Report Version Two August 2006 Entec UK...

DTI

EU Emissions Trading Scheme Phase II Review of New Entrants' Benchmarks - Refineries

Report Version Two

August 2006

Entec UK Limited

Report for Peter Roscoe Senior Economist Energy Strategy Unit DTI Bay 286 1 Victoria Street London SW1H 0ET

Main Contributors Andrew Marsh-Patrick Michael Sorensen Laurence Anness (Solomon Associates) Bill Trout (Solomon Associates)

Issued by ………………………………………………………… Andrew Marsh-Patrick

Approved by ………………………………………………………… Alistair Ritchie

Entec UK Limited Windsor House Gadbrook Business Centre Gadbrook Road Northwich Cheshire CW9 7TN England Tel: +44 (0) 1606 354800 Fax: +44 (0) 1606 354810

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h:\projects\em-260\17000 projects\17304 ppaqcc dti eu ets ner spreadsheet\c - client\final reports - as issued (10-08-06)\refineries phase ii benchmark review06188i2.doc

DTI

EU Emissions Trading Scheme Phase II Review of New Entrants' Benchmarks - Refineries

Report Version Two

August 2006

Entec UK Limited

Certificate No. EMS 69090

In accordance with an environmentally responsible approach, this document is printed on recycled paper produced from 100% post-consumer waste, or on ECF (elemental chlorine free) paper

Certificate No. FS 13881

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Executive Summary

The purpose of this overall project is to review and validate the benchmarks that were used to determine the allocation of emissions allowances to new entrants and other installations for Phase I of the EU Emissions Trading Scheme (ETS), and to determine whether any changes to these benchmarking approaches should be considered for Phase II.

The benchmarks will be used to generate free allocations for Phase II new entrants and other incumbent installations lacking appropriate historical emissions data.

DTI has commissioned a number of separate contracts within this overall project, with each contract focussing on a specific sector covered under Phase II. This report covers the Refineries sector.

The selection of benchmarks for Phase II has been based on the following agreed evaluation criteria, together with government steers on the application and weighting of these criteria.

• Feasibility: Can the input data to the benchmark be verified? Are benchmarks based on ‘best practice’ for new entrants? Can factors be replicated by third party? Are benchmarks based on readily available data?

• Incentives for clean technology for new entrants: Are benchmarks standardised, avoiding differentiation of raw materials, technologies and fuels?

• Competitiveness and impact on investment: Is the proposed benchmark likely to meet needs for a future new entrant? If not, what is the potential impact in emissions and monetary terms?

• Consistency with incumbent allocations: How would an allocation using the proposed Phase II benchmark compare against Phase I allocations & relevant emissions?

Furthermore, for Phase II, government is proposing to move away from the integrated approach1, which applied to a few sectors in Phase I and to focus on developing benchmarks that correspond only to the direct emissions from equipment covered by the scheme. As such, the agreed focus of this project is on potential benchmarks under a direct approach.

This report is intended to accompany the overall allocation spreadsheet for the calculation of benchmarked allocations, available separately.

The work, undertaken within a tight timescale, has involved extensive information collection and analysis including contacts with key stakeholders for this sector. The previous version of this report was consulted on as part of DTI’s consultation on Phase II new entrants’ benchmarks in March and April 2006. Furthermore, the work has been subject to peer review by a sector expert appointed by DTI.

1 Under the integrated approach, the benchmark corresponded not only to the direct emissions from the new / modified equipment, but also to emissions arising elsewhere at an affected site as a result of the new / modified equipment, for example due to an increase in capacity utilisation of existing equipment.

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To provide context, a brief overview of the sector is given, including details on Phase I installations and possible new entrant technologies in Phase II. It is these technologies that the benchmark methodology is primarily focussed on. Relevant data supporting benchmarks is presented, together with a characterisation and validation of Phase I benchmarks. This is followed by an assessment of potential benchmarks, leading to the identification of a proposed Phase II benchmark. The evaluation of this benchmark against the four main criteria, mentioned above, is then presented.

In summary, the proposed Phase II benchmark formula for this sector is as follows:

Ai = Ci * U/100 * BSECt * EFt

Allocation = Capacity * Utilisation *

Solomon Benchmark Specific

Energy Consumption

* Emissions Factor

tCO2 tonnes

feedstock capacity

% kWh fuel/ tonne throughput tCO2 /kWh fuel

(net basis)

Where:

BSECt = EII/100 * SSECt

Solomon Benchmark Specific Energy Consumption

= Solomon Benchmark EII * Solomon Standard Specific

Energy Consumption

kWh fuel (net basis)/ tonne throughput % kWh fuel (net basis)/ tonne

throughput

And:

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Parameter / Variable Value

U 95%

SSECt Value determined by Solomon on application based on refinery process unit type (SSEC value is based on EU-25 refinery cohort). The Solomon SSEC values are mostly quoted per cubic metre of feedstock (or product) since this is the common unit of measurement in their database. The operator will need to convert the Solomon Associate benchmarks to a per tonne basis using actual verified feed or product density data as appropriate. This will ensure that actual feed or product density data is used to accurately convert from kWh/m3 to kWh/tonne. In the case of process units that use a crude oil feedstock only, the density value will be standardised by Solomon Associates based on a typical EU-25 refinery oil density value.

EII Value determined by Solomon on application based on worldwide top ten percent refinery performance (EII value of 88% applies to most process unit types)

EFt 0.358 kgCO2/kWh (net basis) for catalytic cracking units or 0.211 kgCO2/kWh (net basis) for all other process units

Further details are given in the main section of this report, with a summary of the contents of the report given in Section 1.3.

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Contents

1. Introduction 1

1.1 This Project 1 1.2 Evaluation Criteria and Principles for Benchmarks 1 1.2.1 Evaluation criteria 1 1.2.2 Integrated vs. direct approach 2 1.3 This Report 2

2. Background and Sector Description 3

2.1 Sector Structure 3 2.2 Process Overview 4 2.3 Phase I Incumbent and New Entrant Installations 6 2.3.1 Identification of how sector is covered under EU ETS 6 2.3.2 CO2 emissions from sector 7 2.3.3 Identification of Non-benchmarked incumbents, Benchmarked

incumbents and New Entrants 8 2.4 Possible Types of New Entrant Technologies in Phase II 9 2.4.1 Brief description of known or likely new entrants and market

developments 9 2.4.2 Summary of possible types of New Entrants in Phase II 9

3. Review of Relevant Data 11

3.1 Data Sources 11 3.2 Data from Literature 11 3.3 Benchmarks Used in Other Contexts, Including Other

Member States (if available) 13 3.3.1 Denmark 13 3.3.2 Germany 13 3.3.3 Greece 13 3.3.4 Netherlands 14 3.3.5 Sweden 14 3.3.6 Other Member States 14

4. Review of Phase I Benchmarks 15

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4.1 Characterisation of Existing New Entrant Benchmarks 15 4.2 Validation of Phase I Benchmarking Method 18

5. Assessment of Phase I Benchmarks and Proposed Revisions to these Benchmarks 19

5.1 Option 1 - Literature Based Benchmark Fuel Consumption Approach 19

5.2 Further Work Completed for Option 1 20 5.2.1 Sources of Literature Benchmark Data 20 5.2.2 Fluidised bed catalytic cracking unit benchmark 21 5.2.3 Hydrocracker unit benchmark 23 5.2.4 Hydrodesulphurisation unit benchmark 25 5.3 Option 2 - Solomon Based Benchmark Fuel Consumption

Approach 27 5.4 Further Work Completed for Option 2 (Solomon Associates

Benchmark Approach) 31 5.4.1 Process Unit Standardisation 31 5.4.2 Standardisation of Solomon Benchmark Parameters 34 5.4.3 Solomon Based Benchmark for FCC Units 38 5.4.4 Solomon Based Verification Approach 39 5.5 Option 3 - Solomon Based Integrated Refinery Energy

Efficiency Approach 40 5.6 Option 4 - Combustion Unit Thermal Efficiency Approach 41 5.7 Plant Capacity and Load Factor 41 5.8 Fuel Emission Factors 42 5.9 Further Work Completed on Fuel Emission Factors 43 5.10 Summary 44

6. Evaluation of Proposed Benchmarks 47

6.1 Introduction 47 6.2 Feasibility 47 6.3 Incentives for Clean Technology 48 6.4 Competitiveness and Impact on Investment 49 6.5 Consistency with Incumbent Allocations 50

7. Stakeholder Comments 53

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8. References 55 Table 2.1 Refinery Fuels Consumption at UK Refineries in 2004 (DTI 2005) 4 Table 2.2 CO2 Emissions and Throughput for UK Petroleum Refining Sector (DEFRA 2005a, DTI

2005) 7 Table 2.3 CO2 Emissions and NAP Data for UK Petroleum Refineries (DEFRA 2005a) 8 Table 2.4 Summary of possible types of New Entrants in Phase II 10 Table 3.1 Data from sector BREF on emission factors and capacity utilisation / load factors of best

operating practice installations relevant to Phase II New Entrants (EIPCCB 2001a) 12 Table 4.1 Characterisation of the Phase I benchmarking method 17 Table 5.1 FCC Unit Coke Yield Literature Data 22 Table 5.2 FCCU Coke Carbon Content Literature Data 22 Table 5.3 Hydrocracker Unit Literature Data 24 Table 5.4 Hydrodesulphurisation Unit Literature Data 25 Table 5.5 Protocol for Running of Solomon Database to Generate Standard SEC Value for Use in

Refinery NE Allocation 29 Table 5.6 Simplified Refinery Process Unit List for Solomon Benchmarks (Solomon 2006b) 33 Table 5.7 Typical Crude Oil Densities for 2004 (DTI 2005, Solomon 2006b) 35 Table 5.8 Standard SEC Values for NE Allocation (Copyright Solomon Associates Ltd 2006) 36 Table 5.9 Data required by Solomon Associates to determine process unit type (Solomon 2006b) 38 Table 5.10 Refinery Fuel Use (gross basis) and CO2 Emissions Data for 2003 (DEFRA 2005a) 43 Table 5.11 Summary assessment of key elements of Phase I benchmarking method and proposals

for potential revision 44

Figure 5.1 Proposed Process for Use of Solomon Based Benchmark Fuel Consumption Approach 31

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1. Introduction

1.1 This Project This research project, undertaken for DTI, is entitled “EU Emissions Trading Scheme (ETS) Phase II – UK New Entrants Spreadsheet revisions”.

The purpose of this project is to review and validate the benchmarks that were used to determine the allocation of emissions allowances to new entrants and other installations for Phase I (2005-2007) of the EU ETS, and to determine whether any changes to these benchmarking approaches should be considered for Phase II (2008-2012). The benchmarks will be used to generate free allocations for Phase II new entrants and other incumbent installations lacking appropriate historical emissions data.

DTI has commissioned a number of separate contracts within this overall project, with each contract focussing on a specific sector covered under Phase II.

The output of this research consists of an overall allocation spreadsheet for the calculation of benchmarked allocations for all sectors, as well as individual reports documenting the basis of the benchmark for each sector.

This report covers the Refineries sector.

1.2 Evaluation Criteria and Principles for Benchmarks The framework within which this research has been undertaken has been defined by evaluation criteria and principles, as provided a government Steering Group. These are briefly summarised below.

1.2.1 Evaluation criteria The research takes as its starting point the benchmarks developed for Phase I, reviewing and revising these as appropriate. The selection of benchmarks for Phase II has been based on the following agreed evaluation criteria, together with government steers on the application and weighting of these criteria.

Feasibility:

• Can the input data to the benchmark be verified?

• Are benchmarks based on ‘best practice’ for new entrants?

• Can factors be replicated by third party? Are benchmarks based on readily available data?

Incentives for clean technology for new entrants:

• Are benchmarks standardised, avoiding differentiation of raw materials, technologies, and fuels?



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Competitiveness and impact on investment:

• Is the proposed benchmark likely to meet needs for a future new entrant?

• If not, what is the potential impact in emissions and monetary terms?

Consistency with incumbent allocations:

• How would an allocation using the proposed Phase II benchmark compare against Phase I allocations & relevant emissions?

1.2.2 Integrated vs. direct approach During Phase I, most sectors’ benchmarks were based on the principle that allocations would be made to the direct emissions associated with new or modified equipment covered by the EU ETS. For the iron and steel and refining sectors, however, the benchmark corresponded not only to the direct emissions from the new / modified equipment, but also to emissions arising elsewhere at an affected site as a result of the new / modified equipment, for example due to an increase in capacity utilisation of existing equipment. This is termed the integrated approach.

For Phase II, government is proposing to move away from the integrated approach, and to focus on developing benchmarks that correspond to the direct emissions from equipment covered by the scheme. As such, the agreed focus of this project is on potential benchmarks under a direct approach.

1.3 This Report This is the report for the Refineries sector, within the overall DTI project “EU Emissions Trading Scheme (ETS) Phase II – UK New Entrants Spreadsheet revisions”.

This report is structured as follows:

• Section 2 presents the background and sector description, including a brief overview of relevant processes within the sector, details on Phase I installations and details of possible new entrant technologies in Phase II;

• Section 3 presents a review of relevant data supporting benchmarks, including details of data sources and available information on benchmarks in other Member States;

• Section 4 presents a review of Phase I benchmarks including characterisation and validation of these benchmarks;

• Section 5 presents an assessment of proposed Phase II benchmarks;

• Section 6 presents an evaluation of proposed Phase II benchmarks against the agreed evaluation criteria, summarised in Section 1.2;

• Section 7 presents stakeholder comments received during DTI’s consultation related to this project in March and April 2006; and

• Section 8 presents references.

In addition to the stakeholder consultation, this report has been subject to peer review by a sector expert appointed by DTI.



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2. Background and Sector Description

This section is intended to provide a brief overview of the sector structure and the process operations which give rise to CO2 emissions. It is not intended to be a comprehensive description of the sector and its processes. The reader should refer to the relevant BAT reference document for detailed information on the sector.

2.1 Sector Structure The main activity carried out at refineries is the separating and processing of crude oil and natural gas liquids to make fuels (e.g. petrol, diesel, LPG) and selected chemical products (e.g. white spirit, bitumen). The main operations are distillation, reforming, cracking and conversion, all of which require significant heat input via fuel combustion. Overall, refineries use around 6-7% of crude oil processed for their own energy requirements (DTI 2005).

At the end of 2004 there were 9 major refineries and three minor refineries operating in the UK. Total UK distillation capacity at the end of 2004 was 92.0 million t/yr. Total UK reforming capacity 14.2 million t/yr and cracking and conversion capacity was 36.5 million t/yr (DTI 2005). Existing UK refineries range widely in their size and complexity (from 0.7 to 16.2 million tonnes distillation capacity) with some facilities now reaching 40-50 years since first operation. Although it is considered unlikely that any new large refineries will be built in the UK in the foreseeable future, there is significant ongoing investment to replace and upgrade plant equipment at existing sites (UKPIA 2006).

The maintenance of adequate petroleum refining capacity and efficient use of all fractions of crude oil processed at refineries is a key part of the UK’s energy strategy. The UK is a net exporter of oil products and existing UK refining capacity ensures a high degree of self-sufficiency in supply of essential fuels and chemical feedstocks for industry and commerce, transport and domestic users. Total output from UK refineries in 2004, at 90 million tonnes of products, was 6% higher than in 2003. Around 75% of the UK’s primary oil production is exported, and imported crude oil accounts for two-thirds of the UK’s requirements. In future, a decline in exports and increase in imports is likely to occur as indigenous oil production declines.

