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Prepared by:

Genesis Oil & Gas Consultants Ltd3 Queens Gate, Aberdeen, AB15 5YL

Tel. +44 (0) 1224 201201, Fax. +44 (0)1224 201222www.genesisoilandgas.com

Department of Trade & Industry - DTI

Report

Offshore BenchmarkingSupportingDocumentation

Genesis Job Number J-70004/A

March 06
http://www.genesisoilandgas.com/http://www.genesisoilandgas.com/

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File name: J70004-A-A-RE-001-B1.doc Revision: B1

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Genesis Oil & Gas Consultants Ltd Page iii Date: Mar 06


CLIENT: DTI

PROJECT/JOB TITLE: Implementation of EU ETS

DOCUMENT TYPE: Report

DOCUMENT TITLE: Offshore BenchmarkingSupporting 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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Offshore Benchmarking Supporting Documentation

Implementation of EU ETS

Genesis Oil & Gas Consultants Ltd Page v Date: Mar 06


Table of Contents

1 BACKGROUND AND SECTOR DESCRIPTION .......................................................... 91.1 DESCRIPTION OF UK INSTALLATIONS AND STRUCTURE OF SECTOR............................. 91.2 OIL AND GAS PRODUCTION.................................................................................... 11

1.2.1 Emissions from sector..............................................................................................................112 SECTOR STATUS IN THE EU ETS: CRITERIA FOR INCLUSION. ........................... 15

2.1 OFFSHORE SECTOR CRITERIA FOR ACCESS TO THE NER........................................ 152.2 NOTES ON UNITS OF POWER USED IN THE REPORT................................................. 152.3 LIKELY CHANGES IN SECTOR .................................................................................. 16

2.3.1 Known or likely known entrants and retirements ...................................................................... 163 TECHNOLOGY OPTIONS AND EMISSIONS FACTORS........................................... 19

3.1 OFFSHORE GAS AND DIESEL COMBUSTION............................................................. 203.2 FUEL CHARACTERISTICS........................................................................................ 223.3 BENCHMARKING .................................................................................................... 223.4 EMISSIONS FACTORS............................................................................................. 23

3.4.1 Accounting for Diesel Use ....................................................................................................... 253.4.2 Derivation of Efficiency........................................................................................................... 26

3.5 UTILISATION.......................................................................................................... 273.6 FLARING............................................................................................................... 28

4 CRITICAL REVIEW OF PHASE 1 BENCHMARKS.................................................... 304.1 DETAILED DESCRIPTION OF PHASE I BENCHMARKS .................................................. 304.2 SUMMARY OF APPLIED FACTORS ........................................................................... 314.3 COMPARISON TO BENCHMARKS USED IN OTHER CONTEXTS, NOTABLY OTHER MEMBERSTATES (IF AVAILABLE)...................................................................................................... 314.4 STRENGTHS OF PHASE 1NERBENCHMARKING SPREADSHEET ............................... 314.5 WEAKNESSES ....................................................................................................... 32

5 DISCUSSION AND SUGGESTED REVISIONS TO BENCHMARKS ......................... 335.1 SPECIFIC FORMULAE ............................................................................................. 33

5.1.1 Efficiency................................................................................................................................ 345.1.2 Utilisation factor ..................................................................................................................... 34

5.2 RECOMMENDED CHANGES..................................................................................... 346 EVALUATION OF PROPOSED BENCHMARK ACCORDING TO AGREED CRITERIA35

6.1 FEASIBILITY OF VERIFICATION OF UTILISATION ........................................................ 356.2 STANDARDISATION OF THE FUEL FACTOR............................................................... 356.3 COMPARISON OF CO2EMISSIONS .......................................................................... 35

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

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Table of Figures

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

Table of Tables

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

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ABBREVIATIONS

API American Petroleum Institute

BOE Barrel of Oil EquivalentBTU British Thermal UnitCNS Central North SeaCO2 Carbon DioxideDEFRA Department for Environment, Food and Rural AffairsDTI Department of Trade and IndustryEEMS Environmental Emissions Monitoring SystemEPA Environmental Protection AgencyEU European UnionEU ETS European Union Emission Trading SchemeFPSO Floating Production Storage and Offloading (vessel)GHG Greenhouse GasGCV Gross Calorific Value (higher heating value)HHV Higher Heating ValueIPCC Intergovernmental Panel on Climate ChangekW KilowattLHV Lower Heating ValueMJ Mega joulesMOL Main Oil LineMW MegawattsMwt Molecular weightNCV Net Calorific Value (lower heating value)NER New Entrants Reserve

