.53 8.62 9.86 10.79 13.49 11.11

UKOOA Reference Methodology Calculated CO2 factor (kg/kg) 2.834% 2.201% 2.326% 2.441% 2.852% 2.483% Percentage error 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

UKOOA formula (2002 onwards) Default factor (t/t) 2.830 2.199 2.323 2.439 2.852 2.483 Percentage error -0.13% -0.12% -0.13% -0.09% 0.00% 0.00%

API GHG Compendium Methodology 2001 Converted CO2 factor (kg/kg) 2.834 2.201 2.326 2.441 2.852 2.483 Percentage error 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

API GHG Compendium Natural Gas Default Value 2001 Given CO2 factor (tCO2/106 BTU) 0.0531 0.0531 0.0531 0.0531 0.0531 0.0531 Converted CO2 factor (kg/kg) 2.484 1.716 1.969 2.160 2.692 2.220

Percentage error -

12.33% -22.05% -15.33% -11.53% -5.59% -

10.62% IPCC Emission Factors for Natural Gas (based on Corinair 1994) and World Business

Council for Sustainable Development (CO2 e.f. 56060) Given CO2 factor (gCO2/GJ) 56000 56000 56000 56000 56000 56000 Converted CO2 factor (kg/kg) 2.76394 1.909152 2.191392 2.403072 2.995776 2.4696 Percentage error -2.46% -13.27% -5.79% -1.56% 5.05% -0.55%

UK/EU ETS Default Factor for Natural Gas Given CO2 factor (kgCO2/kWh) 0.19 0.19 0.19 0.19 0.19 0.19 Converted CO2 factor (kg/kg) 2.605 1.799 2.065 2.265 2.823 2.328 Percentage error -8.07% -18.26% -11.21% -7.22% -1.00% -6.27%

Note: Lower heating value is equivalent to Lower Calorific Value used in EU ETS documentation. The current UKOOA formula takes account of carbon content from simplified gas composition by the inclusion of an empirical relationship between VOC’s and CO2 emissions. The results show a high level of agreement with the above fundamental calculations, with deviations of less than 0.15%.




For the benchmarking spreadsheet used in Phase 1, an industry-wide average emission factor for fuel gas was adopted rather than a site-specific factor. This was determined as follows:

1. Determination of the fuel gas density was based on an industry average of 0.835kg/m3 from typical ranges of between 0.820 - 0.850kg/m3.

2. The heat content of a typical UKCS fuel gas in MJ/m3 was based on industry

reported calorific values in the range 38-48 MJ/m3. A mid range figure of 43 MJ/m3 was used, with an assumed efficiency, to determine the volume of fuel gas required to deliver 1MW of power.

3. The average density was used to convert MJ/m3 in step 2 into MJ/tonne fuel gas.

4. An emission factor (in tonnes of CO2 per tonne of fuel gas consumed – the factor

used by the offshore industry in reporting emissions via EEMS) was calculated using the range of 2.6-2.9 indicated by UKOOA3. A mid range figure of 2.75tCO2/t of fuel gas was chosen for use in the NER spreadsheet excluding any adjustment for the use of diesel.

5. The final factor used in the NER spreadsheet is expressed in terms of tCO2/MW of

delivered power. Note that the factor used in reporting under M&R rules for the offshore is based on the carbon content of the fuel and expressed as tCO2/t.

3.4.1 Accounting for Diesel Use The benchmarking calculation is based on the use of gas as this is the predominant fuel used for ETS-covered activities offshore. It is, however, inevitable that diesel will also be used to operate small engines (for instance, cranes and firewater pumps), for black start purposes or as the major source of fuel in some installations. As fuel type is not permitted to be site-specific in the calculation and diesel use is unavoidable, it is therefore necessary to include a diesel factor in the calculation to avoid all new allocations being underestimates. It should be noted that the use of gas on FPSO engines may be restricted for safety reasons and allocations for these facilities will always be underestimated. In order to determine a typical diesel fraction of emissions, reference has been made to EEMS data on emissions from diesel combustion for 2003 for the facilities in the EU ETS. Figure 3-3 shows the cumulative percentage of diesel emissions from the ninety two Phase 1, offshore incumbents. A clear division is apparent at 30% emissions from diesel, and it can be seen that platforms using <30% diesel account for approximately half the diesel emissions and platforms using >30% account for the other half. The figure also highlights the fact that a few users are responsible for much of the emissions from diesel with 50% of the emissions coming from seven facilities; these represent the installation with little or no access to gas and/or gas export routes.