The US remains one of the key markets for UK exports of oil products, with 5.3 million tonnes being exported there in 2004. These exports made up 17% of total UK exports of oil products in 2004, with the main other countries receiving UK exports being Belgium, France, Ireland, the Netherlands, and Spain (DTI 2005).

In recent years the sector has come under increasing pressure to produce cleaner fuels due to various directives, eg Sulphur Content of Liquid Fuels Directive. This has required a large investment to modify/replace existing plant and has led to significant plant downtime (DTI 2005). These plant modifications have also increased the energy intensity of the processes, leading to an increase in fuel consumption per tonne of oil processed.

The oil refining industry has used benchmarking as an aid to improving operational productivity and efficiency for two decades. Simple normalisation on the basis of crude throughput or



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product make has generally been regarded as too inaccurate to be helpful even as management information. In practice the market in refinery benchmarking has been dominated by Solomon Associates, who have developed proprietary approaches with the aim of providing useful management information by benchmarking the various components of operating cost.

2.2 Process Overview This section provides a summary of the combustion activities and process operations at petroleum refineries which give rise to CO2 emissions. For additional information, refer to the relevant sector BREFs (EIPCCB 2001a; 2001b).

In 2004, UK refineries consumed approximately 6,600 kilotonnes oil equivalent (ktoe) of energy (or 77,000 GWh) to satisfy their heat and power requirements (DTI 2005). The majority of this heat and power is generated by burning gaseous, liquid and solid fuels derived from crude oil in on-site boilers, furnaces and power plants, with the remainder being imported. Around 90% of the total energy use is for process heating and approximately 70% of refinery electricity demand is generated on-site (DTI 2005). Fuel consumption figures for refinery generated fuels in 2005 are shown in Table 2.1. Combustion of these four fuels represents the main source of refinery CO2 emissions. Some refineries also import natural gas for use as a fuel for on-site heat and power generation and this leads to additional CO2 emissions.

Table 2.1 Refinery Fuels Consumption at UK Refineries in 2004 (DTI 2005)

Refinery Generated Fuel Fuel Consumption (kt) Energy Equivalent (ktoe)

Refinery fuel gases 2,569 3,111

Refinery fuel oils 1,680 1,749

Petroleum coke 1,012 865

Gas oil 192 209

Total refinery generated fuels 5,453 5,943 1

Note

1: The difference between this total and the 6,600 ktoe total quoted above is due to use of non-refinery generated fuels such as imported natural gas.

A refinery is made up of a number of different process units for separating and converting crude oil into saleable petroleum products. The list below is intended to summarise the main distinct process units found at refineries and a description of each can be found in the sector BREF. Note that a refinery may not have all of these process units and the exact configuration varies significantly between refineries. These processes would all need to be covered separately by the benchmarking method if a direct approach were used as a NE application could be for any one of these units.



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MAIN REFINERY PROCESSES Separation Crude oil desalting/dewatering

Atmospheric distillation Vacuum distillation Light ends recovery

Conversion Thermal cracking - coking, visbreaking Catalytic cracking Hydrocracking Steam cracking Catalytic reforming Isomerisation Alkylation and polymerisation

Treating Processes Hydrodesulphurisation Hydrotreating Extraction Bitumen blowing Lube oil manufacture

Auxiliary Facilities Boilers/process heaters Hydrogen production Sulphur recovery and production Compressor engines Power generation Blowdown systems Flares

Refinery complexity varies significantly and there is no standard configuration which presents problems for CO2 emission benchmarking. A wide variety of different crude oils are used and different refinery process configurations are applied to produce a wide range of products. Whilst all refineries have crude oil distillation, there are many options for further processing to enhance the yield of more valuable products (e.g. to increase yield of transport fuels at the expense of heavy fuel oil), and to produce cleaner products meeting the specifications for sulphur-free petrol and diesel. In addition some refineries may produce lubricants or speciality chemical streams. All refineries use considerable quantities of steam and significant amounts of power, and there are a variety of ways of supplying these either on-site or with import arrangements. Traditionally refineries have been designed to use refinery fuel gas and refinery fuel oil produced in their own operations, although in recent years some refineries have been able to take advantage of the possibility to import natural gas as part of the refinery fuel mix. Refineries need to use increasing quantities of hydrogen to remove sulphur from the product streams, and a refinery with a hydrocracker will need to use large quantities of hydrogen, resulting in a refinery gas with higher carbon content. As a result of this complexity, CO2 emissions per tonne of product from a specific refinery unit are dependant on a number of factors including feedstock properties, fuel mix, operating temperature and pressure, and product mix and specification.

Most refinery sites have several direct fired process heaters, gas turbines, incinerators and flare stacks together with steam raising plant, which may include electricity generating facilities and



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Combined Heat and Power facilities (CHP). These combustion processes generate CO2 emissions and are normally fuelled by refinery-generated fuel gas and fuel oil systems, although natural gas may also be imported to site. The capacity of refinery combustion units varies widely from less than 10 megawatts thermal input (MWth) up to 200 MWth. Total installed capacities at individual refineries range from several hundred to 1300 MWth or more on the largest refineries (EA 1995a). In some refinery process units such as fluidized bed catalytic cracking (FCC) units the process feedstock itself is partially consumed to provide heat, leading to ‘process’ (rather than ‘combustion’) CO2 emissions. Process CO2 emissions are also generated from a number of other refinery units due to partial combustion of feedstocks, regeneration of catalysts and flaring. Since all refinery CO2 emissions are covered by Annex I of the EU ETS Directive the distinction between process and combustion CO2 for this sector is not significant in terms of NER allocation.

A variety of furnaces and burner types are used in refineries, largely determined by the heat release characteristics required by a particular process. Many furnaces are dual-fired (oil/gas) to allow flexibility in the refinery fuel system. Petroleum coke is also manufactured at refineries and some of the product is consumed for on-site heating purposes. Refinery process heaters are typically rectangular or cylindrical enclosures with multiple up-fired burners of specialised design using mainly low combustion intensity while boilers are generally fairly standard steam producing units of medium or high combustion intensity (EA 1995a). The proportion of energy supplied by fuel oil and gas oil is normally >20% and can be up to 60% at some refineries (the remainder being supplied by refinery fuel gas, natural gas and coke). Bearing in mind the highly integrated and interdependent nature of the refinery processes, refinery operators aim to match continuously the variable production and consumption of fuels on processes and utilities at the lowest economic and environmental cost (EA 1995a). Although fuel switching at refineries is technically possible, economic and practical considerations limit the fuel switching options. For example, there are high capital costs for installing a natural gas pipeline to supply a refinery and limited alternative disposal routes for refinery fuel oil which may be high in sulphur content. Currently 3 UK refineries use significant amounts of natural gas amounting to energy use of approximately 5.7 TWh/year or 8% of all refinery fuel use (DTI 2005). Wholesale fuel switching to natural gas at UK refineries would require a net increase in total UK natural gas supplies of 6% (66 TWh/year) which would potentially threaten UK energy security and diversity.

Sector guidance (EIPCCB 2001a; EA 1995a) on best practice states that as far as possible, refinery fuel demand should be minimised by making maximum use of heat recovery and exchange techniques to meet process heating duties. New and revamped-fired heaters should be of energy efficient design with modern control systems (EA 1995a). Many refineries have on-site CHP units, which burn refinery fuels to generate electricity. To help reduce CO2 emissions from generation, energy efficient electrical equipment such as variable speed drives (VSDs) should also be used where appropriate (EA 1995a).

2.3 Phase I Incumbent and New Entrant Installations

2.3.1 Identification of how sector is covered under EU ETS Petroleum refineries are covered by Annex I of the EU ETS Directive under ‘mineral oil refineries’. All refinery activities are covered and there is no de-minimis limit for inclusion of CO2 emissions from refinery installations or individual refinery sources. CO2 emitted from a



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multitude of small refinery sources, such as flare stacks and process vents is therefore included. Each refinery may have, say, 10 large points sources of CO2 emissions (i.e. boilers, direct fired process heaters, CHP units) and as many as 50 or so smaller point sources (i.e. flare stacks, process vents, smaller process heaters) which are all captured under the EU ETS.

2.3.2 CO2 emissions from sector The table below presents the total carbon dioxide emissions arising from UK petroleum refinery operations over the years 1998-2003. Equivalent data for 2004 and 2005 are not available at this time.

Table 2.2 CO2 Emissions and Throughput for UK Petroleum Refining Sector (DEFRA 2005a, DTI 2005)

Year Primary Oil Feedstock (kt)

CO2 Emissions (kt)

Specific Emission Factor (tCO2/t oil

processed)

Increase in Emission Factor

(% c.f. 1998)

1998 93797 18054 0.1925 0.0

1999 88286 17304 0.1960 1.8

2000 88014 18036 0.2049 6.5

2001 83343 17111 0.2053 6.7

2002 84784 18150 0.2141 11.2

2003 84585 18061 0.2135 10.9

The data above indicates the general increase in CO2 emissions per tonne of oil processed. Emissions intensity has increased by over 10% since 1998, largely due to the requirements to process petroleum products to meet tighter product standards, for example to reduce sulphur content, which requires more energy input and hence increases CO2 emissions. This trend is likely to continue due to increased conversion of heavier feedstocks to meet the demand for lighter-fraction transport fuels (e.g. aviation fuel) and a drop in demand for heavier fuels (e.g. fuel oil). Under the revised NAP, the oil refining sector has been granted a total Phase I allocation of 19,430 ktCO2/year. Therefore the NAP allocation is 7.6 % above the 2003 sector total emission level.

The data from the revised NAP (14th February 2005) is summarised below.



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Table 2.3 CO2 Emissions and NAP Data for UK Petroleum Refineries (DEFRA 2005a)

Note 1: The ‘relevant emission’ data are taken from the revised phase I NAP and are for baseline period of 1998-2003.

The above data on 2003 actual emissions and the revised NAP allocations for each refinery can be used to analyse the impact of different benchmark emissions allocation methods on refineries as a whole. However, data on energy use and CO2 emissions for individual process units at UK refineries is not readily available as it is considered to be confidential by refinery operators.

2.3.3 Identification of Non-benchmarked incumbents, Benchmarked incumbents and New Entrants

The refinery sector incumbents in Phase I of the EU ETS are identified by their NAP ID in Table 2.3 above. Allocations for these incumbents were not based on benchmarks in Phase I since they have been operating for some time and had sufficient historical emissions data from which to make Phase I allocations. The only known proposal for a new entrant in Phase I was for the rebuild of a FCC unit at an existing refinery installation operated by BP Ltd. In this case the Phase I benchmarking method is applicable, although the existing refinery NE allocation spreadsheet does not provide any benchmarks and therefore requires a verifier’s opinion to determine the allocation. DEFRA has provided guidance on new entrant verification (DEFRA 2005b) and this should be referred to as required.

No. Operator Refinery Name NAP ID EU ETS Sector

Annual Allocation

during Phase 1

2003 Emission

(tCO2)

Relevant Emission

(tCO2)

1 Shell UK Ltd Stanlow 407 Refineries 2,967,750 2,807,950 2,781,0122 Exxon Mobil Co. Ltd Fawley 403 Refineries 3,624,339 3,368,808 3,396,2883 BP Ltd Coryton 399 Refineries 2,397,369 2,234,091 2,246,5214 BP Ltd Grangemouth 409 Refineries 1,464,020 1,414,547 1,371,9015 Total Fina Elf Ltd. Lindsey Oil Refinery 2960 Refineries 2,115,851 1,911,647 1,982,7176 Texaco Refining Co. Ltd Pembroke 408 Refineries 2,176,095 1,819,991 2,039,1707 Conoco Ltd Killingholme 4077 Refineries 2,580,953 2,424,954 2,418,5538 Total Fina Elf / Murco Pet. Ltd Milford Haven 402 Refineries 1,221,633 1,178,740 1,144,7659 Petroplus International Ltd North Tees 406 Refineries 283,919 245,018 266,054

10 Petrochem Carless Ltd Harwich 405 Chemicals -- CIA 37,998 34,769 43,44611 Eastham Refinery Ltd Eastham 401 Refineries -- CIA 58,250 48,799 55,63712 Nynas UK AB Dundee (Camperdown) 410 Refineries -- CIA 22,568 20,500 21,55513 NPower Cogen Trading Ltd Fawley 2531 Refineries 479,983 551,043 449,781

2&13 Total for Fawley Refinery Fawley 403 & 2531 Refineries 4,104,322 3,919,851 3,846,069Total all UK Refineries 19,430,727 18,060,857 18,217,401

Refinery Emissions Data and NAP Allocations



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2.4 Possible Types of New Entrant Technologies in Phase II

2.4.1 Brief description of known or likely new entrants and market developments

There is an expectation/speculation of significant investment at selected sites in the refining sector. Investment may include capacity for biofuels processing and conversion projects to destroy heavy fuel oil to make more valuable products such as jet fuel. Whilst it was relatively easy to predict immediately before the start of Phase I which new plants/developments were likely to come on-stream (i.e. 1 year ahead), Phase II developments (2008-2012) are difficult to predict at this early stage (i.e. 3-7 years ahead). Data provided by the DTI indicates that Phase II new entrants may include:

• Two refineries installing new boilers/CHP units;

• One refinery installing a hydrodesulphurisation unit; and,

• One refinery installing a full conversion hydrocracker.

It also noted that drivers for future increases in UK refinery CO2 emissions will include:

• Tighter fuel specifications which will require more intensive processing of crude oil fractions. This will exert an upward pressure on refinery energy use and CO2 emissions;

• Increased processing of heavier and sourer crude oils. This will increase refinery energy use and CO2 emissions per unit of throughput compared to processing lighter sweet crude oil feedstocks.

• Production rates of sweet light North Sea crude oil are declining and this trend is set to continue. Many UK refineries were designed to process this feedstock but are now installing additional process units to process imported heavier sourer crude oil. Lower quality feedstocks are cheaper and refineries that can process heavier sourer crude tend to have higher profit margins.

2.4.2 Summary of possible types of New Entrants in Phase II A summary of possible types of New Entrants in Phase II is given in Table 2.4.



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Type of New Entrant Is this type of New Entrant realistically possible in Phase II? (Y/N)

Technology type(s)? Fuel type(s)? Other relevant details

New installation Y New installations for biofuels refining are possible in the UK but the sector association (UKPIA) consider a major a new installation for mineral oil refining to be unlikely.

Refinery fuel oil and refinery fuel gas, possibly natural gas and biofuels

Several UK oil refineries have closed in the past 10 years due to industry rationalisation and competition. The remaining nine UK large refineries have adequate capacity to supply the UK's oil refining needs at this time.

New piece of equipment to increase capacity

Y New cracking units to expand capacity and biofuels distillation units are possible at existing mineral oil refineries. In theory, an operator could install any one of the main types of process unit found at refineries as part of a capacity increase.


It is difficult to predict what new plants will come on line in Phase II due to the commercial confidentiality of operator's refinery development plans. The demand for production of biofuels and tightening fuel emission standards are the main drivers for new plant investment.

Extension to existing piece of equipment to increase capacity

Y Modifications to existing cracking and distillation units to increase production and replace end-of-life equipment at mineral oil refineries are likely. In theory, an operator could rebuild/extend any one of the main types of process unit found at refineries as part of a capacity increase.