Nm3

Normal cubic metreNNS Northern North SeaOSPAR Oslo Paris CommissionPa PascalPsia Pounds per square inch, absoluteSCF Standard Cubic FeetSI The International System of UnitsSm3 Standard cubic metreSNS Southern North SeaSTP Standard Temperature and PressureUKCS United Kingdom Continental ShelfUK ETS United Kingdom Emission Trading Scheme

UKAS United Kingdom Accreditation ServiceUKOOA United Kingdom Offshore Operators AssociationVOC Volatile Organic Compounds (excluding methane)WBCSD World Business Council for Sustainable Development

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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 receptionterminals involved in the processing of oil, condensate and gas.

This report addresses benchmarking for the offshore oil and gas facilities within the offshoresector of the EU ETS, situated in the United Kingdoms Continental Shelf (UKCS) and forwhich the Department of Trade and Industry is the competent authority. This report does notaddress benchmarking for the onshore terminals.

Offshore oil and gas reserves are processed in offshore production facilities (platforms) thatcan 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. Asmall number of platforms are fabricated from concrete. Above it are prefabricated units ormodules providing accommodation and housing various facilities including gas turbinegenerating sets. Towering above the modules are the drilling rig derrick (two on someplatforms), the flare stack in some designs (also frequently cantilevered outwards) andservice cranes. Horizontal surfaces are taken up by store areas, drilling pipe deck and thevital 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.

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Other types of fixed structures are used offshore with Figure 1-2 showing the range andrelative size of typical installations. In addition, the UKCS contains a number of floatinginstallations 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 arereferred 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 capacityof an existing platform permits, subsea collecting systems linked to it by pipelines have beendeveloped. This type of development is increasingly used as smaller fields are developedand 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 combustioninstallations from small, unmanned installations in the Southern North Sea generating

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kilowatts (kW) of power to much larger manned facilities in the Northern North Sea that cangenerate over 100 megawatts of electrical power (MWe). In all, there are approximately 90offshore 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 withvery 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 importantbecause it dictates energy use (it takes more energy to produce oil than it does to producegas) and affects emissions. Gas fields tend to produce a gas with a lower molecular weightwith similar properties to the natural gas used onshore whereas the gas on an oil producertend to have a higher proportion of heavier molecular weight hydrocarbons. Regardless ofthe source, other contaminants can be present including carbon dioxide, nitrogen andsulphur compounds. (see for instance, Table 5-1 in Section 5)

1.2.1 Emissions from sectorEmissions of carbon dioxide from the offshore industry (Table 1-1) account for approximately6% of the total UK EU ETS Phase 1 emissions. The inclusion of flaring in Phase 2 willincrease 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 andengines with a smaller amount arising from the use of diesel in engines and gas and dieselin heaters and boilers. Phase 2 will include emissions from flaring. Table 1-2 summariseshistoric emissions from offshore incumbents and shows that flaring represents approximately20% of the total carbon dioxide emitted. Note that the reported emissions of carbon dioxideinclude 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

NotesPhase 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 InstallationAH001Triton FPSO