3 Note that the Phase 1 factors were based on the 2003 EEMS returns to the DTI. Table 3-1 reports on the results from a UKOOA funded study which was not available at the time. Information from the report has been used to update factors as necessary. This is discussed in Section 4.




Figure 3-3 Cumulative % Diesel Emissions (2003 EEMS)

Cumulative % diesel em issions vs % due to diesel 2003 (EEMS)

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Using an average diesel fraction of 30%, and assuming new entrants reflected the existing range of facility characteristics, half of existing diesel emissions would be overestimated and half underestimated. Diesel is a well-defined fuel and it can be shown that CO2 emissions from diesel equate to 7.216x10-5 tCO2/MJ (3.2 tCO2/t at an energy content of 44.3 MJ/kg). Using the assumptions for fuel gas as given in the previous section, the equivalent figure for fuel gas is 6.396x10-5 tCO2/MJ. This gives a diesel factor, D of D = 1 + (30%) x (7.216-6.396) ÷ 6.396 = 1.04 That is, the factor used to calculate emissions of CO2 on the NER benchmarking spreadsheet was altered to include a 4% element to account for essential diesel use changing the factor of 2.75 to 2.9tCO2/t. This factor, converted to tCO2/MW as described above, is used in the Phase 1 NER benchmarking spreadsheet.

3.4.2 Derivation of Efficiency The efficiency of turbines and engines in use offshore is typically in the range 0.18-0.35 with a mid-range figure of 0.26. These numbers come from an initial survey of data reported to the DTI via the EU ETS NAP applications and from discussions with operators. This range reflects the nature of the fuel used offshore and the age and utilisation of the turbines and




engines. The Phase 1 NER spreadsheet used the following values for efficiency in turbines and engines: TEFnew = 0.35 TEFexisting = 0.24 Efficiency from turbines and engines is particularly affected offshore by the nature of the fuel gas burned. Although discussed later (see Table 5-1, Section 5) fuel gas offshore is very variable and can have a high inerts content degrading performance. This is reflected in the chosen efficiencies. Heaters are also used offshore but are responsible for only a small percentage of overall emissions. Heaters are more efficient than turbines and generators and a figure of 84% was adopted with a correction for diesel use.

3.5 Utilisation The rules for access to the NER onshore include a utilisation factor based on new installed capacity and an average load factor for the sector. For instance, it is assumed that, on average, a sector may use 85% of installed new capacity (for every new 100MW installed only 85MW is used). The offshore industry allows allocation of CO2 from the NER for: the installation of a new combustion plant either on an existing or a new facility; or for an increase in load on an existing combustion installation provided that this leads to the enhanced recovery of hydrocarbons. This latter criterion sees no increase in capacity and therefore, a utilisation factor based on installed capacity will not work offshore. Other means of addressing utilisation in the offshore industry was required. The offshore industry shows no generic trend in utilisation of installed capacity. Older facilities are typically producing at a small fraction of their historic levels and tend to have more installed capacity than required to meet current production. This trend is compounded by the need to maintain availability - the failure of an individual combustion installation can cause a process trip with increased flaring and loss of export. This can have a serious knock-on effect on, for instance, onshore gas supplies. This need to maintain production means that, in addition to running combustion units to provide the required power, other units are often run in standby mode, available to take up the load should an individual unit fail. Older facilities are also often oversized in terms of the process equipment. This is particularly true of compressors which can be operating in recycle mode (insufficient gas available to operate therefore gas is recycled back into the compressor to maintain the required volumetric flow rate). Newer developments are typically tie backs to existing facilities using the spare ullage. This is efficient both from an economic and environmental perspective since it minimises the infrastructure in place in the UKCS. A small number of offshore installations act in peak shaving mode; producing at the demand of onshore gas distribution companies. Figure 3-4 illustrates this by showing the ratio of minimum and maximum reported emissions of CO2 for all the offshore facilities in Phase 1 of the EU ETS. On the assumption that the maximum reported emissions can be used as a surrogate for capacity and that the minimum