The increasing demand for cleaner transport fuels and the need to replace ageing plant, often with new plant of a larger capacity, will be the main drivers for plant extensions/rebuilds. In phase I, one company planned to rebuild a fluidised catalytic cracker unit, leading to a refinery capacity increase and an application to the NER.

Table 2.4 Summary of possible types of New Entrants in Phase II



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3. Review of Relevant Data

3.1 Data Sources The following organisations in the sector have been contacted during this study:

• UK Petroleum Industries Association (UKPIA);

• CONCAWE (European oil industry association);

• EUROPIA (European petroleum industry association);

• Selected refinery operators; and

• Solomon Associates Ltd (refinery benchmarking company).

These organisations have provided commentary on key issues which has been used to inform the assessment and development of alternative allocation methods. A range of additional data sources on refinery energy use and CO2 emissions have been obtained and reviewed, as follows:

• FES report and spreadsheet on NE allocations, including methods for CHP units, boilers and refinery processes;

• Phase I NAP submission forms for the 12 UK petroleum refineries;

• Digest of UK Energy Statistics 2005;

• European BREF on mineral oil refineries;

• Journal articles on energy use benchmarking for refineries; and

• Papers on allocation methodologies from other member states.

The above data sources have been useful in assessing aggregate energy use figures for some European refineries and also specific energy use for some types of process units. Total fuel use data for individual UK refineries has been obtained from the NAP submission forms and this information has been used to inform the analysis but is not reproduced in this report due to confidentiality.

3.2 Data from Literature Data from literature searches and other sources on emission factors and capacity utilisation / load factors of best operating practice installations relevant to Phase II New Entrants is summarised in Table 3.1 below. The only source of readily available fuel use and CO2 emission data for individual process units is the sector BREF as this type of data is usually treated as confidential by the operators. The table presents a summary of the data in the BREF for different types of process unit typically found at a refinery. It is not an exhaustive list but simply illustrates the variation in emission factors between common process unit types at different refineries. The key point to be taken from the table is that energy use varies



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significantly between process units depending on their feedstock and product mix and that there are many types of process unit, making benchmarking complex.

Table 3.1 Data from sector BREF on emission factors and capacity utilisation / load factors of best operating practice installations relevant to Phase II New Entrants (EIPCCB 2001a)

Type of installation and process unit

Unit Throughput (t feed/year)

Fuel consumption (GWh/year) - gross basis

Specific fuel use (MWh/t feed unless specified) - gross basis

CO2 emissions (t/year)

Specific CO2 emissions (kg/t feed)

OMV Schwechat refinery, Naptha Hydrotreater

1,160,000 205.9 0.178 40,152 35

Mider refinery, Naptha Hydrotreater

1,500,000 205.9 0.137 39,937 27

OMV Schwechat refinery, Middle Distillate Unit

1,780,000 135.8 0.076

26,341 15

Mider refinery, Middle Distillate Unit

3,000,000 205.9 0.069 39,937 13

OMV Schwechat refinery, Vacuum Distillate Unit

1,820,000 72.4 0.040 19,466 11

Mider refinery, Vacuum Distillate Unit

2,600,000 578.2 0.222 164,776 63

Hydrocracking No data No data 0.111-0.333 (also steam produced 30-300 kg/t feed)

No data No data

Hydroconversion No data No data 0.167-0.278 (also steam produced 200-300 kg/t feed)

No data No data

Steam reforming No data No data 9.72-22.22 MWh/t H2 produced (also steam produced 2-8 t/t H2)

No data No data

Hydrotreatment of naptha

No data No data 0.056-0.097 No data No data

Hydrotreatment of distillate


Hydrotreatment of residue


From the table above the key points are as follows:

• The specific energy consumption and specific CO2 emissions for each type of refinery process unit varies significantly between refineries (e.g. hydrocracking 400-1200 MJ/t feed);



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• This significant variation is a complex function of parameters such as the feedstock composition, degree of feedstock conversion, process conditions and product yield; and

• It may not be possible to accurately predict energy use or CO2 emissions with use of a single factor (i.e. MJ/t feed) for each process unit.

The data presented above is not further assessed or discussed since it is considered to be of limited use for the purposes of benchmarking new entrants and is not subsequently used in this study.

3.3 Benchmarks Used in Other Contexts, Including Other Member States (if available)

Investigations have been undertaken to try to identify benchmarking approaches for new entrants in other Member States. Overall, the extent of information available within the tight timescales of this study has been limited. Furthermore, information will tend to relate to Phase I approaches, and hence may not be indicative of approaches in Phase II, which this study is focussed on. Notwithstanding this, it is useful to consider these approaches, as briefly summarised below.

3.3.1 Denmark The Danish NAP assumes an efficiency factor of 0.9 for new entrants but no distinction is made between sectors for this factor. No discussion of new entrant benchmarks or formula.

3.3.2 Germany New entrants are granted allocation on BAT benchmarks. These benchmarks are established for installations with comparable products, and derived from BAT for new installations in that class. Also, each product category will have a benchmark. New entrants that don’t have defined benchmarks will be granted allowance based on BAT.

New entrant formula (industry non-specific);

Allocationi = Ci · PiU ·BAT,

where

i is an index for the installation;

Ci is the installation-specific output capacity in MW;

PiU is the projected utilisation or load factor by installation; and

BAT BAT benchmark for emissions per output unit.

3.3.3 Greece Known new entrant allocation for specific sectors including; steelworks and refineries.

Ai = Pi x Hi x 3.6 x 10-3 x BAi x EFj x CFi



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where

Ai = annual installation-i allowances (t CO2/year);

Pi = new entrants installations-i power (MW);

Hi = installation’s-i hours of operation (h/year);

BAi = installation’s-i efficiency ratio;

CFi = installation’s-i compliance factor (compliance factor less than or equal to 1).

3.3.4 Netherlands The allocation is based on refineries attaining top 10% performance worldwide, using the Solomon Energy Intensity Index (EII). The Solomon EII is a proprietary energy efficiency index for refineries operating across the world. It is understood that Dutch industry argued for this approach (c.f. simply using refinery energy use per tonne of throughput) on the basis that it is more accurate for benchmarking.

3.3.5 Sweden Allocation05-07 = k x Projected output05-07 x BM / BAT

Where

k = Scale factor applied to fuel-related emissions from combustion installations in the energy sector. For non energy sector sites, k = 1.0;

Projected output05-07 = emissions in accordance with projected produced quantity of installation-specific product 2005-2007. Only production based on fossil fuels is meant for electricity and heat production;

BM = Benchmark emission factor;

BAT = Corresponds to estimated specific emissions at installation (tCO2/t product).

3.3.6 Other Member States For a number of other Member States, the readily available information simply indicates that new entrant allocations are to be based on BAT levels of performance. This applies to Czech Republic, Ireland, Malta, Portugal (explicitly stating BAT Reference Documents), Slovenia (also referencing BAT Reference Documents), and Spain.

Based on this data the Netherlands is the only Member State we are currently aware of that provides a benchmark value for refineries and this involves use of the Solomon Energy Intensity Index (EII)2. Other Member States such as Germany and Greece provide equations to determine refinery allocations but benchmark values to be used for each parameter in the equations are not given.

2 The Energy Intensity Index (EII) is a proprietary energy benchmarking method for refineries that has been developed by Solomon Associates Ltd. Information on the EII that is presented in this report should not be used without the prior permission of Solomon Associates Ltd.



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4. Review of Phase I Benchmarks

4.1 Characterisation of Existing New Entrant Benchmarks

The existing allocation methodology (used in Phase I) for new entrant refineries from the FES report3 is as follows:

Ai = Ci * Us/100 * SECt * EFf

Allocation = Capacity * Utilisation * Benchmark Specific

Energy Consumption

* Emissions Factor

tCO2 tonnes

feedstock capacity

% tonnes fuel/ tonne throughput tCO2 / t fuel

The FES report suggests that this equation be applied to new fluidised bed catalytic cracking (FCC) units but does not provide any guidance on the values to be used for parameters such as benchmark fuel consumption. Standard emission factors (tCO2/t fuel) for different types of refinery fuels are quoted in the FES report, although in the NAP submissions, each refinery used different emission factors according to their own site specific fuel data.

The current NE spreadsheet4 uses a different allocation equation for FCC units as follows:

Ai = Qi * Mi/100 * Ni/100

Allocation = Throughput * Mass percentage of feed

consumed as primary fuel

* Carbon content of primary fuel

tCO2 tonnes

feedstock throughput

% %

3 EU Emissions Trading Scheme – Calculating the Free Allocation for New Entrants, Report for DTI produced by Future Energy Solutions (FES), November 2004, 4 Calculating the Allocation for New Entrants: spreadsheet for applicants by FES, updated 23rd May 2005, available at www.dti.gov.uk.



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The NE spreadsheet does not provide any guidance on the values to be used for parameters such as the quantity of feed consumed as fuel in a FCC unit. The value for annual fresh feed throughput is equivalent to the actual feedstock processed by the unit per annum.

As such the allocation methods for refinery new entrants are not based on BAT benchmarks, a verifiers opinion is required to assess applications from refinery new entrants in Phase I. Although the approach adopted for Phase I for the refinery sector as a whole was an ‘integrated’ one, the specific formula for the FCC benchmarked allocation is in fact closer to a ‘direct’ approach. The FES equations take a ‘direct’ approach to allocation by calculating the CO2 emissions from the new refinery unit itself (i.e. a FCC unit). They do not take an ‘integrated’ approach to allocating allowances for CO2 emissions in that the net impact of the new unit on refinery total emissions is not considered. The difference between ‘direct’ and integrated approaches is summarised as follows:

• A direct approach means that allocations are awarded only for the emissions arising directly from a new piece of equipment added to an installation. For example, if a site adds new boiler or CHP capacity, then it will be given a new entrant allocation based on the capacity of that piece of equipment. By contrast, if the new piece of equipment does not directly produce any emissions, it is not eligible for a new entrant allocation. For example, the addition of a new paper machine to a paper mill typically would not qualify for a new entrant allocation, as there are no emissions directly from the paper machine (even though its addition may result in higher emissions as existing boiler/CHP capacity is run harder once the new paper machine is added).

• An integrated approach means that the benchmark is based on the production capacity of the installation as a whole. For example, in integrated steelworks, the allocation is calculated on the basis of the production capacity of liquid steel by the whole steelworks. If equipment is added to the site then the new entrant allocation is based on the resulting change in total production capacity. For example, the addition of a new ladle is likely to lead to higher utilisation of other components of the works (blast furnace, casting, rolling, etc.), and the new entrant allocation therefore also is likely to exceed the emissions produced directly by the new ladle itself.

The DTI have indicated that they wish to pursue a direct approach to allocating NE allowances in Phase II.

In the FES report, load factors and allocation methodologies are given for standard boilers (i.e. ‘other combustion plant >20 MW’) and CHP plants operating in the refinery sector.

Therefore, the main gap for this sector is in the development of new entrant benchmarks for the multitude of refinery CO2 sources which are not covered by the methodology for standard boilers, CHP units or electricity generators in the FES report. These sources include but are not limited to FCC units, crude distillation units, steam reformers, hydrocrackers, hydrodesulphurisation units, direct fired process heaters, flare stacks, etc.

A characterisation of the Phase I benchmarking method is given in Table 4.1.



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Table 4.1 Characterisation of the Phase I benchmarking method

Item Parameter value / details

Justification for choice of parameter value / details given by FES

Source of data

Coverage of activities (how does the coverage of activities included in the spreadsheet compare to the activities in the sector that are covered by EU ETS)

Only covers FCC units. Other types of unit would be assessed on an ad-hoc basis by the DTI

A FCC unit rebuild was the only known new entrant proposal at the time of the FES report

The BREF for mineral oil refineries was consulted by FES but no BREF data was used in the final report.

Level of sector differentiation (Is there one set of formulae / parameter values for the whole sector, or are there separate formulae / parameter values for different technologies, fuels, products etc)

Allocation is made separately for each refinery process unit but only an equation for FCC units is given.

There are a number of different types of refinery process units to perform different functions. Benchmarks are required for each type of unit.

Industry consultation on new entrant types. The BREF for mineral oil refineries was consulted by FES but no BREF data was used in the final report.

Degree of standardisation of formulae (ie what types of input parameters are required in the formulae?)

Simple standard formula calculates actual CO2 emissions from consumption of feedstock as fuel but is not benchmarked

Simple approach but specific standardised values are not proposed and values are assumed to vary by installation.

Industry consultation on key parameters

Technology / process types (What types of technologies / processes are used as the basis for the parameter values?)

Only covers FCC units. Pre-heating of feed is not covered.

Simple approach Industry consultation on new entrant technologies

Fuels assumed (What types of fuels are used as the basis for the parameter values?)

User defines carbon content of feedstock used as fuel

Simple approach No fuel use benchmarks provided

Emission factors (What are the fuel CO2 and Process CO2 emission factors?)

User defines proportion of feedstock used as fuel

Simple approach No fuel emission factor benchmarks provided

Capacity utilisation factors / load factors (What are the values for these factors?)

User defines annual feedstock throughput

Simple approach No load factor benchmarks provided

Other assumed parameters, excluding input parameters (one row per parameter to identify the parameter – what are the values for these parameters?)

n/a n/a n/a



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4.2 Validation of Phase I Benchmarking Method Since the Phase 1 benchmarking method only applies to FCC units and does not provide any benchmarks at all it is not possible to make any meaningful validation of the existing NE spreadsheet for refineries.

If data were available for existing refinery FCC units (this data is considered confidential by operators) then use of the allocation equation would simply allow calculation of actual CO2 emissions, rather than benchmark CO2 emissions. This is because the spreadsheet simply calculates the actual CO2 emissions from the FCC unit based on three user defined parameters. The allocation is then set to be equal to the actual CO2 emission predicted. Therefore the new entrant will receive 100% of its predicted CO2 emissions as an allocation. New entrant guidance states that a verifier’s opinion is also required for refinery applications. This would involve auditing of the values entered for the user defined parameters to ensure that they are accurate and representative of the proposed FCC unit. DEFRA guidance refers to the NE operator providing a Design Report containing documentation to demonstrate that the projected inputs for the NE spreadsheet are reasonable (DEFRA 2005b). The verifier will use the Design Report to examine the figures used and the justification of these figures (DEFRA 2005a).

It is concluded that the Phase 1 benchmarking method is not comprehensive enough to cover all potential refinery new entrants. The list of main refinery units given earlier indicates the extent of required coverage of the benchmarking method for refineries.



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5. Assessment of Phase I Benchmarks and Proposed Revisions to these Benchmarks

Based on the research completed so far, there are four types of alternative benchmarking methodology that may be appropriate for use in the refinery sector, as follows:

5.1 Option 1 - Literature Based Benchmark Fuel Consumption Approach

This approach would use the existing allocation equations given in the FES report and spreadsheet but would be applied to different types of refinery unit using single literature-based value for benchmark fuel consumption.