Amerada Hess Ltd

Uisge Gorm

Forties AlphaForties Bravo

Forties Charlie

Apache North Sea Limited

Forties DeltaBG Group Armada

DouglasBHP Billiton Petroleum Limited

Oil Storage Installation (OSI)AndrewBruce

ClairCleetonETAP CPF

Everest NorthFoinaven FPSO

HardingLomondMagnus

MillerRavenspurn North

BP Exploration Operating Company

SchiehallionBritannia Operator Limited BritanniaCentrica Storage Ltd Rough 47/3B

Alba FSU

Alba NorthernCaptain FPSO

ChevronTexaco Upstream Europe

Captain Platform Complex

BanffCNR International (UK) LimitedMaersk Curlew

Operator Host InstallationMurchisonNinian CentralNinian Northern

Ninian SouthernBalmoralCNR International (UK) Limited

(formerly Eni UK Limited) TiffanyJudyLOGGSMcCulloch

Murdoch

ConocoPhillips (UK) Limited

VikingHydrocarbon Resources Ltd Morecambe CPC

Global Producer IIIGryphon Alpha

Kerr-McGee North Sea (UK)Limited

Janice Alpha

Heather AlphaLundin Britain Limited

Thistle Alpha

Brae AlphaBrae BravoMarathon Oil UK Ltd

East Brae

Beryl AlphaBeryl BravoMobil North Sea Limited

Thames AlphaBuzzard

Nexen Petroleum (UK) LimitedScott

Paladin Resources plc Montrose Alpha

Indefatigable 23ALeman 27A

Perenco UK LimitedPerenco UK Limited

Trent

AnasuriaShell UK LtdAuk Alpha

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Operator Host InstallationBrent BravoBrent Charlie

Brent DeltaCormorant AlphaDunlin Alpha

Eider AlphaFulmar Alpha

Gannet AlphaLeman AlphaNelson

North CormorantPierce (Hawene Brim)Sean

ShearwaterSole Pit ClipperTern Alpha

Beatrice AlphaBleo HolmBuchan Alpha

Claymore AlphaClyde AlphaNorthern Producer (Galley)

Piper BravoSaltire Alpha (2005 only)

Talisman Energy (UK) Limited

Tartan AlphaAlwyn North

Total E&P UK PLCElgin PUQ

Tullow Oil PLC Hewett 48/29A

Tuscan Energy Ardmore (2005 only)Venture Production Company Kittiwake Alpha

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2 SECTOR STATUS IN THE EU ETS: CRITERIA FOR INCLUSION.

The offshore sector is captured within the EU ETS as a Combustion Process defined inAnnex I to the Directive and under Schedule 1 of the UKs Greenhouse Gas EmissionsTrading 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 wasnot 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 quantifiedenhanced recovery of the UKs offshore oil and gas reserves. Typical qualifying combustioninstallations can include:

Combustion installations on new offshore facilities such as platforms and FPSOsthat 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 installations capacity) in order to process hydrocarbons arisingfrom increased production either from existing or new field developments providedthat the increase in power enhances oil and gas recovery through, for instance, theaddition of gas lift facilities or water injection for optimum reservoir management.

This latter definition means that increased use of existing combustion installations forreasons other than enhanced recovery of reserves, such as injection of produced water tomeet 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 thesubmission to the DTI of an Environmental Statement under the Offshore PetroleumProduction 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 willabsorb 3 MW of power on the input shaft ie MWshaft.

So for the commonly used Gas Turbine powered Alternator, the overall efficiency from `fuelin to `electrical power out should take into account the cascaded efficiency of the thermalefficiency of the gas turbine, the mechanical losses in couplings or gearboxes, and theelectrical efficiency of the alternator.

1OSPAR 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 toincrease re-injection of produced water; the additional power for which does not qualify for access tothe NER.

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However, the case when the gas turbine directly drives a pump or compressor is slightlydifferent and for such mechanical drive the efficiency of the gas turbine (or diesel) will be thethermal 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 clearlyreflected 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, comparedto 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 spreadsheetso, throughout this report MW is used to represent both MWe and MWshaft. However, thederived 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 majorchanges to the sector are anticipated. Table 1-1 showed that the inclusion of flaring willincrease the offshore sectors contribution to EU ETS reportable CO2 emissions by roughly20%.

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 dueto the tie back of new fields. A list of the new entrants is provided below in Table 2-1 alongwith their provisional NER allocations. Two of these projects are due to commenceproduction in 2007.

There have been two retirements from the offshore sector in 2006; Talismans Saltireinstallation which fell below the 20MW(th) threshold and Tuscan Energys Ardmore fieldwhich decommissioned in 2005. In addition, Maersks (ex KMG) Global Producer III willdecommission in late 2006. No additional retirements are anticipated in Phase 1. Currentestimates are that as many as 17 offshore installations may decommission in Phase 2though it should be stressed that this represents a moving target will actualdecommissioning 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 theNER in Phase 2: however, given the current price of oil there is no reason to believe thatthere will be a significant reduction in Phase 1 levels of applications. Continued developmentof marginal oil and gas fields in the UKCS is likely to mean as many as ten applications perannum; none of these are anticipated to be in support of major new facilities such as Clair orBuzzard though Maersks GPIII will commence production from the Donan/Dumbarton fieldin late 2007/early 2008. Given the lead times for offshore developments it is likely that themajority of applications will be submitted during 2007/2008 with first oil anticipated 2008 to2010.