emission reflects the lowest “utilisation”. The graphs shows a wide spread of ratios. Figure 3-5 shows the ratio of the average emission of CO2 in the period 1998 to 2004 against the maximum and although there does seem to be limited banding, the range still lies in a broad band of 60 to 95% utilisation. For the above reasons, it was concluded that the only effective means of including utilisation into the spreadsheet for the offshore industry was to allow site specific utilisation factors for each combustion installation based on running hours at load. This factor is verifiable as part of the NER independent audit process.

3.6 Flaring Benchmarking for emissions of carbon dioxide from flaring have not been included within the Phase 2 NER spreadsheet and no allowances have been allocated for flaring associated with new combustion installations.




Figure 3-4 Ratio of Minimum and Maximum Emissions 1998 to 2004

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Figure 3-5 Ration of Average and Maximum Emissions

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4 CRITICAL REVIEW OF PHASE 1 BENCHMARKS

4.1 Detailed description of Phase I benchmarks The current benchmark for the offshore industry calculates the CO2 allocation in tonnes based on industry average emission factors (expressed as tonnes CO2 emitted per megawatt of energy delivered – the delivered power - per annum) and site specific utilisation. Within the spreadsheet, the way in that the energy delivered is captured differs for new versus an existing combustion installation. For new combustion installations, drop down boxes with selectable power values (0, 2, 5, 10, 15 etc MW) are used. For existing combustion installations the operator enters the actual, calculated power requirement. As discussed above, utilisation is entered directly into the spreadsheet as running hours at 10, 50, 75 and 100% of load with a maximum allowable value of 8760 hours per annum per individual combustion installation. There is no difference between existing and new entrants. This approach to the calculation of CO2 allocations is summarised below in Table 4.1 for new installations and Table 4.2 for existing installations. With the specific energy consumption derived as shown in Table 4.3.

