Haifa refinery Analysis of the Best Available Techniques (BAT...

Study executed by order of Haifa District Association of Municipalities for the Environment

2006/IMS/R/

DNV Certification B.V., BELGIË

Reg.No.013QS

VITO

May 2006

Contract 051246

Haifa refinery Analysis of the Best Available Techniques

(BAT) for air emissions

Final report

W. Nijs, P. Stouthuysen, P. Lodewijks, K. Vrancken

I

DISTRIBUTION LIST

Haifa District Association of Municipalities for the Environment (HDMAE), 24 Hahermesh St. POB 25028, Haifa 31250 Israel www.envihaifa.org.il VITO Flemish Institute for Technological Research Integrated Environmental Studies Boeretang 200 2400 Mol Belgium www.vito.be Project Manager VITO – BAT Centre K.Vrancken [email protected] 0032 14 335892

http://www.envihaifa.org.ilhttp://www.vito.bemailto:[email protected]

III

SUMMARY

In this report, VITO proposes air emission standards for the refinery in Haifa (HR), Israel. The study focuses on the pollutants NOx, SOx, PM, and VOC. A revision of the air emission standards for the refinery was instigated by the Haifa District Municipal Association for the Environment (HDMAE). The proposed standards are based on the concept of Best Available Techniques (BAT), as defined in the European IPPC Directive 96/61/EC. The revision process of the standards was carried out using the following sources and tools: the Reference document on Best Available Techniques for Mineral Oil and Gas Refineries [BREF 03], a EU survey of air emissions and emission standards and VITO’s multipollutant costing model. The latter was used to make a cost assessment. The added value of this multipollutant model is that it selects a set of most cost effective measures for several pollutants at a time. Chapter 1 and 2 of the report describe context and methodology. Chapter 3 of the report gives an overview of the situation of HR air emissions. When comparing air emissions, it is important to normalize all emission concentrations in order to compare the refineries’ installations with each other and with installations from other refineries or with other standards. Reported emission data are normalized to flow rates at dry circumstances and at 3% O2 and 0°C. A thorough comparison of emission data revealed that performance on SO2 reduction efforts at HR in the year 2005 is in line with EU efforts in the year 2003. The NOx levels, however, are considerably exceeding the average emission level of 40 EU refineries, which indicates a considerably improvement potential. The outlook of emissions in Belgium (Flanders) and the Netherlands in the year 2010 for SO2 and NOx indicate a large emission reduction potential between emissions of HR in 2005 and the levels that will be reached in 2010 in Flanders and the Netherlands (figure 1).

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Figure 1: Comparison of emissions of SO2 and NOx of HR in 2005 with situation in Flanders and the Netherlands in 2005 and outlook for 2010

Concentration bubble (mg/Nm3)


Load bubble (g/tonne crude oil)


IV

In chapter 4 the current situation at HR is described and checked for its BAT compliance as it is described in BREF for Mineral Oil and Gas Refineries ([BREF 03]). All BAT reduction measures that are not yet implemented are included in the model to evaluate their applicability and cost. The calculations with the multipollutant costing model are described in chapter 5. The techniques mentioned in chapter 4 are evaluated and compared using data primordially from [BREF 03] and information of Belgian refineries. The model calculated cost curves for each individual pollutant and the total yearly cost for different bubble emissions for SO2 and NOx. Chapter 6 summarizes the results of the model and gives a proposal for emission standards. For SO2 and NOx an optimal reduction target of respectively 70 and 65% is presented in a situation without possibility to use natural gas. The reduction cost associated with these emission standards is about 9 - 12 M$2006 per year. The recommendations in chapter 7 group all results from the BAT check in chapter 4 and from the model results in chapter 6. In annex 1 and 2 a calculation is made to compare the cost of the proposed reduction with data from the accountancy of Oil Refineries Ltd. The annual cost is about 2% of annual added value of the refinery and the list of reduction techniques in the model are reported. In annex 3, an overview is given of the current air emission legislation for refineries outside Israel.