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

Operator Host Installation NER ProvisionalAllocation (tCO2)

Amerada Hess Ltd Triton FPSO 69,017Apache North Sea Limited Forties Alpha 183,383Apache North Sea Limited Forties Charlie 250,629BHP Billiton Petroleum Limited Douglas

383,884

BP Exploration Operating Company Andrew

21,513BP Exploration Operating Company Bruce LPBC

80,050

BP Exploration Operating Company Clair 474,677BP Exploration Operating Company Cleeton

15,178

BP Exploration Operating Company Schiehallion

26,103Britannia Operator Limited Britannia 68,068

CNR International (UK) Limited BalmoralConocoPhillips (UK) Limited MurdochEclipse Energy Ormonde 216,273Kerr-McGee North Sea (UK) Limited Global Producer IIIKerr-McGee North Sea (UK) Limited Janice AlphaLundin Britain Limited Heather Alpha 155,121Marathon Oil UK Ltd Brae Alpha 28,695Mobil North Sea Limited Thames Alpha 39,031Mobil North Sea Limited Thames Alpha 41,887Nexen Petroleum UK Ltd Buzzard 432,907Paladin Resources plc Montrose Alpha 28,590Perenco UK Limited Leman 27APerenco UK Limited Trent 215,798Shell UK Ltd Pierce (Haewene Brim) 151,529Shell UK Ltd Sean

Shell UK Ltd Shearwater

Shell UK Ltd Sole Pit Clipper

19,103Shell UK Ltd Sole Pit Clipper

7,829

Talisman Energy (UK) Limited Piper Bravo 85,807Total E&P UK PLC Alwyn North 72,438Total E&P UK PLC Elgin PUQ 19,257Total E&P UK PLC Elgin PUQ 21,002Venture 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 3.3million 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 shownin Figure 2-1. Note that the large increase from 2006 to 2007 is mainly due to the entry ofthe UK ETS opt out combustion installations following closure of the UK scheme in 2006. Toimprove clarity, Figure 2-1 does not include a legend, however, the colours representindividual facilities.

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

0

500000

1000000

1500000

2000000

2500000

2005 2006 2007

Year

tCO2

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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 themain oil line (MOL) pumps, crude export pumps and gas compression and export.

Pumps used to inject water into subsurface strata either for the purposes ofincreasing the recovery of hydrocarbons (enhanced oil recovery) or as a means ofminimising 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 fromGenesis 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 50Fresh 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

Miscellaneous2000 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 anearby facility. Some facilities use fuel gas to produce electricity which in turn is used todrive the pumps and compressors. The fact that the gas used on the facility is alsoproduced there means that, in general, its characteristics do not match the compositionsfound onshore in typical natural gas from the grid. This is discussed further below.

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Figure 3-1 Energy Use on a Typical Platform

Main Oil Line (MOL) Pumps

22%

Drilling

14%

Separation

2%

Compression

25%

Gas dehydration

2%

Water injection

11%

Miscellaneous

13%

Seawater lift pumps

3%

Cooling medium

Electrochlorinator

Instrument air

2%

Chemical injection

Heating medium

Fuel gas

3.1 Offshore Gas and Diesel CombustionGas is the predominant fuel used offshore with over 90% of fuel based emissions of carbondioxide arising from the use of gas (EEMS 2003)2. The majority of this gas comes from theprocessing of the hydrocarbons on the facility though, in some cases, fuel gas may besupplemented, or wholly arise from, gas imported from nearby facilities. The gas is ofvarying quality which depends on where in the process the gas is taken from and the natureof the hydrocarbons being processed.

Typically, diesel consumption offshore contributes less than 8% to total emissions of carbondioxide with flaring contributing roughly 20% and fuel gas making up the remaining 72%(EEMS 2003). Routine diesel consumption is typically in smaller engines driving, forinstance, 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 tripsand goes into failsafe mode. Under these circumstances, production stops and there is noavailable fuel gas: essential services switch to diesel and, in order to produce the gasneeded 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 backto fuel gas. On some installations there is little or no fuel gas and no infrastructure to importgas, in these circumstances diesel may be the only available fuel.

2The 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 usesince the mid 1990s and since then has undergone a number of revisions to improve upon theaccuracy of emissions factors.