Table 4-1 Calculation of Allocation for New Combustion Installations

A = Ci * Ui * SECs * EFs * Adj

Allocation = Capacity * Utilisation * Specific Energy

Consumption * Emissions

Factor * Adjustment factor

tCO2 Unit

output MW

Hours at load

Tonne fuel/MWh

input tCO2 /

tonne fuel Diesel use factor

Table 4-2 Calculation of Allocation for Existing Combustion Installations

A = Li * Ui * SECs * EFs * Adj

Allocation = Increase in Load * Utilisation *

Specific Energy

Consumption * Emissions

Factor * Adjustment factor

tCO2 Unit

output MW

Hours at load

Tonne fuel/MWh

input tCO2 /

tonne fuel Diesel use factor




Table 4-3 Calculation of Allocation for Existing Combustion Installations

SEC = ρs / CVs * TEFt / Adj

Specific Energy

Consumption = Density / NCV * Thermal

Efficiency / 1000

Tonne fuel/MWh

input Kg/m3 Net CV

MJ/m3 % Convert kg to tonnes

4.2 Summary of Applied Factors

Table 4-4 Summary of Phase 1 NER Emission Factors

CO2 Emission factor Equipment Status Efficiency t/t t/MW New 0.35 0.6 Turbines

Existing 0.24 0.86 New 0.35 0.6 Engines

Existing 0.24 0.86 New 0.825 0.25 Heaters†

Existing 0.825

2.9

0.25 Notes: † CO2 factor expressed in terms of t/MWth output.

4.3 Comparison to benchmarks used in other contexts, notably other Member States (if available)

To be completed

4.4 Strengths of Phase 1 NER Benchmarking Spreadsheet The spreadsheet follows a format similar to that used by other sectors and, on average, does not favour one operator over another. BAT is represented through the use of realistic efficiency factors taking account of the age of the equipment in use in the offshore sector and, in particular the nature of the fuel used. The derived CO2 emission factors are an average of those used in the reporting of emissions to the DTI via the EEMS system and therefore represent the best available without seeking installation specific factors. The derived carbon dioxide factor (expressed as tCO2 per MWh) is representative of those typically used offshore. For instance, fuel gas is rarely, if ever, NTS quality gas and the use of diesel is unavoidable.




4.5 Weaknesses The use of fixed drop down boxes to select the capacity (in MW) of new turbines and generators lends itself to overestimates of emissions. For instance, an operator installing a new RB211C turbine rated at 28MW could select 30MW from the drop down box as the nearest equivalent gaining 2MW or around 10,000 tonnes of extra CO2 per annum. Better accuracy could be achieved by use of actual CV (since operators are required to measure this) along with the site specific emission factors. But this needs to be balanced against the additional work involved in the use and reviewing of the spreadsheet. This would also move the spreadsheet philosophy further from those for the other sectors. There is a need to address offshore operating philosophies particularly given that Phase 2 is for five years. This is because, whereas, existing installations will tend to operate under relatively steady state conditions, new installations may pre-invest in future compression requirements (adding larger than immediately required equipment to be used as the reservoir depletes). The capacity will remain the same but use may vary over the five year period. As it stands an operator could complete the NER form based on an average or the maximum over the five years. Addressing this issue may only require guidance as to how the form should be completed for year on year variations in use of combustion equipment.




5 DISCUSSION AND SUGGESTED REVISIONS TO BENCHMARKS The approach to the benchmarking spreadsheet in Phase 1 was largely dictated by the need to follow, as closely as possible, the spreadsheets being developed for use onshore. A number of issues were highlighted in use of the spreadsheet during Phase 1 and the opportunity has been taken to review and amend the spreadsheet for Phase 2.

5.1 Specific formulae In the Phase 1 guidance, it was reported that the density of fuel gas is typically in the range 0.820 - 0.850 kg/ m3 with a mid range figure of 0.835 kg/m3 used. Subsequent to that report, UKOOA has published an internal document reviewing typical fuel and flare gas properties used offshore. The minimum, maximum and average values are presented in Table 5-1, however this masks the significant spread in the data (Figure 5-1). From this data the fuel gas densities were derived (Table 5-1) with a range of varying from 0.73 kg/m3 to 1.31 kg/m3 and an average value of 0.91 kg/m3 at standard conditions. A value of 0.91kg/m3 should be adopted for Phase 2.

Table 5-1 Summary of Offshore Fuel Gas Properties

%CH4 %VOC VOC Mwt %CO2 %N2 %H2S Avg

Mwt CO2

Factor Density Kg/m3

Min 52.8 0.07 17.24 0.04 0.1 0 16.33 2.07 0.73 Max 97.74 43.1 56.11 24.54 8.45 0.07 29.28 2.83 1.31 Ave 80.65 15.14 38.62 1.98 2.17 0.001 20.38 2.66 0.91

Figure 5-1 Calculated Range of Molecular Weights

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The calorific value of fuel gas used in Phase 1 was reported as typically in the range 38-48 MJ/m3. A mid range figure of 43 MJ/m3 chosen as typical. The same value has been chosen for use in Phase 2. The calorific value is used once in the development of the




spreadsheet, with the density, to calculate the heat released from the combustion of 1 tonne of gas. The carbon dioxide emission factor used in Phase 1 was based on data available at the time and an average value of 2.75tCO2 per tonne of fuel gas burned was chosen with a range of between 2.6-2.975tCO2 per tonne of fuel gas burned. The 2004 data (Table 5-1), indicates that an average value 2.66tCO2 per tonne of fuel gas burned is more representative. Which, when diesel use is factored in, gives a recommended Phase 2 NER factor of 2.77tCO2 per tonne of fuel gas burned. This factor is used in the spreadsheet to convert heat released from the combustion of 1 tonne of gas into the tonnes of carbon dioxide emitted per tonne of gas. It is this derived factor that is then used, with the thermal efficiency, to calculate the amount of carbon dioxide emitted per MW load.