As summarised earlier, the refinery BAT Reference Document (BREF) reports values for fuel use in different types of refinery unit (e.g. hydrocracking in the range 400-1200 MJ per tonne of throughput). For example the allocation equation for a hydrocracker could be based on the lowest achievable value of 400 MJ (gross basis) per tonne of throughput and would then be:

Ai = Ci * Us/100 * SECt * EFf

Allocation = Capacity * Utilisation * Benchmark Specific

Energy Consumption

* Emissions Factor

tCO2 tonnes

feedstock capacity

% MJ fuel/ tonne throughput tCO2 /MJ fuel

Where:


SECt 400 MJ/tonne of throughput for a hydrocracker unit

An initial review of the international literature on refinery fuel consumption was carried out with the aim of deriving a standard benchmark value for each type of refinery unit. However, whilst this approach would be transparent and simple, it became clear that the published data on refinery energy use is not comprehensive or detailed enough for benchmarking. Much of the data required is confidential and is not available in the public domain. The further problem with this approach is that a single benchmark value for a process unit would not take account of the significant variations in the type of technology employed, feed composition, operating



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conditions or process energy outputs such as steam and hydrogen. All of these parameters affect energy use and CO2 emissions and it is beyond the scope of this study to fully describe these complex aspects of refinery unit design and operation. However, variations in these parameters are the result of genuine differences between refinery units in terms of the intended product mix and they do not represent more/less energy efficient means of making the same products.

5.2 Further Work Completed for Option 1 The literature-based benchmark approach (Option 1) has been further developed following the stakeholder consultation in co-operation with the government Steering Group. A more detailed review of literature benchmarks for the following likely Phase II new entrants was carried out using a range of international literature sources:

1. Fluidised bed catalytic cracking units;

2. Hydrocracking units; and,

3. Hydrodesulphurisation units.

5.2.1 Sources of Literature Benchmark Data The Best Available Techniques reference document (BREF) for mineral oil and gas refineries was the first point of reference for developing formulae, but was found to contain little detailed data. Therefore a wide trawl of published papers was required. Unfortunately very little applicable data published in English language and available in the public domain was found, and some of that was not always fully transparent.

On searching for data for this study it was soon recognised that applicable references would be difficult to find given the timescales available. The following terms were used in combination and with ‘wild cards’ during various searches:

• petrochem • refining and/or refinery • emissions • energy • hydrocracker • hydrodesulphurisation • FCCU • catalytic cracker • CO2

The following data bases were searched:

• Chemical Abstracts • ISI Web of Knowledge • Science Direct • British Library Inside Web



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• Knovel e-books

Searches were made of the internet using Google. Also, websites of the relevant organisations were searched, including:

• Environment Agency (EA); • Department for Trade and Industry (DTI); • UK Petroleum Industry Association (UKPIA); • Institution of Chemical Engineers (IChemE); • American Institute of Chemical Engineers (AIChemE); • US Environmental Protection Agency (EPA); • American Petroleum Institute (API); and, • US Department of Energy.

Also, company websites, including those of oil companies, design engineers and catalyst manufacturers were searched. They included Shell, BP, Total, ExxonMobil, UOP, Foster Wheeler, Grace Davison, Engelhard.

5.2.2 Fluidised bed catalytic cracking unit benchmark Catalytic cracking is the most widely used conversion process for upgrading heavier hydrocarbons into more valuable lower boiling hydrocarbons (EIPCCB 2001), and FCC are the most common type of catalytic cracking unit. They use heat and a catalyst to break larger hydrocarbon molecules into smaller, lighter molecules.

The FCC unit consists of three distinct sections, the reactor-regenerator section including air blower and waste heat boiler, the main fractionator section including wet gas compressor; and the unsaturated gas plant section.

The cracking process takes place at temperatures between 500 and 540°C and a pressure of 1.5 - 2.0 barg. The catalysts are usually zeolites (some 15% by weight) supported by amorphous synthetic silica-alumina with metals. It is in a fine, granular form which mixes intimately with the vaporised feed.

Having passed through a reactor section, the fluidised catalyst and reacted hydrocarbon vapour are separated mechanically in a (two-stage) cyclone system. Any oil remaining on the catalyst is removed by steam stripping and the catalyst is returned for reuse. The catalytic cracking process produces coke, which collects on the catalyst surface and diminishes its catalytic properties. The catalyst therefore needs to be regenerated by ‘burning off’ the coke, which is an integral part of the catalyst circulation.

Regeneration of the catalyst produces carbon monoxide (CO) and CO2. Most units include a CO boiler, which converts most of the CO to CO2. Catalyst cannot be continually regenerated, and a certain amount is continually removed and replaced with fresh catalyst.

Although there are a number of energy users on an FCC unit, the only source of CO2 from the unit itself is the catalyst regeneration stage. Therefore, CO2 emissions are directly related to:

• Amount of coke removed from the catalyst at the regenerator;

• Carbon content of the coke;



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• Degree of conversion of coke to CO2.

In simple terms, the cracking process converts feedstock into products and coke. The ‘coke yield’ of a unit is the percentage (by weight) of the feedstock that becomes coke on the circulating catalyst. Given that this coke is the source of CO2 emissions for the FCC unit, this parameter is of particular interest when developing the emissions benchmark.

A coke yield in the range 5 to 8% is considered to be ‘normal’ for an FCC unit (Colorado school of mines). However, this can vary considerably, with 15% being normal in some circumstances (i.e. processing of heavier feedstock).

The following table summarises coke yield quoted in the literature.

Table 5.1 FCC Unit Coke Yield Literature Data

Coke yield range Reference

4.2 - 4.4 % McKinney et al 2002

4.9 - 5.0 % Engelhard

5.6 % Couch et al 2003

6.0 - 10.9 % Grace Davison

The actual coke yield depends on a number of factors including:

• Nature of feedstock;

• Type of catalyst;

• Rate at which catalyst is replaced with fresh;

• Process conditions in the cracking and regeneration stages of the unit.

From a BAT perspective, it seems reasonable to suggest that the lower coke yields quoted in the literature are achievable. Excluding the very lowest figures that may include some marketing hype, it is proposed that a benchmark figure for coke yield could be taken as 5%.

Little data has been found in the literature about the carbon content in FCC coke. This is probably because catalyst regeneration is an integral part of the FCC unit and so the coke is not an easily distinguished product. The following table reports two figures for ‘petroleum coke.’

Table 5.2 FCCU Coke Carbon Content Literature Data

Coke carbon content Reference

91 % Ritter et al 2005

90 - 92 % US EPA 2003



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Taking the average of these values it is suggested that the standard carbon content of the coke is considered at 91%.

A two stage conversion process involving regenerator and CO boiler would be considered best practice. It is proposed full conversion of coke to CO2 is considered achievable.

The aim of the FCC regenerator is to remove coke in a way that minimises pollution. This is generally understood to mean minimising the amount of CO emitted, but this is achieved by maximising the proportion of CO2 in the flue gases. This means BAT applies more to the recovery of as much energy from the regeneration process, rather than reduction in CO2.

There are other uses of energy from external sources, and clearly BAT applies to these but is not relevant to this study.

Given that FCC emissions are process CO2 rather than combustion, it is possible to calculate allocation without reference to the emission factor. Instead a benchmark CO2 yield can be calculated as follows:

CO2 yield = Coke yield

* Carbon content

* Conversion * Molecular weight conversion

5% * 91% * 100% * 44/12

This gives a benchmark formula of:

Allocation = Unit capacity

* Utilisation factor

* 0.167 tCO2/t feedstock

Because this is calculated from carbon content it is possible to combine the Specific Energy Consumption (SEC) and emission factor into a single figure. If a standard petroleum coke emission factor of 0.34 kgCO2/kWh (gross basis) were used with the above overall benchmark of 0.167 tCO2/t feed, the standard SEC would be back-calculated as 491 kWh/t feed (gross basis).

Application of this benchmark to the Grangemouth phase I NE FCC unit gives an allocation of 161,045 tCO2/year when a utilisation factor of 95% is applied. This is 34% below the phase I allocation of 244,825 tCO2/year. The main reason for the under-allocation is that the actual coke yield at the Grangemouth cracker is 7.25%, which is signficantly above the benchmark coke yield of 5%.

It therefore seems likely that the CO2 emissions from many FCC units will exceed the allocation from this literature-based benchmark. This is because of the feedstock being used and product mix being produced, quite apart from any failure to achieve BAT. It could be argued that this is reasonable because the refinery is making a financial decision. Although they may need to buy CO2 credits, they are getting a payback in using cheaper feedstock and making high value products.

5.2.3 Hydrocracker unit benchmark The hydrocracker has become an important process in the modern refinery to allow for flexibility in product mix (Worrell et al 2005). It typically takes a heavy vacuum distillate stream feed from the high vacuum unit, possibly blended with other heavy products. This is



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mixed with a hydrogen-rich gas stream, heated and vaporised and fed into the hydrotreater reactor. The reactor contains a fixed bed cobalt/nickel/molybdenum catalyst and operates at 30 to 40 bar and 320 to 380 °C. The reactor effluent is cooled in the feed/effluent exchanger and reactor cooler and flashed into the high-pressure separator. The flashed vapours, consisting mainly of unreacted hydrogen, are compressed and recycled to the reactor. A fractionator separates the product stream into its components.

Hydrocracking is an exothermic process and heat integration techniques can be applied to minimise fuel use. However, furnaces are used to heat feedstock and fractionator and these are the source of CO2 emissions as there are no other energy or process CO2 emissions associated with the unit.

The literature contains very little data about the energy use of the hydrocracker unit. The following table summarises the data found in the literature.

Table 5.3 Hydrocracker Unit Literature Data

Energy consumption quoted

Conversion Converted energy consumption (kWh/t feed) – gross basis

Reference

400 to 1200 MJ per tonne feed

111- 333 EIPCCB 2001 (BREF)

US Average = 68.5 TBtu for 507.2 million barrels/year

1 Btu = 0.000293 kWh 1 barrel = 0.159 m3 Feed density = 0.92 t/m3

271 Worrel et al 2005

California average = 21 TBtu for 0.48 million barrels/day

As above

(note per day not year)


Indian refinery = 262,320 Btu/barrel

As above 868 Sathaye et al 2005

The use of fired heaters on the unit means that standard combustion BAT considerations apply for CO2 emissions including design of equipment, fuel used and operating conditions. Also, the exothermic nature of the hydrocracker process provides the opportunity to minimise fuel use on the unit and/or export energy to other units. The BREF (EIPCCB 2001) suggests the following techniques can be applied:

a) The heat generated in the reactors can be partially recovered in a feed/product heat exchanger. A furnace heats the feed to its required temperature. The reactor temperature is controlled via the injection of cold hydrogen between the catalyst beds.

b) A significant amount of heat is required in the fractionation section. Heat integration is applied to minimise heat consumption.

c) The energy efficiency can further be increased by applying a four-stage separator system. The feed to the fractionation section is in that case rendered significantly hotter, and consequently less heat is required in the fractionation section.

d) The use of heat recovery from high-temperature process streams in Waste Heat Boilers and power recovery in the high-pressure units (letting down liquid).



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Also, it is stated in literature that choice of catalyst can save up to 5% on energy use (Alsema et al 2001). There are other uses of energy from external sources, and clearly BAT applies to these but is not relevant to this study.

From the data provided above the low figure quoted in the BREF (EIPCCB 2001) is the lowest and hence the benchmark should be 111 kWh/t feed (gross basis). No incumbent or new entrant data is available at this time to test this benchmark.

The wide variation in data from the literature and lack of explanation of why the figures vary must create some doubt about how applicable the benchmark figure is. It seems unlikely that this doubt can be answered by the literature that is currently available.

The suggested benchmark shown above comes from the BREF. Unfortunately, there is no explanation about how this is achieved or why there is such a variation in energy use. Equally, it is reasonable to assume that a benchmark figure would be significantly lower than an average of actual energy uses for existing refineries (i.e. as quoted for US and Californian refineries) as the data would include some refineries that are not operating to BAT requirements. If the BREF is considered to be a credible source of data, it is reasonable to use the figure above as benchmark.

5.2.4 Hydrodesulphurisation unit benchmark Hydrodesulphurisation is a form of hydrotreatment used to remove sulphur from distillate (e.g. kerosene, diesel). The process uses a fixed bed catalytic system that operates at moderate temperatures and moderate to high hydrogen partial pressures (Larsen Toubro limited). The fresh diesel feed is combined with makeup hydrogen and recycled gas, and then heat exchanged through feed/effluent exchanger and fired heaters before entering the reactor system. High and low-pressure separation, hydrogen make-up and recycle, amine scrubbing, stripping and fractionation complete the process. The hydrogen rich recycle gas is scrubbed to remove H2S and recycled to reactors, while finished products are recovered in the fractionation system.

Hydrocracking is an exothermic process and heat integration techniques can be applied to minimise fuel use. However, furnaces are used to heat feedstock and this is a source of CO2 emissions as there are no other energy or process CO2 emissions associated with the unit.

The literature contains very little data about the energy use of the hydrotreater unit and even less specifically related hydrodesulphurisation.

The following table summarises the data found in the literature applicable to distillate hydrotreatment.

Table 5.4 Hydrodesulphurisation Unit Literature Data



Reference

300 to 500 MJ/t 83.3 - 139 EIPCCB 2001 (table 3.53) (BREF)

135.8 GWh/yr for gasoil throughout of 1.78 million t/yr

76.3 EIPCCB 2001 (table 3.54)



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Reference

206.9 GWh/yr for gasoil throughout of 3 million t/yr

69.0 EIPCCB 2001 (table 3.55)

US Average = 253.2 TBtu for 3679.8 million barrels/year

1 Btu = 0.000293 kWh 1 barrel = 0.159 m3 Feed density = 0.84 t/m3


California average = 36 TBtu for 1.6 million barrels/day

As above

(note per day not year)


Before new exchangers = 12MW for 65,000 barrels/day

As above 120 Packinox 2003

After new exchangers fitted = 5MW for 65,000 barrels/day

As above 50 Packinox 2003

Clearly there is some considerable variation in the data, including a number of different figures in the BREF. The use of fired heaters on the unit means that standard combustion BAT considerations apply for CO2 emissions including design of equipment, fuel used and operating conditions. Also, as for the hydrocracker, the choice of catalyst can reduce energy use (Alsema et al 2001).

From the data provided above for distillate hydrotreatment, the low figure quoted for a case study where highly efficient shell and plate heat exchangers were installed (Packinox 2003) is the lowest at 50 kWh/t feed (gross basis). This may be taken as the benchmark figure. No incumbent or new entrant data is available at this time to test this benchmark.

Once again, the wide variation in data from the literature and lack of explanation of why the figures vary must create some doubt about how applicable the benchmark figure is. It seems unlikely that this doubt can be answered by the literature that is currently available.

The suggested benchmark shown above comes from a case study demonstrating the benefit of highly efficient heat exchangers that maximise the opportunities for heat integration on the unit. There may be concern that this may include some marketing hype. Certainly the figure is significantly lower than the lowest quoted in the BREF. Unfortunately the BREF does not provide any information about how the energy consumption figures are achieved or why there is such variation.

If the case study quoted in the literature is considered to be a credible source of data, it is reasonable to use the figure above as benchmark. Alternatively, the lowest figure in the BREF may be more appropriate, but there is still a lack of information to back this up.



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5.3 Option 2 - Solomon Based Benchmark Fuel Consumption Approach

This option would use a direct approach to allocation for each refinery unit with the benchmark energy consumption figure being provided by the Solomon worldwide refinery database5. This section is not intended to fully describe the Solomon database equations which are proprietary. The aim is to outline how the Solomon approach could be applied to determine a refinery NE allocation.