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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 theoffshore 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 aspressure, and releases process gas to the flare to relieve this overpressure. Gas to flare cancome from a number of sources, and in order to ensure safe operation of the process, fuelgas is used to maintain a pilot light on the flare(s) and is also often used to purge vesselsand flare stacks to ensure no ingress of air (therefore minimising the risk of an explosive mixof gas and air forming). Typically purge gas is also collected and sent to flare. These twoflows 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 flowin a column. Routine flaring is generally low in oil and gas operations and is consistent withsafe operation of facility, possible exceptions are on facilities that have no economic gasexport route. In addition to routine flaring, and as discussed above, when there is a trip inthe process, the system is designed to failsafe by depressurising. The consequence of thisis that significant quantities of gas can be sent to flare over short time periods. In extremecases, this may include the safe disposal by flare of gas in the pipelines. Non routine flaringcan therefore be the major source of flaring offshore. Figure 3-2 summarises the totalemissions of carbon dioxide from flaring between 1998 and 2004, respectively.

Flaring from offshore facilities in the UKCS is controlled via the DTIs flare consent regime.This sets caps on flaring from individual facilities and requires improvements to beintroduced to further reduce flaring. The decline in flaring shown in Figure 3-2 is, in part, duethe 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

TotalCarbonDioxide(t)

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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 thesecond stage separator and from gas dehydration. Ideally, the gas used for fuel will beexport quality gas from the last stage of processing but at times the gas used can come fromthe 1st or 2nd stage separators or elsewhere in the process. The situation is furthercomplicated 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 ofsite specific emissions factors, including one for carbon dioxide, used offshore for reportingoverall emissions to the DTI within the Monitoring and Reporting framework. This isdiscussed in more detail below.

Flare gas composition can be very variable depending upon where in the process the gas toflare 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 anindustrial sector, benchmarking can be based on, for instance, energy used per unit ofproduct exported or, because in the case of the oil industry this is an energy product, energyused per barrel of oil equivalent (boe) of hydrocarbon exported where boe is a means ofcomparing oil with gas based on their energy content. Such comparisons are of limited usein the offshore industry because, as shown in Table 1-1, the major energy users are: exportpumps and gas compression requirements which can be related to the distance to themarket place (how far the facility is from the coast); and means of facilitating recovery ofhydrocarbons such as the use of gas lift and/or water injection, which can be related to thenature of the reservoir. These examples highlight the fact that energy use offshore is drivennot so much by the delivery of a unit of product but by reservoir properties, production levelsand 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 theform of gas lift (pumping gas down into the production riser) to reduce the density of the oiland/or the injection of water at the periphery of the reservoir to flush the oil out. Equally, anearby oil reservoir may be sitting under a significant gas cap (this will provide naturalpressure 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 capdecreases. This example highlights two problems that arise when trying to benchmark the

offshore industry. First, similar installations with closely matched oil and gas production mayhave completely different emissions profiles. Second, in general, an installations emissionsrise 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 andgas reserves than has historically been the case due to the fact that the large, relativelyeasily accessible fields have already been developed. Despite this, since overall productionhas fallen, emissions from the offshore industry have fallen from peak historic levels.

Benchmarking for the offshore sector is therefore based on efficiency of the combustionprocess with Table 3-2, summarising the efficiencies used in Phase 1 for existing and newcombustion 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 ofPPC permit application received by the DTI to date, from NAP applications and from

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discussions with operators. The data in Table 3-2 was derived from a combination of thesesources. Closer to Phase 2, more information will become available as the industry comeswholly 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 factorsGiven the variability of fuel gas compositions offshore the United Kingdom OffshoreOperators Associated (UKOOA) developed a methodology for determining carbon dioxide(CO2) emissions based upon site specific fuel gas characteristics. The results from thisprocess 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 factorhas been reviewed and updated on a regular basis such that there is a high confidence inthe accuracy of the factor. The factor is based on a compositional analysis of the fuel gasdetermined 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 instancenet 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 theUK/EU ETS or IPPC default factors. Note that Table 3-3 has been reproduced as is fromthe UKOOA report.