V

CONTENT

Distribution list .................................................................................................I

Summary........................................................................................................III

Content ............................................................................................................V

List of figures ................................................................................................ VII

List of abbreviations....................................................................................... IX

Chapter 1 Context ....................................................................................... 1

Chapter 2 Methodology ............................................................................... 3

2.1 Current situation of the refinery in Haifa .................................................... 3 2.2 Legislation survey and EU emission level survey ......................................... 4 2.3 BREF compliance..................................................................................... 4 2.4 BATAEL ................................................................................................. 4 2.5 Multipollutant costing model..................................................................... 4

Chapter 3 Benchmark of EU air emission levels........................................... 7

3.1 Overview of current emission levels........................................................... 7 3.2 SO2 ....................................................................................................... 8 3.3 NOx ..................................................................................................... 10 3.4 SO2 and NOx in Flanders and the Netherlands ........................................... 12 3.5 VOC .................................................................................................... 13 3.6 Energy use........................................................................................... 13

Chapter 4 BAT compliance and possible reduction measures .................... 15

4.1 Refinery wide ....................................................................................... 15 4.2 Process/activity..................................................................................... 15 4.3 Flares .................................................................................................. 18 4.4 Odour.................................................................................................. 22 4.5 Spent caustic........................................................................................ 27

Chapter 5 Cost curves and bubbles with multipollutant costing model...... 33

5.1 Multipollutant costing model................................................................... 33 5.2 General model assumptions.................................................................... 34 5.3 SO2 ..................................................................................................... 35

VI

5.4 NOx ..................................................................................................... 41 5.5 PM....................................................................................................... 44 5.6 VOC..................................................................................................... 46 5.7 Bubbles................................................................................................ 47

Chapter 6 Proposal of emission standards.................................................52

6.1 SO2 and NOx: 70 and 65% reduction by 2010........................................... 52 6.2 VOC reduction by LDAR.......................................................................... 57 6.3 PM reduction ........................................................................................ 57

Chapter 7 Recommendations.....................................................................58

References .....................................................................................................60

Annex 1: Cost comparison of proposed air emission standards.......................62

Annex 2: Reduction techniques in the model..................................................64

Annex 3: Benchmark of legal framework: air emission standards...................71

REFERENCES of annexes...............................................................................116

VII

LIST OF FIGURES

Figure 1: Comparison of emissions of SO2 and NOx of HR in 2005 with situation in Flanders and the Netherlands in 2005 and outlook for 2010..............................III

Figure 2: Concentration bubble in mg/Nm3 for NOx and SOx [BREF 03]...................... 8 Figure 3: Comparison of HR SO2 load bubble of 2005 to emissions of EU refineries in

2003 ........................................................................................................... 9 Figure 4: Comparison of HR NOx load bubble of 2005 to emissions EU refineries 2003

................................................................................................................ 11 Figure 5: Comparison of the emissions of SO2 and NOx of HR in 2005 with situation in

Flanders and the Netherlands in 2005 and the expected situation for 2010. ....... 12 Figure 6: All quantifiable BAT measures in the model ............................................ 34 Figure 7: SO2 cost curve with bonus effect on NOx and PM emissions with the option to

switch to natural gas ................................................................................... 38 Figure 8: SO2 cost curve without the option to switch to natural gas. There is no bonus

effect on NOx or PM..................................................................................... 40 Figure 9: NOx cost curve with bonus effect on SO2 and PM emissions. ..................... 43 Figure 10: PM cost curve: there is no interaction or bonus effect of PM reduction

measures with other pollutants..................................................................... 45 Figure 11: Contour plot of total annual reduction cost, gas available

(distance weighted least squares) ................................................................. 49 Figure 12: Contour plot of total annual reduction cost, gas not available

(distance weighted least squares) ................................................................. 50 Figure 13: Contour plot of total annual reduction cost, gas not available

with optimal target points and BAT based range (S: start, B: Belgium, H: Haifa) 53

IX

LIST OF ABBREVIATIONS

BAT Best Available Techniques BATAEL Best Available Techniques Associated Emission Level BREF BAT Reference document FCC Fluidized Bed Catalytic Cracker FGD Flue Gas Desulphurisation HDMAE Haifa District Municipal Association for the Environment HR Haifa Refinery PM Particulate Matter VOC Volatile Organic Compounds