For example, the Solomon database provides a standard energy consumption value for severe hydrocracking processes as follows (Solomon 2005):

SECi = 300 + [0.08* (Pi-1500)] - [Di + 1.5*(Gi + Bi)]

Standard Specific Energy

Consumption

= Function of operating pressure -

Function of product mix for D (diesel), G (gas oil) and B

(balance of products)

kBtu fuel (net basis)/barrel

of oil throughput

pressure in psi gauge % of each product type

The key observation from this equation is that energy use is a function of a number of parameters which relate to the hydrocracker operating conditions. This approach provides a more accurate means of benchmarking energy use (c.f. using a single literature based value) in that it accounts for operating pressure and product mix. The standard energy consumption is based on US refineries operating in the 1980’s. Modern refineries would be expected to operating more efficiently than this according to the energy efficiency index (EII), as defined below:

BSEC = EII/100 * SSECt

Benchmark Specific Energy Consumption = Benchmark EII * Standard Specific Energy

Consumption

MJ fuel/ tonne throughput % MJ fuel/ tonne throughput

5 Solomon Associates Ltd are the world leader in refinery energy use benchmarking. They own a proprietary database which includes the majority of the world’s refineries. Over a period of 20 years they have developed benchmark fuel consumption values for the full range of refinery units.



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Where:


EII 75 (c.f. 1980s baseline value of 100)

A Solomon EII value of 100 indicates a plant with an efficiency equal to that of the average US refinery operating in the 1980s, which corresponds to the ‘Standard Energy Consumption’ in the above equations. A Solomon EII plant-specific value below 100 indicates a more efficient plant, while a value above 100 indicates a less efficient plant. Currently, the average worldwide EII is 92 with a range from 62 to 165 for individual refineries. Based on data from Solomon Associates the top 10% of worldwide refineries currently achieve a whole-site EII of 75 or less using a 1980’s baseline (Solomon 2005). The Dutch allocation method for refineries is based on incumbents achieving such a top 10 percentile target. New entrants in the UK therefore might be expected to meet a benchmark EII of 75 (c.f. 1980s baseline value of 100) for the new process unit itself (i.e. rather than the whole-site) which should be broadly indicative of BAT for the new plant based on the comprehensive Solomon Associates data (i.e. in the top 10% of current worldwide refinery energy efficiency performance). Solomon (2006a) have confirmed that the EII can in principle be applied to individual refinery units (rather than the whole refinery) for a given capacity and load factor.

With this proposed approach the equations above would be applied to determine the allocation for a new severe hydrocracking process. Solomon’s database also has equations for standard energy use for the full range of other refinery process units. In the Solomon database some process units have a single standard energy use figure whilst others are more complex and based on key process parameters and heating duties involved. The key process parameters which are inputs to the Solomon database include:

• Feedstock composition;

• Feedstock temperature and pressure;

• Refinery unit operating temperature and pressure;

• Product mix;

• Process unit type and technology (e.g. catalytic or non-catalytic); and,

• Fuel mix.

These parameters are also part of the design specification for a given type of refinery unit with a specific hydrocarbon feedstock and intended product mix. The parameters are well defined and would normally be part of the contractual design specification for the new refinery unit. The parameters such as operating temperature and pressure are dictated by the reaction kinetics and catalyst properties and are essentially fixed for a given product mix and feedstock type. The above process parameters are part of the design specification (which is typically well documented by operators) and often form part of a legal agreement between the operator and the design/construction contractor and are therefore easily verified.

Solomon Associates Ltd have confirmed that the suggested allocation approach is viable and can be verified (Solomon 2006a). This may involve the verifier meeting with the operator and a



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Solomon representative to discuss a specific NE application and inspect the data inputs and outputs used in determining the allocation. The verifier would seek assurance that the proposed process design represents BAT by reference to the sector BREF. The verifier would also seek assurance that the database inputs were representative and accurate but did not allow differentiation for use of heavier crude oil feedstocks, for example, when lighter crude oil feedstocks are available on the market. The allocation method must ensure that both combustion and process CO2 emissions arising directly from the unit are fully accounted for. A simple approach would be for Solomon to determine the total fuel use for the refinery unit including feedstock use but subtract any energy use for imported steam and electricity generation as appropriate. The fuel emission factor would be a standard value as detailed later in this report section. Based on the above considerations, a protocol for running of the Solomon database is summarised in the table below.

Table 5.5 Protocol for Running of Solomon Database to Generate Standard SEC Value for Use in Refinery NE Allocation

Issue Allocation Basis (according to government policy)

Corresponding Protocol for Solomon Database Use

Practical Implementation

Raw Material Differentiation

Operators should not be rewarded for use of ‘dirtier’ feedstocks to make the same product (e.g. use of heavier and sourer crude oil should not result in extra allowances)

Database should be run using a standard crude oil specification based on EU-25 refinery average crude oil feedstock.

Solomon database assumptions for feedstock parameters can be changed to reflect protocol. Verifier to seek assurance this has been done in calculating standard SEC.

Technology Differentiation

Operators should not be rewarded for using technologies that are more CO2 intensive when making the same product (e.g. use of non-catalytic reactor to reduce capital cost versus when a catalytic reactor is more energy efficient)

Database should be run using a standard technology type for common processes which represents BAT given the feedstock and product mix.

Solomon database assumptions for unit operation type can be selected to avoid undue differentiation (e.g. choosing BAT for severe hydrocracking). Verifier to seek assurance this has been done in calculating standard SEC.

Double-counting

Double counting of CO2 emissions and energy must be avoided particularly with regard to electricity use and steam imports in an integrated refinery complex

Database should be run so that only the fuel use that results in direct CO2 emissions from the new process unit is reported. Electricity and steam imports are not to be included. If a new boiler or CHP plant is required at the refinery to power the new entrant process unit then the separate boiler / CHP methodologies should be applied. If an existing boiler or CHP plant at the refinery is required to increase its load factor then this does not qualify as a new entrant and should not receive additional allowances.

Solomon database setup can be modified to report only direct fuel use with contributions from electricity generation and steam import subtracted. Verifier to seek assurance this has been done in calculating standard SEC..

Use of BAT Operators are expected to use BAT for energy efficiency

Database should be run assuming that commercially viable heat integration and heat recovery is part of the new unit design.

Solomon database setup can be modified to assume that BAT for energy saving measures is part of the new refinery unit design. Verifier to seek assurance this has been done in calculating standard SEC.



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The proposed allocation method would require the applicant to obtain from Solomon a value for standard energy consumption and appropriate benchmark EII value for their new refinery unit and submit this in their NER application. The benefit of this approach is that it is uses a world-wide recognised approach to refinery energy use benchmarking. The approach is reliant on use of the Solomon database which is proprietary and the implementation of the process would require an agreement between the New Entrant applicant (i.e. operator) and Solomon Associates Ltd outside the scope of this study. However, a workable proposed process has been developed during this study based on discussion with relevant stakeholders and is summarised in the figure below.

It is noted that the operator would pay a fee to Solomon Associates Ltd in addition to the verifiers fees. The actual fee scale for providing this service would need to be agreed between the Solomon and the operator in due course in the same way that verifiers fees are currently agreed.



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Figure 5.1 Proposed Process for Use of Solomon Based Benchmark Fuel Consumption Approach

5.4 Further Work Completed for Option 2 (Solomon Associates Benchmark Approach)

This Solomon Associates benchmark approach (Option 2) has been further developed following the stakeholder consultation in co-operation with the government’s EU ETS steering group and Solomon Associates (2006b). The findings of the further work are presented below.

5.4.1 Process Unit Standardisation Solomon Associates Ltd have carried out an exercise to consolidate their refinery process unit/technology list according to guidance from the government’s EU ETS steering group as detailed below.

Solomon Associates’ database of refinery process energy standards contains 39 different refinery process unit types and a total of 136 distinct process units. 120 of the benchmarks are single standardised values expressing energy consumption per unit of feed or product, whilst the

Operator submits Process Design

Specification for NE refinery unit to Solomon with

appropriate fee

Solomon uses refinery energy

database to determine Standard SEC and relevant

benchmark EII value

Solomon issues SEC certificate to operator

Operator enters Benchmark SEC value into NER

allocation spreadsheet

Allocation Process

Verifier checks that data submitted by

operator corresponds with contractual process design

specification

Verifier liaises with Solomon and

operator to check that data used correctly

according to protocol

Verifier seeks assurance that SEC certificate matches Solomon database

output and performs sanity check

Verifier checks that operator has correctly

entered data into NER allocation spreadsheet

Verification Process

Sanity checks of Benchmark SEC value:

1. Value corresponds to BAT ranges for unit type as given in BREF

2. Value is at lower end of range of SECs for actual worldwide refinery operating units based on available data

3. Value is broadly consistent with calculated energy use in contractor process design documentation

Design Report

submitted for

verification



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other 16 also depend on a small number of process parameters such as operating pressure and product yields. This differentiation reflects the genuine complexity of refinery installations and the large number of different products that are made, each requiring a different process unit.

Government guidance requires standardisation of the benchmarks as far as possible and states that there should be no undue differentiation between technology types that are making the same product. Any differentiation (e.g. different benchmarks for hydrotreating sub-types) must be backed up with a justification as to why the sub-types are different and why it is necessary to have separate benchmarks. The technologies listed should be based on those which are the best practice technology for new entrants for manufacture of a specific product type. Further government guidance is that benchmarks are not to be developed for pollution abatement equipment.

Entec have worked with Solomon Associates to implement this policy guidance. As a result Solomon Associates’ list of processes used to assess the energy performance of refineries has been reduced for the purposes of the new entrant scheme from 16 to 13 different refinery process unit types and from 136 to 56 distinct process units with different benchmarks according to the different products being made. This list has been reduced by removing processes that do not represent BAT for manufacturing a distinct refinery product type or are no longer used when building new plant. Multiple technology types for making the same distinct refinery product have also been reduced to one technology type which represents BAT.

However, it is not possible to reduce the number of separate benchmarks to less than 56 as this would no longer resemble what a refinery actually does in terms of oil products manufacture. Each of these 56 process units could be a valid phase II new entrant that makes a distinct refinery product (whether finished or unfinished) or performs a distinct ancillary operation. A distinct product in this sense means a specific mixture of hydrocarbons produced by a process unit (or other product such as sulphur) which has properties that are significantly different to the product from another process unit in terms of potential for further use as feedstock or for sale as unfinished product. A Solomon-based benchmark has been developed for each of these 56 process units which each make distinct products as detailed below.



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Table 5.6 Simplified Refinery Process Unit List for Solomon Benchmarks (Solomon 2006b)

No. Process Type Process Unit Notes on Differentiation

1 A. Crude Units Atmospheric Crude Units

2 B. Vacuum Units Standard Vacuum Unit

3 Vacuum Unit with Extra Fractionation

Atmospheric crude units and vacuum units use distillation to separate crude oil into its components. The list has been reduced from 7 to 3 types based on BAT. They produce significantly different product mixes, and so there is clear justification for differentiation.

4 C. Visbreaking/Thermal Cracking

Visbreaking Unit

5 Thermal Cracking Unit

6 D. Coking Delayed Coking Unit

7 Flexicoking Unit

These units all process heavy materials but produce different mixtures of gas and fuel oil, and so there is clear justification for differentiation. The list has been reduced from 6 to 3 types based on BAT.

8 E. Catalytic Cracking Fluid Catalytic Cracking Unit

9 Mild Residuum Catalytic Cracking Unit

10 Residuum Catalytic Cracking Unit

The fluid catalytic cracking, mild residuum catalytic cracking and residuum catalytic cracking units all employ a similar process. However, the subsequent product mix will vary significantly and so there is clear justification for differentiation.

11 F. Hydrocracking Naphtha Hydrocracking Unit

12 Mild Distillate Hydrocracking

13 Severe Distillate Hydrocracking

14 H-Oil/LC-Fining Unit

These units all employ a similar process. However, the subsequent product mix will vary significantly and so there is clear justification for differentiation.

15 G. Catalytic Reforming Catalytic Reforming Units The list of reforming unit types has been reduced from 3 to 1 type based on BAT.

16 H. Hydrogen Generation & Purification

Methane/Naphtha Steam Reforming Hydrogen Plant

17 Partial Oxidation Hydrogen Plant

18 Hydrogen Purification Unit

These units all produce hydrogen rich streams but the hydrogen content varies significantly. They produce significantly different product mixes, and so there is clear justification for differentiation.

19 I. Olefin Processing Alkylation, TAME, MTBE

20 Iso-octene/Iso-octane Units

21 Polymerisation or Dimersol Unit

22 ETBE Unit

These units all involve olefin processing but produce distinct different product mixtures, and so there is clear justification for differentiation.

23 J. Hydrotreating Naphtha, Kerosene, Distillate, Vacuum Gas Oil Hydrotreating

24 Residual Desulphurisation Unit

The list of hydrotreating unit types has been reduced from 20 to 2 types based on BAT.

25 L. Other Processing POX Syngas Plant for Fuel

26 Methanol Unit

27 Fuel Gas Sales Treating & Compression

28 Polymer Modified Asphalt Blending

29 Flare Gas Recovery

30 ISOSIV, Amine Regeneration, Isomerisation

31 Cryogenic LPG Recovery

32 Ethylbenzene Unit

33 Toluene DP, Transalkylation, Aromatics Extraction, Xylene Isom Units

34 CO Shift & Hydrogen Purification

35 Hydrodealkylation

36 Solvent Deasphalting Unit

37 Cyclohexane Unit

38 POX Syngas Plant for Hydrogen Generation

These are all specialised processes for manufacturing distinct refinery products/petrochemical feedstocks and there seems to be no opportunity to combine them. They also include some utility and waste treatment units which are all covered by the EUETS Directive definition of refinery operations and therefore cannot be excluded.



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No. Process Type Process Unit Notes on Differentiation

39 Paraxylene Unit, Cumene Unit

40 Sulphuric Acid Regeneration

41 Sludge Incinerator

42 Butadiene Unit

43 Hydrogen Sulphide Springer Unit

44 Coke Calciner

45 Air Separation Unit

46 Desalinisation Plant

47 M. Special Fractionation Depropaniser, Debutaniser, Dehexaniser, Depentaniser

48 Naphtha/Reformate/Cat-Cracked Gasoline Splitter

49 Deethaniser, Deheptaniser, Deisohexaniser, Splitter with Heartcut

50 Solvent, Heavy Aromatics Column

51 Benzene, Deisopentaniser, Deisoheptaniser, Ethylbenzene Tower

52 Toluene Column

53 Xylene Rerun Column

54 Deisobutaniser Tower

55 Propylene Splitter

56 Orthoxylene Rerun Column

These are all fractionation processes for manufacturing distinct refinery products/petrochemical feedstocks and there seems to be no opportunity to combine them.

It is noted that since Annex I of the EUETS Directive and Annex III of the associated monitoring and reporting guidelines essentially cover all refining process units then there are no exempt operations/process units (e.g. petroleum sludge incineration is covered).

5.4.2 Standardisation of Solomon Benchmark Parameters Solomon Associates Ltd have carried out an exercise to standardise the parameters in their standard energy use values according to guidance form the government’s EUETS steering group as detailed below. A decision was made to use EU-25 refinery dataset as the basis for standardisation as described below. Solomon Associates have also updated their baseline year for the standard SEC values to 2004 (from a 1980’s baseline) based on their most recent Worldwide Fuels Refinery Performance Analysis. This means that the relevant benchmark, estimated to be equivalent to worldwide top 10% performance is different to that quoted in Section 5.3 as detailed below.