The UKOOA report concludes that the results of the study demonstrate the inadequacy ofdefault emissions factors in the calculation of CO2 emissions from fuel gas. These defaultfactors may be based on fuel volume, mass or energy, but unless the gas composition istaken into account the results are inaccurate. Default factors under-predict emissions byover 22% in the selected examples. However, using the UKCS mean (simplified) fuel gascompositions, the UK ETS and IPCC default factors showed an average error of 2.1 and5.9% respectively.

The American Petroleum Institute (API) carbon mass method is highly accurate andconsistent as it derives the emissions from fundamental calculations of carbon content (fromgas composition data) and gas mass consumption. If the quantities consumed are in units ofvolume, the gas composition data allows for accurate conversion to mass. Unlike otherschemes, there is no reliance on empirical relationships or average values.

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

Hypothetical Gas Compositions

1 2 3 4 5 6

Higher HeatingValue MW/t 13.71 9.47 10.87 11.92 14.86 12.25

Lower HeatingValue MW/t 12.53 8.62 9.86 10.79 13.49 11.11

UKOOA Reference Methodology

Calculated CO2factor (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 CO2factor (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(tCO2/10

6BTU) 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 BusinessCouncil for Sustainable Development (CO2 e.f. 56060)

Given CO2 factor(gCO2/GJ) 56000 56000 56000 56000 56000 56000


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


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 gascomposition by the inclusion of an empirical relationship between VOCs and CO2 emissions.The results show a high level of agreement with the above fundamental calculations, withdeviations of less than 0.15%.

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

1. Determination of the fuel gas density was based on an industry average of0.835kg/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 industryreported calorific values in the range 38-48 MJ/m3. A mid range figure of 43 MJ/m3was used, with an assumed efficiency, to determine the volume of fuel gas requiredto 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 factorused by the offshore industry in reporting emissions via EEMS) was calculated usingthe range of 2.6-2.9 indicated by UKOOA3. A mid range figure of 2.75tCO2/t of fuelgas was chosen for use in the NER spreadsheet excluding any adjustment for theuse of diesel.

5. The final factor used in the NER spreadsheet is expressed in terms of tCO2/MW ofdelivered power. Note that the factor used in reporting under M&R rules for theoffshore 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 fuelused for ETS-covered activities offshore. It is, however, inevitable that diesel will also beused to operate small engines (for instance, cranes and firewater pumps), for black startpurposes or as the major source of fuel in some installations. As fuel type is not permitted tobe site-specific in the calculation and diesel use is unavoidable, it is therefore necessary toinclude a diesel factor in the calculation to avoid all new allocations being underestimates. Itshould be noted that the use of gas on FPSO engines may be restricted for safety reasonsand allocations for these facilities will always be underestimated.

In order to determine a typical diesel fraction of emissions, reference has been made toEEMS 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 Phase1, offshore incumbents. A clear division is apparent at 30% emissions from diesel, and itcan be seen that platforms using 30% account for the other half. The figure also highlightsthe fact that a few users are responsible for much of the emissions from diesel with 50% ofthe emissions coming from seven facilities; these represent the installation with little or noaccess 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 reportson the results from a UKOOA funded study which was not available at the time. Information from thereport has been used to update factors as necessary. This is discussed in Section 4.

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

Cum ulative % diesel emissions vs % due to diesel 2003 (EEMS)

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%

100.0%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

% emissions due to diesel

Cumulative%

dieselemissions

Using an average diesel fraction of 30%, and assuming new entrants reflected the existingrange of facility characteristics, half of existing diesel emissions would be overestimated andhalf underestimated.

Diesel is a well-defined fuel and it can be shown that CO2 emissions from diesel equate to7.216x10-5 tCO2/MJ (3.2 tCO2/t at an energy content of 44.3 MJ/kg). Using the assumptionsfor fuel gas as given in the previous section, the equivalent figure for fuel gas is 6.396x10 -5tCO2/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 benchmarkingspreadsheet was altered to include a 4% element to account for essential diesel usechanging the factor of 2.75 to 2.9tCO2 /t. This factor, converted to tCO2 /MW as describedabove, 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 witha mid-range figure of 0.26. These numbers come from an initial survey of data reported tothe DTI via the EU ETS NAP applications and from discussions with operators. This rangereflects the nature of the fuel used offshore and the age and utilisation of the turbines and

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engines. The Phase 1 NER spreadsheet used the following values for efficiency in turbinesand engines:

TEFnew= 0.35

TEFexisting= 0.24

Efficiency from turbines and engines is particularly affected offshore by the nature of the fuelgas burned. Although discussed later (see Table 5-1, Section 5) fuel gas offshore is veryvariable and can have a high inerts content degrading performance. This is reflected in thechosen efficiencies.