Chapter 1 Context

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The Haifa District Municipal Association for the Environment (HDMAE) wants to elaborate emission standards for the refinery in the Haifa District (Israel). These standards should be based on the concept of Best Available Techniques (BAT) as defined in the European IPPC Directive 96/61/EC. The European Directive 96/61/EC, better known as the IPPC Directive, lays down a framework requiring Member States to issue operating permits for certain installations performing industrial activities as described in its Annex 1. These permits must contain conditions that are based on ‘Best Available Techniques’ (BAT). In line with the IPPC Directive, these permit conditions will be elaborated on the basis of the BAT Reference Documents from the IPPC Bureau. In the case of the oil refinery, this BREF is the “Reference document on Best Available Techniques for Mineral Oil and Gas Refineries”, carried out by the European IPPC Bureau in 2003 [BREF 03]. The BREF is a large document and allows room for interpretation because of the complexity of the sector and the specific situation of the refineries. The analysis also includes a survey of European legislation and emission standards in the oil refinery sector and a cost assessment. VITO has developed or improved several evaluation methods to assist authorities in the establishment of emission control standards and limit values. These methods are based on cost efficiency and have been used to assist the Belgian and Flemish authorities to implement its CO2, NOx, SO2, and VOC reduction policies. Especially, the approach to tackle the problem of the cost-efficient selection of multi pollutant measures (reduction measures having an effect on two or more pollutants) has proven to be very useful. This model is designed to calculate (by means of linear programming techniques) least cost scenarios and to derive cost curves. This model is applied for the refinery in Haifa. The most important BAT reduction techniques are integrated in a comprehensive cost curve, with the focus on the NOx, SO2, PM, and VOC emissions. The results of the surveys and the analyses are integrated into a suggestion, which is in line with the BAT concept and which is realistic because it takes into account specific local circumstances.

Chapter 1 Context

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Chapter 2 Methodology

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This chapters explains the information and instruments used to attain an emission standard proposal. Different steps were needed to elaborate a specific proposal for the emission standards of the Haifa refinery.

2.1 Current situation of the refinery in Haifa

It is crucial to have a clear view on the current situation of the refinery sector in the Haifa District. This includes characteristics of the installation, applied processes and present emissions. This information was collected in cooperation with HDMAE, using two questionnaires. Based on this information VTIO made some calculations which proved to be consistent with the information sent by HDMAE.

2.1.1 Questionnaire 1

The first questionnaire was a BREF checklist. This checklist presented all BAT techniques that are described in the BAT chapter of the relevant BREFs, together with the associated emission levels. The goal was to check whether plants already apply the mentioned techniques and/or whether their emissions comply with the BAT associated levels. The filled-in list was a starting point to decide what further actions are needed. The list gives a short description of each technique, its applicability and a reference to the corresponding paragraph in the BREFs. Three fields are added in which the applicability of the technique and its results are evaluated for the installation under consideration:

- applicability: gives checkboxes to indicate whether the technique applies to the installation;

- application: allows to indicate whether the technique is already in place, or planned to be applied at a specified date;

- environmental benefit: allows to indicate emission loads before and after application of the technique.

2.1.2 Questionnaire 2

On basis of the filled-in checklist VITO made an additional questionnaire to gather more information. This second questionnaire was highly detailed and was meant to collect information on HR emission levels, HR fuel consumption and HR technologies used.


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2.1.3 VITO calculations on present emissions With the information of the two questionnaires, a process flow scheme, a scheme of stack locations, several phone calls and a meeting, VITO calculated as good as possible the emissions of HR in the year 2005. This was an intensive process. The results of this exercise are discussed in chapter 3.

2.2 Legislation survey and EU emission level survey

A benchmark of air emission standards and air emission levels is given by 2 surveys. 1. In annex 3 HDMAE has made an overview of air emission standards in some countries.

Most countries (like Belgium) use concentration bubble emission standards for all the installations situated at a specific refinery. Others use specific emission standards.

2. In chapter 3 VITO compared the emissions of HR with a selection of emission levels for some European countries.

2.3 BREF compliance

In chapter 4, the current situation at HR is described and checked for its BAT compliance as described in the BREF-document on “Mineral Oil and Gas Refineries”. For each process/activity a table gives an overview of its current BAT-compliance. All the missing BAT techniques are integrated in the model calculations in chapter 5.

2.4 BATAEL

BATAEL are BAT Associated Emission Levels. All the BAT techniques that are discussed in chapter 4 are candidate techniques to reduce i.e. sulphur dioxide. The levels that correspond to using BAT techniques are so called BATAEL. It should be highlighted that in the IPPC philosophy the stress is on the “L”, thus compliance is reached when the BATAEL are achieved. The company can choose a mix of technologies out of a long list of BAT technologies. The BATAEL method is the link between chapter 4 and chapter 5. In chapter 5, the multipollutant costing model is used to identify this mix of technologies. Some techniques make the application of other techniques superfluous. The model takes those effects into account.