5.1.1 Efficiency Section 3.4.2 presented data on the efficiencies used in the Phase 1 NER spreadsheet. No additional information is available and, therefore Phase 1 NER value for the efficiency of new turbines and engines has been retained. However, assessment of the Phase 1 NER data received to date suggests that a stricter efficiency could be applied to existing installation. A value of 0.28 is recommended. The Phase 1 NER value of 84% for the efficiency of heaters has been retained.

5.1.2 Utilisation factor The utilisation factor is an indication of how much of an installations capacity is utilised and is generally a fixed factor. For the offshore, it was concluded that a standard utilisation factor was not practicable as discussed in Section 3.5, above. For the offshore industry, no single utilisation is used instead operators enter running hours and associated loads for each affected combustion installation.

5.2 Recommended Changes

1. Operators should be required to enter actual load rather than select the closest load from the drop down menus. This will help reduce potential over allocation by selection of next nearest value (for instance currently if new combustion installation is 750kW operators may choose 2MW).

2. Retain current efficiency of 35% for new turbines and engines. Increase efficiency to 84% for heaters. Increase efficiency from 24% to 28% for existing installations as this will encourage energy efficiency.

3. Amend CO2 factor from 2.9 to 2.77 in light of UKOOA study on the range of fuel compositions.

4. Do not implement a single utilisation factor for the offshore. 5. Retain diesel factor or consider introducing a separate factor for diesel to account for

the unavoidable use of diesel offshore. 6. Increase number of combustion installation rows available for entries. New

installations had insufficient space for entering all combustion sources.




6 EVALUATION OF PROPOSED BENCHMARK ACCORDING TO AGREED CRITERIA

6.1 Feasibility of Verification of Utilisation Verification of the running and load entered into the NER spreadsheet depends on the availability of this information from operators. The majority, if not all, operators monitor combustion plant condition on their main generating units. This includes running hours since this data is essential to the management of maintenance scheduling. In addition, many also record load with the running hours. Using running hours and load in place of a standard utilisation factor is therefore not seen as causing the industry an unnecessary burden.

6.2 Standardisation of the Fuel Factor The fuel factor proposed for the Phase 2 NER spreadsheet represents an average value used in the offshore industry with a small component (4%) to account for unavoidable diesel use. Use of the standard factor used by the onshore industry was rejected because it is not representative of gas composition offshore. Given the disparity in gas compositions offshore, consideration was also given to allowing use of site specific fuel gas compositions, as used for the purposes of Monitoring and Reporting. Although this would give a truer value of the resultant CO2 emissions and transparency across Monitoring & Reporting, it was rejected because it moved away from strict benchmarking and allowed the operator too much freedom when entering information into the spreadsheet.

6.3 Comparison of CO2 Emissions For the purposes of this report, CO2 emissions were calculated using a number of methodologies. An attempt was made to make direct comparison with other sectors but this was not possible. For instance, attempts at comparing the data against that derived for the national transmission sector was not possible because of the uncertainty in the loads used in the derivation of the emission factors for that sector. A full comparison will be made when additional information on the Phase 2 sector NER spreadsheets become available.




7 REFERENCES UKOOA Website http://www.ukooa.co.uk/ UKOOA 2004 Offshore Industry Carbon Dioxide Calculation Requirements for Emission Trading, 9084-UKO-RT-X-00001, July 2004

http://www.ukooa.co.uk/

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