Government guidance requires standardisation of the benchmarks as far as possible and there should be no undue differentiation between feedstock quality or process operating conditions (e.g. coke yield) when a unit is making the same product.

The main refinery feedstock is crude oil and UK refineries process a range of crude oils. Currently, around 70% of the crude oil comes from the North Sea (UKPIA, 2006, Refining, www.ukpia.com/industry_information/refining.aspx), this is light and sweet, with a high percentage of short chain molecules. The UK also imports crude oil, which generally is of a heavier variety as required to produce a higher percentage of long chain substrates such as



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lubricants and bitumen. The table below summarises typical densities of crude oils used in UK and EU-25 refineries.

Table 5.7 Typical Crude Oil Densities for 2004 (DTI 2005, Solomon 2006b)

Crude oil Density (kg/m3)

UK refinery indigenous 834

UK refinery imported 847

Typical UK refinery throughput 843

Typical EU-25 refinery throughput 851

The typical density of the light North Sea crudes used in UK refineries is 834 kg/m3. The oil density determines the energy input required for distillation. However, North Sea oil production is in decline and it is therefore suggested that a typical EU-25 refinery oil density of 851 kg/m3 be used for benchmarking purposes. This value is used in determining the Solomon benchmark energy use for crude oil distillation.

A number of other process units (16 in total) require plant-specific inputs to calculate the Solomon standard energy values (e.g. coke yield). These values were all standardised based on the EU-25 refinery dataset to ensure that they are representative but do not allow undue differentation.

In developing the standard SEC values Solomon also excluded steam and electricity imports and energy use in stand-alone equipment. This ensures that there is no double-counting of emissions and allows a direct allocation approach. The standard SEC values include process CO2 emissions as well as combustion CO2 emissions that are directly associated with the new entrant process unit.

Solomon Associates also compared the standard SEC values in their database for UK refineries with those for EU-25 refineries. This indicated no significant differences in energy consumption and therefore the EU-25 refinery cohort has been used for benchmarking since this is a larger sample which has a higher level of confidence in the values. The Solomon SEC values are all quoted on a lower heating value (net) basis. The SEC values are mostly quoted per cubic metre of feedstock (or product) since this is the common unit of measurement in their database. The operator will need to convert the Solomon Associate benchmarks to a per tonne of feedstock (or product) basis as appropriate using actual verified feed or product density data as appropriate. In the case of process units that use a crude oil feedstock only, the density value will be standardised by Solomon Associates based on a typical EU-25 refinery oil density value as explained in Section 5.4.2. This will ensure that actual feed density data is used to accurately convert from cubic metres to tonnes. This does not affect the integrity of the SEC value but simply allows it to be quoted in the required units for use of the new entrant spreadsheet. The table below summarises the format of the standard SEC values to be used for allocation. The actual SEC values are proprietary and confidential to Solomon Associates Ltd and can be obtained on application by a new entrant.



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Table 5.8 Standard SEC Values for NE Allocation (Copyright Solomon Associates Ltd 2006)

No. Process Type Process Unit Standard SEC value –

net basis (NE to obtain

from Solomon)

Units and feed (F) or product (P)

basis

1 A. Crude Units Atmospheric Crude Units kWh/m3 (F)

2 B. Vacuum Units Standard Vacuum Unit kWh/m3 (F)

3 Vacuum Unit with Extra Fractionation kWh/m3 (F)

4 C. Visbreaking/Thermal Cracking

Visbreaking Unit kWh/m3 (F)

5 Thermal Cracking Unit kWh/m3 (F)

6 D. Coking Delayed Coking Unit kWh/m3 (F)

7 Flexicoking Unit kWh/m3 (F)

8 E. Catalytic Cracking Fluid Catalytic Cracking Unit kWh/m3 (F)

9 Mild Residuum Catalytic Cracking Unit kWh/m3 (F)

10 Residuum Catalytic Cracking Unit kWh/m3 (F)

11 F. Hydrocracking Naphtha Hydrocracking Unit kWh/m3 (F)

12 Mild Distillate Hydrocracking kWh/m3 (F)

13 Severe Distillate Hydrocracking kWh/m3 (F)

14 H-Oil/LC-Fining Unit kWh/m3 (F)

15 G. Catalytic Reforming Catalytic Reforming Units kWh/m3 (F)

16 H. Hydrogen Generation & Purification

Methane/Naphtha Steam Reforming Hydrogen Plant

kWh/knm3 (P)

17 Partial Oxidation Hydrogen Plant kWh/knm3 (P)

18 Hydrogen Purification Unit kWh/knm3 (F)

19 I. Olefin Processing Alkylation, TAME, MTBE kWh/m3 (P)

20 Iso-octene/Iso-octane Units kWh/m3 (P)

21 Polymerisation or Dimersol Unit kWh/m3 (P)

22 ETBE Unit kWh/m3 (P)

23 J. Hydrotreating Naphtha, Kerosene, Distillate, Vacuum Gas Oil Hydrotreating

kWh/m3 (F)

24 Residual Desulphurisation Unit kWh/m3 (F)

25 L. Other Processing POX Syngas Plant for Fuel kWh/knm3 (P)

26 Methanol Unit kWh/m3 (P)

27 Fuel Gas Sales Treating & Compression kWh/BHP (F)

28 Polymer Modified Asphalt Blending kWh/m3 (F)

29 Flare Gas Recovery kWh/knm3 (F)

30 ISOSIV, Amine Regeneration, Isomerisation kWh/m3 (F)

31 Cryogenic LPG Recovery kWh/knm3 (F)

32 Ethylbenzene Unit kWh/m3 (P)

33 Toluene DP, Transalkylation, Aromatics Extraction, Xylene Isom Units

kWh/m3 (F)

34 CO Shift & Hydrogen Purification kWh/knm3 (P)

35 Hydrodealkylation kWh/m3 (F)

36 Solvent Deasphalting Unit kWh/m3 (F)

37 Cyclohexane Unit kWh/m3 (P)



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No. Process Type Process Unit Standard SEC value –

net basis (NE to obtain

from Solomon)

Units and feed (F) or product (P)

basis

38 POX Syngas Plant for Hydrogen Generation kWh/knm3 (P)

39 Paraxylene Unit, Cumene Unit kWh/m3 (P)

40 Sulphuric Acid Regeneration kWh/m3 (P)

41 Sludge Incinerator kWh/m3 (F)

42 Butadiene Unit kWh/m3 (F)

43 Hydrogen Sulphide Springer Unit kWh/m3 (P)

44 Coke Calciner kWh/m3 (P)

45 Air Separation Unit kWh/knm3 (F)

46 Desalinisation Plant kWh/m3 (F)

47 M. Special Fractionation Depropaniser, Debutaniser, Dehexaniser, Depentaniser

kWh/m3 (F)

48 Naphtha/Reformate/Cat-Cracked Gasoline Splitter

kWh/m3 (F)

49 Deethaniser, Deheptaniser, Deisohexaniser, Splitter with Heartcut

kWh/m3 (F)

50 Solvent, Heavy Aromatics Column kWh/m3 (F)

51 Benzene, Deisopentaniser, Deisoheptaniser, Ethylbenzene Tower

kWh/m3 (F)

52 Toluene Column kWh/m3 (F)

53 Xylene Rerun Column kWh/m3 (F)

54 Deisobutaniser Tower kWh/m3 (F)

55 Propylene Splitter kWh/m3 (F)

56 Orthoxylene Rerun Column kWh/m3 (F)

Notes:

1. The SEC for units which have gaseous feedstocks/products are quoted on a normal gas volume basis (nm3). The Fuel Gas Sales Treating & Compression SEC is quoted on a brake horse power (BHP) basis. The Sulphur Recovery SEC is quoted per tonne of product.

2. The benchmark EII of 88 (2004 baseline) must be applied to the standard SEC to determine the benchmark SEC. Catalytic cracker and hydrogen generation require special consideration of the relevant EII by Solomon Associates Ltd on application by the new entrant.

In determining the standard SEC values, Solomon used their 2004 refinery fuels survey database to reset the factors and efficiency baseline. For the purposes of the new entrant scheme, an EII of 100 now closely represents worldwide average energy efficiency in 2004. Using this new baseline, the benchmark EII to apply to all process units is now 88 (n.b. this is the equivalent performance of an EII of 75 based on a 1980’s baseline). This EII value adjusts the standard SEC to ensure that the benchmark SEC represents BAT (i.e. worldwide top ten percent performance). To be clear, the standard SEC values are based on the EU-25 refinery cohort to ensure that standardised values for crude oil density, coke yield, etc. are representative of regional refinery operations, whereas the benchmark EII of 88 is a worldwide top ten percent value to ensure that the final allocation represents BAT. The exception to this is for catalytic cracking units and units for hydrogen production. In these cases the benchmark EII applies only to a portion of the standard SEC value since they generate process CO2 which cannot be



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reduced. The detailed assessment of the benchmark for catalytic cracking units is shown below for illustration purposes.

The table below summarises the data that Solomon Associates would require from the operator in order to determine which process unit type is proposed for the new entrant, and therefore which benchmark is applicable.

Table 5.9 Data required by Solomon Associates to determine process unit type (Solomon 2006b)

This data is readily available from process design documentation and can easily be verified. It is not required as an input to the new entrant allocation spreadsheet but is required to enable the proper classification of the unit. The verifier will seek assurance that this determination has been undertaken by Solomon Associates Ltd on behalf of the operator.

5.4.3 Solomon Based Benchmark for FCC Units As part of the benchmark energy consumption assessment process for new entrants, Solomon Associates Ltd has completed an initial review of the Innovene Grangemouth FCCU data provided in the Phase I NER Design Report. Though some of the feed properties and operating characteristics are not contained in the report, Solomon Associates was able to use the reported data (feed types, feed density, and coke yield), process description, and flow diagram provided to determine that the unit is a Mild Residue Catalytic Cracking (MRCC) process type. This assessment was further confirmed by comparing the design report information with other MRCC type units in the UK. Based on a MRCC process type assessment for the Grangemouth FCCU, Solomon assessed the standard energy consumption on both a UK and an EU refinery cohort basis. Average data for each of these regions were used for coke yield to determine Solomon Standard Energy

Process Type Input Data Requirements

All Units(1) Process Unit Description (per Design Document)General Feed Types per Design DocumentFresh Feed Density, kg/m3

Fresh Feed ASTM D-1160 10% Distillation Point, ºCFresh Feed ASTM D-1160 90% Distillation Point, ºC

Vacuum Distillation Produces product streams for lube feedstocks (Yes or No).

Catalytic Cracking Fresh Feed ConCarbon, Weight %Fresh Feed Aniline Point, ºCConversion to 221 Degrees Centigrade TBP, Volume % of Fresh FeedAir Blower Capacity, nm3/hCoke Yield, Weight% of Fresh Feed

Hydrocracking Final Reactor Pressure, bargTotal Hydrogen Consumption, nm³/m³ Fresh FeedNet Volume Gain, Volume % of Fresh Feed

Footnotes (1) Report product data also where product is the basis for Solomon's standard energy consumption.



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Consumption for the Grangemouth FCCU and to determine an appropriate adjustment to eliminate process unit imports of steam and electricity required to calculate ‘direct’ emissions only from the FCCU. A Benchmark EII of 88 was applied to the non-process component of the standard SEC to reflect the top ten percent of worldwide refineries in energy efficiency terms. This benchmark is based on updated standard energy factors for their Worldwide Fuels Refinery Comparative Performance Analysis for Operating Year 2004 (Fuels Study). The FCCU and other standard energy factors now reflect early 2000’s energy practices and technology. The energy standards have been re-calibrated so that the average energy efficiency (EII) recorded by Solomon Associates’ worldwide participants is close to 100. In line with government EUETS policy steering group guidance, Solomon limited the adjustments for energy imports and Benchmark EII solely to the non-coke component of the FCCU standard energy. This ensures that the non-coke component is benchmarked using an EII of 88 which represents BAT and that only direct emissions are accounted for. The coke component is process-related and is not subject to direct control by energy efficiency measures. Confidence in the EU data is higher than the UK data due to a larger refinery sample size and EU values are therefore suggested as the benchmarking basis for all process unit types. Based on available data, application of the EU benchmark to the Grangemouth phase I NE FCC unit gives an estimated allocation of 240,074 tCO2/year when a utilisation factor of 95% and coke emission factor of 0.358 kgCO2/kWh (net basis) is applied. This is 2% below the phase I allocation of 244,825 tCO2/year.

The above description demonstrates the derivation and application of the Solomon-based benchmark values for a FCC unit. The method is believed to be a workable means of determining an allocation. However, the above is an example of the benchmark process derived for the Grangemouth FCC. New Entrants will in practice apply to Solomon Associates Limited for a final determination and certificate.

5.4.4 Solomon Based Verification Approach The government EU ETS steering group highlighted the need to consider the verifiers role for the Solomon-based approach (see Figure 5.1 above) in more detail. UKAS (2006) have indicated that the role of the verifier is threefold:

i) ensure compliance with the rules;

ii) eliminate mistakes and ensure the minimisation of error and uncertainty; and,

iii) where required by the rules, provide ‘opinion’ on validity of benchmarks.

With phase I refinery and iron and steel sector new entrants, UKAS made three suggestions (UKAS 2006):

1. Relaxation of the strict 5% materiality criteria and its replacement with the new concept of ‘the highest practicable level of assurance’;

2. Placing the onus on the operator to demonstrate, in a ‘Design Report’, how the ‘highest practicable level of assurance’ could be achieved in their specific case; and,



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3. Requiring independent verification of the Design report to verify (and validate) the input numbers to the allocation spreadsheet.

This expanded the verifiers role, in assessing the Design Report, to provide an opinion on the validity and correctness of the approach and to verify the basis of the allocation spreadsheet input data. The approach worked successfully in the iron and steel sector under UKAS supervision, and also at the Grangemouth refinery where the verifier DNV, used two specialists from the DNV consultancy (UKAS 2006).

It is therefore proposed that for use of Solomon-based benchmarks in phase II, a similar approach be taken to that in phase I refinery new entrant verification. The verifier would assess the Design Report and seek assurance that the Solomon-based benchmark had been correctly derived according to the relevant principles. The verifier would also seek assurance that the allocation spreadsheet input data was representative of the new entrant refinery process unit. It essential that the verification team include the necessary technical expertise in the refinery sector. In assessing a Design Report, verification costs are increased (c.f. standard new entrant verification) but these costs are likely to be trivial in context of the value of the allowances applied for. It is likely that UKAS would want to amend their verification procedures for refineries to ensure that refinery new entrants were verified to a high standard (UKAS 2006). These procedures would, for example, only allow use of verifiers with appropriate technical expertise in the sector.

5.5 Option 3 - Solomon Based Integrated Refinery Energy Efficiency Approach

The addition of a new unit at a refinery may affect the overall refinery fuel balance and energy consumption. This approach recognises this complexity and takes an ‘integrated’ refinery view using the Solomon EII value for the whole refinery both before and after the new refinery unit is added.

For example, assuming that a refinery currently had an overall Solomon EII of 85, and that a new hydrocracking unit were to be added. It could be assumed that the upgraded refinery would at least maintain an overall Solomon EII of 85. That is, the expansion should improve or maintain overall current levels of refinery energy efficiency. The benefit of such an integrated approach would be the proper consideration of the effect of the new hydrocracker on the balance of refinery fuel use, steam production, hydrogen production and use, by-product fuels, etc. To implement this approach the operator would provide data to Solomon for use in their refinery database. Solomon would then calculate the net emissions increase from the refinery assuming an EII of 85 was to be maintained once the new refinery unit was installed. The NE allocation would then be based on the net increase in emissions. The drawback of such an approach is that it would be complex and potentially costly to verify the NE allocation due to the large number of parameters that affect the overall refinery EII.