Heaters are also used offshore but are responsible for only a small percentage of overallemissions. Heaters are more efficient than turbines and generators and a figure of 84% wasadopted with a correction for diesel use.

3.5 Utilisation

The rules for access to the NER onshore include a utilisation factor based on new installedcapacity and an average load factor for the sector. For instance, it is assumed that, onaverage, a sector may use 85% of installed new capacity (for every new 100MW installedonly 85MW is used). The offshore industry allows allocation of CO2 from the NER for: theinstallation of a new combustion plant either on an existing or a new facility; or for anincrease in load on an existing combustion installation provided that this leads to theenhanced recovery of hydrocarbons. This latter criterion sees no increase in capacity andtherefore, 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. Olderfacilities are typically producing at a small fraction of their historic levels and tend to havemore installed capacity than required to meet current production. This trend is compoundedby the need to maintain availability - the failure of an individual combustion installation cancause a process trip with increased flaring and loss of export. This can have a seriousknock-on effect on, for instance, onshore gas supplies. This need to maintain productionmeans that, in addition to running combustion units to provide the required power, otherunits are often run in standby mode, available to take up the load should an individual unitfail. Older facilities are also often oversized in terms of the process equipment. This isparticularly 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 therequired volumetric flow rate).

Newer developments are typically tie backs to existing facilities using the spare ullage. Thisis efficient both from an economic and environmental perspective since it minimises theinfrastructure in place in the UKCS.

A small number of offshore installations act in peak shaving mode; producing at the demandof 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 themaximum reported emissions can be used as a surrogate for capacity and that the minimum

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emission reflects the lowest utilisation. The graphs shows a wide spread of ratios. Figure3-5 shows the ratio of the average emission of CO2 in the period 1998 to 2004 against themaximum 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 utilisationinto the spreadsheet for the offshore industry was to allow site specific utilisation factors foreach combustion installation based on running hours at load. This factor is verifiable as partof the NER independent audit process.

3.6 Flaring

Benchmarking for emissions of carbon dioxide from flaring have not been included within thePhase 2 NER spreadsheet and no allowances have been allocated for flaring associated

with new combustion installations.

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

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 10 20 30 40 50 60 70 80 90 100

Installation

FractionofMaximum

Enmissions

Figure 3-5 Ration of Average and Maximum Emissions

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 10 20 30 40 50 60 70 80 90 100

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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 tonnesbased on industry average emission factors (expressed as tonnes CO2 emitted permegawatt of energy delivered the delivered power - per annum) and site specificutilisation.

Within the spreadsheet, the way in that the energy delivered is captured differs for newversus an existing combustion installation. For new combustion installations, drop downboxes with selectable power values (0, 2, 5, 10, 15 etc MW) are used. For existingcombustion installations the operator enters the actual, calculated power requirement.

As discussed above, utilisation is entered directly into the spreadsheet as running hours at10, 50, 75 and 100% of load with a maximum allowable value of 8760 hours per annum perindividual 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 fornew installations and Table 4.2 for existing installations. With the specific energyconsumption 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 *SpecificEnergy

Consumption*

EmissionsFactor

*Adjustment

factor

tCO2

UnitoutputMW

Hours atload

Tonnefuel/MWh

input

tCO2 /tonne fuel

Diesel usefactor

Table 4-2 Calculation of Allocation for Existing Combustion Installations

A = Li * Ui * SECs * EFs * Adj

Allocation =Increasein Load

* Utilisation *SpecificEnergy

Consumption*

EmissionsFactor

*Adjustment

factor

tCO2

UnitoutputMW

Hours atload

Tonnefuel/MWh

input

tCO2 /tonne fuel

Diesel usefactor

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Table 4-3 Calculation of Allocation for Existing Combustion Installations

SEC = s / CVs * TEFt / Adj

SpecificEnergy

Consumption= Density / NCV *

ThermalEfficiency

/ 1000

Tonnefuel/MWh

inputKg/m3

Net CVMJ/m3

%Convert kgto tonnes

4.2 Summary of Applied Factors

Table 4-4 Summary of Phase 1 NER Emission Factors

CO2 Emission factorEquipment Status Efficiencyt/t t/MW

New 0.35 0.6TurbinesExisting 0.24 0.86

New 0.35 0.6EnginesExisting 0.24 0.86

New 0.825 0.25Heaters

Existing 0.825

2.9

0.25Notes:

CO2 factor expressed in terms of t/MWth output.