Further analysis would be required to assess the feasibility of such an integrated refinery approach to NE allocation. However, the government steer is to implement a ‘direct’ approach to new entrant allocation in all sectors (e.g. based on the modified/new refinery unit only, rather than the modified refinery as a whole). Therefore the ‘integrated’ approach described under Option 3 above has not been developed further. UKPIA and EUROPIA have commented that this option may lead to a different allocation for the same new unit (i.e. same feedstock, product



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mix and operating temperature/pressure) installed at two different refineries and therefore they do not support this option.

5.6 Option 4 - Combustion Unit Thermal Efficiency Approach

This approach aims to simplify down the allocation method to benchmark each combustion unit that makes up or supplies energy to the new refinery unit. For example, a new hydrocracking unit would typically include a fired process heater for pre-heating of the feedstock. Based on the process design, the energy input to the process would be known. The allocation equation for the feed preheater would then be as follows:

Ai = Ci * Us/100 * SECt / Tt/100 * EFf

Allocation = Capacity * Utilisation *Process Actual

Energy Requirement

*

Benchmark Thermal

Efficiency of Process

Heater

* Emissions Factor

tCO2 tonnes

feedstock capacity

% MJ/ tonne throughput % tCO2 /MJ

fuel

The allocation method would provide benchmarks for thermal efficiency (for example a benchmark efficiency of 70% for a feed preheater fired by refinery fuel oil) depending on the type of process heater technology in use. The benefits of this approach is that it simplifies the refinery unit down into basic combustion units which can be benchmarked on efficiency. The main drawback is that it takes no account of the use of feedstock as a fuel (which is significant for units such as catalytic crackers). It also does not account for process CO2 emissions such as contributions to flaring from the process unit. Complexity may also be added due to the new unit being integrated with existing units, leading to CO2 allocation problems (e.g. a fired heater may serve both an existing unit and the new unit, thereby leading to problems apportioning fuel use to the new unit).

5.7 Plant Capacity and Load Factor With all alternative new entrant allocation methods, the plant capacity and load factor are required to determine total annual plant throughput. Data on load factors for UK refinery units was not available since operators consider this data to be confidential. However, the key points regarding load factors are discussed below.

Information from UKPIA (2006) indicates that refinery plants typically operate at high load factors (>80%) as opposed to plants in other sectors which may operate at low load factors (e.g. standby power plant often with <40% load factor). For example, after a commissioning period a new FCC unit will typically run at almost full capacity for 3 years with a high load factor in excess of 95% (UKPIA 2006). There will typically be a month-long shutdown period for



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maintenance in the fourth year, giving a four-year average load factor in the region of 93% (UKPIA 2006). The actual load factor will depend upon the operator’s future production plans, type of technology in use, maintenance schedules and projected sales volumes. Historical refinery load factors can be determined from UK Energy statistics (DTI 2005). Using the most recent data for the three year period 2002-2004 the average load factor of crude oil distillation units in UK refineries was 95.4%, with annual values ranging from 93.6 % to 97.6% (DTI 2005). Load factors for other refinery units would be expected to correspond to this value on average as they use the distilled crude oil fractions as feedstock and are designed to have an equivalent capacity. On this basis it is suggested that a sector standard load factor of 95% (i.e. UK historical refinery average value) be used in the allocation methodology.

The plant capacity value should be the nameplate capacity of the equipment (i.e. theoretical maximum annual production capacity) and should be backed up with verifiable data such as relevant parts of the PPC application for the unit. This evidence to justify plant capacity could be part of a Design Report provided by the operator as per the verification guidelines (DEFRA 2005b).

5.8 Fuel Emission Factors With all alternative new entrant allocation methods, the fuel emission factor is required to determine the CO2 emission allocation. Refinery fuels are mix of refinery fuel gas generated from process operations, FCC unit coke (this is coke deposited on the circulating catalyst which is continuously burned off in the FCC unit Regenerator, releasing a lot of heat, much of which is then recovered and used), refinery fuel oil (generally a heavy vacuum residue), and in some cases imported natural gas. These streams vary enormously in carbon content. Additionally, the carbon content of refinery fuel gas will vary significantly between refineries due to differing process configurations. For example a refinery with a large catalytic reformer may produce a high proportion of hydrogen (of zero carbon but good heat value) in the fuel gas. However, refineries need to use increasing quantities of hydrogen to remove sulphur from the product streams, and a refinery with a hydrocracker will need to use large quantities of hydrogen, resulting in a refinery gas with higher carbon content.

For example, an operator may use fuel gas which consists of mostly hydrogen in a new hydrotreating unit, in which case the CO2 emission factor would be close to zero. Alternatively if the fuel gas is 50% hydrogen and 50% methane the emission factor would be 0.10 kgCO2/kWh. For a unit using heavy fuel oil for preheating the feed and consuming a proportion of the feedstock itself the weighted emission factor could be up to around 0.30 kgCO2/kWh. Natural gas supplies are available to some UK new refinery units but not others, depending on location and infrastructure. Allocation based on natural gas as a fuel (i.e. 0.19 kgCO2/kWh) could lead to significant under-allocation (up to 30%) in the case of refinery units which use feedstock as a fuel (e.g. catalytic cracking units). It could also lead to significant over-allocation (up to 500%+) for refinery units which are fed with a hydrogen rich fuel gas (e.g. hydrotreating units). However, hydrogen is an attractive low-carbon fuel whose use presumably is to be encouraged.

Operators are unlikely to switch to natural gas due to economic considerations and allocation based on natural gas could lead to competitive distortion if other member states do not do the same for refineries. Use of a standard fuel emission factor based on UK refinery average fuel mix could also lead to similar under and over-allocation issues for new entrants. However, as explained in the evaluation section, this is a verifiable parameter, whereas site specific fuel



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mixes are considered to be difficult to verify. There are other advantages with using a standardised fuel mix as set out earlier.

5.9 Further Work Completed on Fuel Emission Factors Following the stakeholder consultation, further work on refinery fuel emission factors has been completed in co-operation with the government’s EU ETS steering group as detailed below.

Government policy is to standardise fuel emission factors as far as possible and to assume a standard low-carbon fuel type (normally natural gas). The exception to this standardisation is where it is not technically possible for the sector to use natural gas or is not the best environmental option in terms of CO2 emissions abatement.

During the refining process 6-7% of the crude oil throughput is used as a fuel (DTI 2005). This accounts for up to 90% of the fuel used, with the remainder being a mix of natural gas and other imported fuels (DEFRA 2005a). The most recent year for which complete set of UK refinery fuel use data and corresponding CO2 emission data is available is for 2003 (DEFRA 2005a) as summarised below.

Table 5.10 Refinery Fuel Use (gross basis) and CO2 Emissions Data for 2003 (DEFRA 2005a)

Fuel type Total fuel consumption (MWh)

Total CO2 emissions (tonnes)

Emissions factor (kgCO2/kWh)

Refinery fuel gas 40,265,036 8,053,007 0.20

Refinery fuel oil 11,694,885 2,923,721 0.25

Petroleum coke 11,401,162 3,876,395 0.34

All other fuels 8,849,776 3,207,733 0.36

Total 72,210,860 18,060,857 0.25

All fuels excluding coke 60,809,698 14,184,462 0.23

The data above indicates an overall UK refinery emissions factor of 0.25 kgCO2/kWh of fuel (gross basis), including the contribution of feedstock used as fuel. Calculating the emissions factor using total fuel consumption and total emissions ensures both the combustion and process emissions are accounted for.

However, the use of petroleum derived coke as a fuel in FCC units is unique amongst refinery process units. A FCC unit will have a significantly (36%) higher emission factor than the refinery average. It is not technically possible for a FCC unit to use any other fuel type due to the deposition of coke on the catalyst which must be burnt off in the regenerator. It is therefore recommended to use an emissions factor for FCC units based on petroleum coke, which is given by DEFRA as 0.34 kgCO2/kWh (gross basis) or 0.358 kgCO2/kWh (net basis).

However, for all other process units it is considered to be technically possible to switch to natural gas as a fuel and an emission factor of 0.19 kgCO2/kWh (gross basis) or 0.211 kgCO2/kWh (net basis) is recommended. This is in line with the government EUETS steering



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group guidance and has been applied across sectors. However, this is likely to lead to an under-allocation for new entrants of around 17% on average given the current UK refinery emission factor excluding coke of 0.23 kgCO2/kWh (gross basis). In reality there may be a significant incentive to use high-carbon refinery residues as fuels regardless of the allocation because there is no market outlet for these fuels and they would otherwise need to be disposed of in some other way, which could be prohibitively expensive.

5.10 Summary From the research completed and discussion with industry representatives, it is concluded that Option 2 (Solomon Based Benchmark Fuel Consumption Approach) is the most feasible alternative allocation method.

The following table assesses the key elements of the Phase I benchmarking method and summarises details of proposed revisions. The proposals are then justified against the agreed evaluation criteria in the following section.

Table 5.11 Summary assessment of key elements of Phase I benchmarking method and proposals for potential revision

Tests to be applied to Phase I benchmarking method

Answer / Details of proposed revision Source of data

Differentiation: should there be less or more differentiation within the sector (i.e. differentiating based on sub-product, raw materials, technology, fuel, efficiency etc)? If so, what should it be?

The existing NE spreadsheet and report by FES applies only to refinery FCC units and provides no benchmarks for any of the parameters. Differentiation at the refinery unit level is proposed by FES for other types of new entrant using a verifiers opinion for allocation to that unit.

Proposed revision includes standardised emission factor, fuel type and utilisation. A protocol is proposed to limit the differentiation in the Solomon database.

The BREF for mineral oil refineries was consulted by FES but no BREF data was used in the final allocation method.

Level at which benchmark is set

is the emission factor consistent with sector best practice6? If “No”, what should it be?

No benchmarks for emission factor are provided in existing NE spreadsheet. The user specifies the carbon content of the fuel and the proportion of feedstock used as fuel.

The proposed benchmark Energy Intensity Index (EII) is based on the best refineries worldwide (eg. top 10%) which should broadly be indicative of BAT for the sector. The fuel emission factor is standardised based on natural gas (except for catalytic crackers which are standardised on petroleum coke)

No benchmarks are given for emission factor in the existing NE spreadsheet.

6 Interpreted as ‘Best Available Techniques’ (BAT), as defined in the IPPC Directive. In practice, within the scope of this study it will only be possible to assess this in broad indicative terms at a sectoral level. It is clearly not within our scope to define BAT at the level of detail that would be required for a site specific PPC Permit.



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Tests to be applied to Phase I benchmarking method

Answer / Details of proposed revision Source of data

is the load factor realistic for new entrants in that sector? If “No”, what should it be?

No benchmarks for load factor are provided in existing NE spreadsheet. The user specifies the annual plant throughput.

The proposed revision uses an industry standard load factor of 95% based on recent UK energy statistics.

No benchmarks given for load factor in the existing NE spreadsheet.

Overall, the proposals for potential revisions to the formulae to be used in the benchmarking method are:

Ai = Ci * U/100 * BSECt * EFt

Allocation = Capacity * Utilisation *

Solomon Benchmark Specific

Energy Consumption

* Emissions Factor

tCO2 tonnes

feedstock capacity

% kWh fuel/ tonne throughput tCO2 /kWh fuel

(net basis)

Where:

BSECt = EII/100 * SSECt

Solomon Benchmark Specific Energy Consumption

= Solomon Benchmark EII * Solomon Standard Specific

Energy Consumption

kWh fuel (net basis)/ tonne throughput % kWh fuel (net basis)/ tonne

throughput

And:



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U 95%

SSECt Value determined by Solomon on application based on refinery process unit type (SSEC value is based on EU-25 refinery cohort). The Solomon SSEC values are mostly quoted per cubic metre of feedstock (or product) since this is the common unit of measurement in their database. The operator will need to convert the Solomon Associate benchmarks to a per tonne basis using actual verified feed or product density data as appropriate. This will ensure that actual feed or product density data is used to accurately convert from kWh/m3 to kWh/tonne. In the case of process units that use a crude oil feedstock only, the density value will be standardised by Solomon Associates based on a typical EU-25 refinery oil density value.

EII Value determined by Solomon on application based on wolrdwide top ten percent refinery performance (EII value of 88% applies to most process unit types)

EFt 0.358 kgCO2/kWh (net basis) for catalytic cracking units or 0.211 kgCO2/kWh (net basis) for all other process units

It is noted that:

• The standard specific energy consumption is the total specific energy consumption by the process unit based on the Solomon EU-25 refinery database. This includes any feedstock used as fuel but excludes energy imports which do not give rise to direct CO2 emissions such as steam and electricity. This value is obtained by the operator from Solomon Associates Ltd for the proposed new refinery process unit.

• The applicant must apply to Solomon Associates Ltd and pay an appropriate fee for the determination of the benchmark SEC, which is made up of the standard SEC and the benchmark EII. Solomon will issue a certificate detailing the determination. The new entrant application should be supported by a technical annex which includes a copy of the Solomon certificate. The verifier will seek assurance that the benchmark SEC quoted in the certificate is representative of the proposed new entrant.

• The benchmark energy intensity index (EII) for new entrants is set at 88 (2004 baseline) based on the top 10 percentile of worldwide refinery performance. This is equivalent to an EII of 75 using a 1980’s baseline.

• The operator specifies the capacity of the refinery unit based on the process design.

• Values for each parameter should be justified in a Design Report according to DEFRA guidance on new entrant verification. For example, the Design Report may include a copy of relevant parts of the design documentation to justify the plant capacity.



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6. Evaluation of Proposed Benchmarks

6.1 Introduction • The Solomon-based benchmark approach (Option 2) is the most feasible option. It

has been further developed following the stakeholder consultation in co-operation with the government’s EUETS steering group and Solomon Associates. This has allowed development of a workable allocation method which aligns with the government’s policy steer on new entrant allocation benchmarks. Overall, the Solomon-based benchmark approach scores most highly on the assessment criteria.

• The literature-based benchmark approach (Option 1) is the second most feasible option. It has been further developed following the stakeholder consulation in co-operation with the government’s EUETS steering group. However, the literature-based approach does not score as highly as the Solomon approach on the assessment criteria.

• The following evaluation is therefore based on implementation of the Solomon-based benchmark approach (Option 2).

6.2 Feasibility • The Solomon Energy Intensity Index (EII) is used for wide range of purposes in the

petroleum sector in Europe and worldwide. In particular, it is already being used by the Dutch authorities to benchmark refineries. Literature based benchmarks are not feasible since the publicly available data on refinery unit energy use is not comprehensive or detailed enough for this application.

• The approach is direct rather than integrated according to government policy on new entrant allocation for phase II. Refinery operators will receive a separate allocation for any new CHP plant or boiler using the relevant ‘CHP’ and ‘other combustion’ allocation methods (see separate reports on these methods).

• The plant capacity value should be the nameplate capacity of the new refinery unit and should be backed up with verifiable data.

• It is suggested that a standardised load factor of 95% be used in view of historical refinery sector data which indicates consistently high load factors.

• Key documents to allow verification may include the PPC application / permit, process design specification and other design documentation.

• Solomon Associates have confirmed that they would be able to provide a certified standard energy consumption figure for any type of new refinery unit. The Solomon database is proprietary which potentially reduces the transparency of this approach. However, a process that would allow verification has been proposed (see



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Figure 1.1) and this is considered to be feasible by Solomon Associates Ltd. This is also backed up by a proposed protocol for use of the Solomon database which limits technology differentiation and ensures that BAT is assumed in calculating the allocation.

• Overall, the proposed approach is regarded as verifiable and an operator should be able to justify their values for all parameters in the allocation equation.

• A standard fuel emission factor based on natural gas is proposed, which aligns with government policy and is simple and verifiable. A different fuel emission factor for catalytic crackers is proposed based on petroleum coke. This contrasts with site specific fuel mix data which would be considered difficult to verify.

• The proposed benchmark EII is based on performance of the best refineries worldwide (i.e. top 10 percentile) which should be broadly indicative of BAT for new entrants in the sector. This equates to a benchmark EII of 88 (2004 baseline) for new entrants, which is some 15% below the current UK refinery average performance. This indicates that a new entrant refinery unit would be expected to achieve CO2 emissions of around 15% lower than the equivalent existing refinery unit through the application of BAT. This is considered to be achievable given that new plant will employ the latest technology and energy efficiency measures compared to existing ageing refinery equipment which may be 20 or more years old.

6.3 Incentives for Clean Technology • In general there is always an incentive to apply the cleanest technology unless the

benchmark directly includes technology as a parameter. This is not the case with the proposed benchmark. Though it takes product mix into account, it still benchmarks each process and therefore includes an incentive to apply the most efficient technology. It proposed to standardise the feedstock specification based on EU-25 average values. Other process parameters have been standardised based on the EU-25 refinery dataset. In this way the full incentive for using the cleanest and most efficient technology is preserved while still differentiating by the production activity and conditions related to that.

• Refinery-specific information reduces the degree of standardisation of the benchmarking approach. However, a standardised simple benchmark approach would not recognise the significant variations in refinery product mix and product yield. These variations are genuine differences in refinery units due to the product mix and type of process unit employed. Accounting for them does not reward the use of less energy efficient technology provided that the benchmark is based on BAT for that type of unit. In contrast, not accounting for them could lead to significant under and over allocation and would not incentivise clean technology. For example, hydrocrackers allocated based on a single literature based benchmark of 400 MJ/t of feed could leave some operators (i.e. those carrying out severe hydrocracking) under-allocated by up to 200% - not because they are less efficient but because they are making different products.



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• The assessment of alternative benchmarks for the NE allocation spreadsheet has also considered using site specific refinery fuel-mix. Such an approach would recognise the need for refineries to fully utilise refinery fuels which could not be sold on the open market. It would therefore allow the operators to maximise the energy recovery/fuel production per barrel of crude oil processed without the risk of potentially significant under-allocation. With a standardised approach there could be a shortfall of allowances when a refinery would be using residual fuels with no market value. Whether this in reality would imply an incentive to use other fuels depends on the site specific conditions. As the residual fuels have no market value the overall financial benefit of using them instead of fuels that could be sold might still provide sufficient incentive for the most efficient use of refinery fuels. An alternative option of allowing for site specific fuel mix might also have introduced an undesirable incentive to re-distribute the fuels used within a refinery as to maximise the total allocation of free allowances for a new capacity. The costs of a process modification would on the other hand make such changes less likely.

• The choice of the most efficient fuel mix depends on site specific conditions. The many complicating factors preclude any firm conclusion on what provides the strongest incentives to use clean technology. Because of the weightings the Government has applied to simplicity and incentives for cleaner production, as well as achieving consistency with approaches adopted for other sectors, it is proposed to use a standardised fuel emissions factor.

• The benchmark method proposed recognises the need for increased transport fuel supplies in the UK to meet market demand. This is typically achieved by converting heavier crude oil components to lighter fuels which requires more energy input. However, such conversion processes help to ensure security of energy supply in the UK by maximising the efficient use of available crude oil supplies to meet domestic fuel demands.

6.4 Competitiveness and Impact on Investment • The impact of alternative benchmarks on the allocation to a new refinery unit could

be significant. The maximum impact with no free allowances could be up to 15-30% of running costs. Compared to the total refinery margin (difference between crude oil price) and average price of refinery products, the CO2 costs would be up to approximately 4-8%. This could affect the profitability of various refinery products.

• The proposed Solomon approach uses a ‘direct’ approach by specifying a benchmark EII for the new refinery unit and excluding any energy imports. This ensures that the same new refinery unit will receive the same allocation whichever UK refinery it is installed at. This is as opposed to an ‘integrated’ approach, which is not supported by government policy, and would use the EII for the whole of the modified refinery and accounts for energy imports and exports.

• The proposed benchmark method allows for the refinery-specific product mix in making an allocation. This method prevents significant under or over-allocation compared to using a single literature-based benchmark per tonne of throughput.



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• In reality a refinery is unlikely to change parameters for a new unit such as technology type, feedstock composition or product mix based on the allocation it would receive. However, if the new unit were to be significantly under or over allocated there would be competitive distortion c.f. other European refineries. The proposed allocation method is the most likely to avoid such competitive distortions whilst still making an allocation based on BAT.

• Refineries do not normally have much choice over their fuel mix and BAT is to fully utilise the available refinery fuels. The fuels used also vary significantly in carbon content between refineries. There is a risk of under or over allocation of allowances when using a standardised fuel mix. Potentially, this introduces impacts on competitiveness and distortion of the competition. As discussed above, it is not possible to derive a clear conclusion on which approach provides the strongest incentive to use clean technology. Overall, the standardised approach has been chosen due to Government’s priorities. The weightings the Government has applied to simplicity and incentives for cleaner production, as well as achieving consistency with approaches adopted for other sectors leads to the standardised fuel being proposed.

• The proposed approach takes into account the average EU-25 feedstock quality in assessing the energy intensity of a process unit. Sites using lower quality, heavier feedstocks have higher energy use to produce fuels but also tend to have higher overall profit margins. However, the benchmarking method would use a protocol as proposed in Table 5.5 to ensure that use of ‘dirtier’ feedstocks is not rewarded with a higher emissions allowance.

• The refinery sector is a key part of the UK energy industry and conversion of available heavier feedstocks improves the security of transport fuel supplies. By meeting need and still applying BAT the EII approach should reduce the risk that new refinery capacity will be located outside the UK, which should not adversely affect the security of energy supply.

• Given the fact the benchmark takes the above mentioned mainly ‘external’ conditions into account and given that the overall level of energy costs into total production costs is relatively low in the refinery sector there are considered to be no significant competition or competitiveness issues attached to the proposed benchmark.

• The proposed benchmark method using the Solomon EII approach is already being used by the Dutch authorities to benchmark refineries. It is also widely accepted across the industry both in Europe and worldwide as the leading benchmarking method.

• It should be noted that it is not within the scope of this report to undertake a detailed assessment of competitiveness and investment impacts.

6.5 Consistency with Incumbent Allocations • The fact that the benchmark takes the process unit type into account combined with

proposed EII benchmark of 88 (equivalent to top 10 percentile of worldwide



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refinery performance) compared to a 2004 baseline of 100 suggests that benchmark will allocate similar to the best performing refinery unit operations.

• Overall, it is expected to allocate approximately 15% less than existing incumbent refineries in the UK. However, it would be expected to allocate broadly similar allocations compared to ‘best practice’ new incumbent unit operations at refineries. Such an allocation should be achievable given that new plant will employ the latest technology and energy efficiency measures compared to existing ageing refinery equipment which may be 20 or more years old.

• Refinery plant tends to operate at high load factors and therefore use of a standard load factor of 95% is unlikely to lead to significant over-allocation to new entrants compared to incumbents.



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7. Stakeholder Comments

Responses to DTI’s consultation on the EU ETS Phase II New Entrants’ Benchmarks Review for this sector were received from:

• BP

• Conoco Phillips

• UKPIA

The specific details in the responses have been noted and taken into account where appropriate. The key specific elements of the responses which have not resulted in modifications are summarised below, for the reasons outlined.

Stakeholder response Entec comment

Inflated expectations as to the capability of Solomon to model refinery energy. The equations used to calculate theoretical energy for calculation of EII are extremely simple. For most process units the theoretical energy is simply a constant number of kBtu/bbl feed. The only exceptions are CDU/HVU/FCC/HCU and cat reforming for which a formula featuring a small number of key operating parameters is used. Arguing that these are based on ‘fundamental physics’ is a little optimistic.

Solomon method is government steering group preferred approach and is more robust than literature data. Solomon Associates Ltd have been consulted to develop a workable method as detailed in the report.

Concern over standardisation, particularly EII benchmark of 75 (1980’s baseline). This value is only valid for the overall energy consumption for refineries and not necessarily for each individual process unit. If there is a ‘state of the art’ figure it will be different for different process units. A different benchmark value must therefore be considered for each individual unit.

Solomon Associates Ltd have been consulted to develop a workable method as detailed in the report. It is considered that the use of a refinery wide EII will provide a reasonable approximation at the level of an individual process unit.

Utility generation needs to be considered along side process. It must ascertain whether the currently proposed methodology for utilities adequately covers the needs of refineries.

A separate allocation is made using the CHP and other combustion methods – no action

The principle behind the proposal appears to lead to technology forcing, attempting to establish a hierarchy of technologies that are not comparable. The different technologies that can be used to e.g convert residues are not directly comparable from the point of view of energy use. The only possible point of comparison is different embodiments of the same technology. The proposed application of an energy benchmark would ensure that the technology is applied at a ‘state of the art’ level.

Solomon Associates Ltd have been consulted to develop a workable method as detailed in the report.

Direct versus integrated approach to emissions - operators prefer an integrated approach.

Government steering group policy is to use a direct approach – no action



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8. References

Alsema, E 2001. Sector study for the refineries. Report prepared for Utrecht centre for energy research.

Colorado School of Mines. Catalytic cracking. Colorado School of Mines web site.

CONCAWE 1999. Best available techniques to reduce emissions from refineries

Couch, KA; Seibert, KD; Opdorp; PV 2003. ‘Controlling FCC Yields and Emissions UOP Technology for a Changing Environment.’ Presented at National Petrochemical & Refiners Association meeting 2003.

DEFRA 2005a. Revised UK National Allocation Plan (NAP) for the EU ETS. Department of the Environment, Food and Rural Affairs. 14 February 2005.

DEFRA 2005b. Guidance on New Entrant Verification. Department of the Environment, Food and Rural Affairs. 9 June 2005.

DTI 2005. Digest of UK Energy Statistics 2005. Department of Trade and Industry. 2005.

EA 1995a. IPC Guidance Note S2 1.10: Petroleum Processes: Oil Refining and Associated Processes. Environment Agency. November 1995.

EA 1995b. IPC Guidance Note S2 1.01: Combustion Processes: Large Boilers and Furnaces 50MW(th) and Over. Environment Agency. November 1995.

EA 2006. Pollution Inventory England & Wales. Environment Agency. www.environment-agency.gov.uk (accessed January 2006).

EIPPCB 2001a. Reference Document on Best Available Techniques in the Best Available Techniques for Mineral Oil and Gas Refineries. European IPPC Bureau. December 2001.

EIPPCB 2001b. Reference Document on Best Available Techniques for Large Combustion Plants (Draft). European IPPC Bureau. March 2001.

Engelhard. What a low delta coke catalyst means to the refiner.’ Published on www.refiningonline.com website.

EUROPIA 2006. Communication with Bruno Conti, European Petroleum Industries Association. February 2006.

Grace Davison. Building Block: RAM Matrix. Publicity from Grace Davison website

Larsen Toubro Limited. Diesel Hydrodesuphurisation Proces. Website

McKinney, JD; Henning, WD; Andrews, P; Dodds, B. Change to maintain FCCU conversion. Presented at National Petrochemical & Refiners Association meeting 2002.

Nilsson, K; Zetterberg, L; Ahman, M 2005. Allowance allocation and CO2 intensity of the EU15 and Norwegian refineries. IVL Swedish environmental research institute.



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Packinox 2003. Minimisation of atmospheric emissions in hydrocarbon processing industries with high efficiency plate and shell heat exchangers. Presented at Texas Technology Showcase 2003

Ritter, K; Nordrum, S; Shores, T; Lev-On 2005. Ensuring consistent greenhouse gas emissions estimates. AICHemE

Sathaye, J; Price, L; de la Rue du Can, S; Fridley, D 2005. Assessment of Energy Use and Energy Savings Potential in Selected Industrial Sectors in India. Berkeley National Laboratory.

Solomon 2005. Description of EII Methodology and EII Statistics. Provided by Solomon Associates Ltd for use within ETS studies. March 2005.

Solomon 20056a. Communication with Lawrence Anness, Solomon Associates Ltd. March 2006.

Solomon 2006b. Further communication with Lawrence Anness on detailed approach to benchmarks, Solomon Associates Ltd. May 2006.

UKAS 2006. Communication from David Shillito, UKAS. April 2006.

UKPIA 2006. Communication with Ian McPherson, UK Petroleum Industries Association. February 2006.

US EPA 2003. Methodology for Estimating the Carbon Content of Fossil Fuels.

Wang, M., Lee, H. and Molburg, J. 2004. Allocation of Energy Use in Petroleum Refineries to Petroleum Products. International Journal of Life Cycle Assessment. 9 (1) 34-44. 2004.

Worrell, E; Galitsky, C 2004. Profile of the Petroleum Refining Industry in California. Berkeley National Laboratory March 2004

Worrell, E; Galitsky, C 2005. Energy Efficiency Improvement and Cost Saving Opportunities For Petroleum Refineries. Berkeley National Laboratory.

The following table provides an overview of some of the references reviewed during the study, but found to be lacking relevant data.

Reference Comments about the reference

EA. Petroleum activities guidance note. Environment Agency. 2004

No data provided for energy consumption or CO2 emissions from refinery units provided.

US EPA. Sector Notebook Project – Petroleum Refining. 1995

No relevant energy consumption or CO2 emission data provided.

Letzch, W. Benchmarking FCCU performance. Petroleum Technology Quarterly 2006

No relevant data. Relates to general efficiency of the FCC unit as a whole.

IEA. The European Refinery Industry under the EU emissions trading scheme.

Deals with total refinery emissions rather than at unit level.

Golden, S; Fulton, S. Low-cost methods to improve FCCU energy efficiency. Petroleum Technology Quarterly 2000

No relevant data.



August 2006

© Entec

Reference Comments about the reference

Wang, M; Lee, H; Molburg, J. Allocation of energy use in petroleum refineries to petroleum products. International journal of Lifecycle assessment. 2004

Data only at unit and refinery level.

UK PIA. Statistical review. 2005 Data only at unit and refinery level.

US Government. The status of the US refining industry. Hearing before the subcommittee on energy use and air quality. 2004

No relevant data

API. Towards a consistent method for estimating greenhouse gas emissions from oil and natural gas industry operations. American Petroleum Industry 2002

Data only at unit and refinery level.

US DOE. DOE and Flying J Refinery Cooperate to Determine Energy Savings. Department of energy. 2003

No relevant data

EIA. The Impact of Environmental Compliance Costs on U.S. Refining Profitability. Energy Information Administration. 1997

No relevant data

Californian Climate Action Registry. Electric Power Generators, Utilities, and Natural Gas Entities. 2004

No relevant data



August 2006

© Entec

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