4.3 Comparison to benchmarks used in other contexts, notably otherMember 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 ofthe 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 emissionsto the DTI via the EEMS system and therefore represent the best available without seekinginstallation specific factors.

The derived carbon dioxide factor (expressed as tCO2 per MWh) is representative of thosetypically used offshore. For instance, fuel gas is rarely, if ever, NTS quality gas and the use

of diesel is unavoidable.

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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 anew RB211C turbine rated at 28MW could select 30MW from the drop down box as thenearest 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 tomeasure this) along with the site specific emission factors. But this needs to be balancedagainst the additional work involved in the use and reviewing of the spreadsheet. This wouldalso 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 isfor five years. This is because, whereas, existing installations will tend to operate underrelatively steady state conditions, new installations may pre-invest in future compression

requirements (adding larger than immediately required equipment to be used as thereservoir depletes). The capacity will remain the same but use may vary over the five yearperiod. As it stands an operator could complete the NER form based on an average or themaximum over the five years. Addressing this issue may only require guidance as to howthe form should be completed for year on year variations in use of combustion equipment.

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5 DISCUSSION AND SUGGESTED REVISIONS TO BENCHMARKS

The approach to the benchmarking spreadsheet in Phase 1 was largely dictated by the needto follow, as closely as possible, the spreadsheets being developed for use onshore. Anumber of issues were highlighted in use of the spreadsheet during Phase 1 and theopportunity 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 range0.820 - 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 propertiesused 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 fuelgas 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 beadopted for Phase 2.

Table 5-1 Summary of Offshore Fuel Gas Properties

%CH4 %VOCVOCMwt

%CO2 %N2 %H2SAvgMwt

CO2Factor

DensityKg/m

3

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

10

15

20

25

30

35

0 20 40 60 80 100 120 140 160 180

Installation

Averag

eMolecularWeight

The calorific value of fuel gas used in Phase 1 was reported as typically in the range 38-48MJ/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

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spreadsheet, with the density, to calculate the heat released from the combustion of 1 tonneof gas.

The carbon dioxide emission factor used in Phase 1 was based on data available at the timeand an average value of 2.75tCO2 per tonne of fuel gas burned was chosen with a range ofbetween 2.6-2.975tCO2 per tonne of fuel gas burned. The 2004 data (Table 5-1), indicatesthat 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 2.77tCO 2 pertonne of fuel gas burned. This factor is used in the spreadsheet to convert heat releasedfrom the combustion of 1 tonne of gas into the tonnes of carbon dioxide emitted per tonne ofgas. It is this derived factor that is then used, with the thermal efficiency, to calculate theamount 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. Noadditional information is available and, therefore Phase 1 NER value for the efficiency of newturbines and engines has been retained. However, assessment of the Phase 1 NER datareceived to date suggests that a stricter efficiency could be applied to existing installation. Avalue 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 andis 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 hoursand 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 loadfrom the drop down menus. This will help reduce potential over allocation byselection 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 to84% for heaters. Increase efficiency from 24% to 28% for existing installations as thiswill encourage energy efficiency.

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

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.

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6 EVALUATION OF PROPOSED BENCHMARK ACCORDING TOAGREED CRITERIA

6.1 Feasibility of Verification of Utilisation

Verification of the running and load entered into the NER spreadsheet depends on theavailability of this information from operators. The majority, if not all, operators monitorcombustion plant condition on their main generating units. This includes running hours sincethis data is essential to the management of maintenance scheduling. In addition, many alsorecord load with the running hours. Using running hours and load in place of a standardutilisation 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 valueused in the offshore industry with a small component (4%) to account for unavoidable dieseluse. Use of the standard factor used by the onshore industry was rejected because it is notrepresentative of gas composition offshore. Given the disparity in gas compositionsoffshore, 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 truervalue of the resultant CO2 emissions and transparency across Monitoring & Reporting, it wasrejected because it moved away from strict benchmarking and allowed the operator toomuch freedom when entering information into the spreadsheet.

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

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7 REFERENCES

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

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