2.5 Multipollutant costing model

A detailed description of the multipollutant costing model of VITO is given in Chapter 5. The Environmental Costing Model is used in this project for generating: - Cost curves for the most important pollutants in the Haifa refinery. Cost curves

describe the most cost effective combination of abatement measures for various emission reductions for one pollutant. The bonus effect on other pollutants can also be examined. A cost curve presents the cost (Y-axis in k$/ton) to reduce an extra ton of emission (X-axis in ton pollutant). Marginal cost curves can be used to compare different companies or sectors.


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- Bubble emissions have to be implemented at the company level. Therefore the bubble concept is less strict as not all the individual installations have to meet given emission or concentration limitation values. All model simulations were performed by enforcing a certain load level for SO2 and NOx.


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Chapter 3 Benchmark of EU air emission levels

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This chapter gives an overview of the current emission situation of the Haifa Refinery. All data for 2005 have been normalized to flow rates at dry circumstances and at 3% O2 and O°C. The data are grouped to obtain a consistent emission data set. For every emission component, also an overview of EU-emission levels is given and compared with the levels of HR. The EU data is gathered from references [BREF 03], [PDC 04], [TEP 00] and from Belgian data.

3.1 Overview of current emission levels1

The concentrations are normalized to flue gas conditions at dry circumstances and at 3% O2 and 0°C. For example: the atmospheric distillation of 1 furnace has a reported, not normalized flow of 75 000 m³/h. This is at an excess oxygen level of about 11%. When we normalize the oxygen level to 3% at dry conditions and at 0° C, the flow amounts to 35 000 Nm³/h. The reported not normalized NOx concentration is 200 mg/m³, which changes under these circumstances to 465 mg/Nm³. It is important to normalize all concentrations to be able to compare the refineries’ installations with each other and with installations from other refineries. It is also important to interpret the possible reduction measures that can be implemented. Furthermore environmental legislation is often based on normalized concentrations. In HR there is no natural gas at this moment. The refinery has Claus-units with SCOT and a fluidized catalytic cracker with a pre-treatment in a hydroconversion Scanfining process. It has a visbreaking unit and a power plant that meanly burns heavy fuel oil. An overview of the normalized concentration bubble is given in the table below. Normalized concentrations [mg/Nm³]

SO2 NOx PM (total) 981 500 112

The next table shows the emissions in tons per year. The emissions are calculated by using the reported data by the refinery. Therefore, the concentration for each pollutant in mg/m³ is multiplied by the flow in m³/year. Emission load per year [tons per year]

SO2 NOx PM (total) 6 881 3508 784

1 Exclusive lube oil plant, inclusive flares. If flares are not included, only SO2 data changes significantly to 974 mg/Nm3 and 6753 tons per year.


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3.2 SO2

3.2.1 Refinery wide (bubble concept)

Most of the countries (like Belgium) use concentration bubble emission standards for the whole of the installations within a refinery (LCPs2 are included, though different emission standards are imposed by a European directive). Others use specific emission standards. The BREF does not propose one range of emission levels because there was no agreement between different member states. The graph below shows the BREF associated concentration bubbles.

Figure 2: Concentration bubble in mg/Nm3 for NOx and SOx [BREF 03]

In the next two graphs, the emissions of HR are compared with the emissions in almost all EU refineries. The load bubble is compared taking into account the complexity of the refinery. This complexity is measured by the Nelson complexity index. For HR, the index is 7.2, which is average. In this complexity level, the isomerisation plant is included (restart in the near future). When comparing refineries’ bubbles, some important remarks are necessary:

o Are flares included ? (VITO did for HR) o Which plants are included ? (VITO included the power plant for HR, some

other EU refineries have petrochemical plants in the bubble) o There is a big difference between daily, monthly and yearly averages (VITO

only elaborated yearly averages) o Bubbles are weak instruments to compare refineries’ specific situation, though

there is no better, easier way to compare such complex companies o From which year is the data ? (VITO compared HR data of 2005 with data EU-

refineries of 2003).

2 Large Combustion Plants (combustions plants with a capacity of more than 50 MWth)


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Figure 3: Comparison of HR SO2 load bubble of 2005 to emissions of EU refineries in 2003

Concerning the SO2 emissions per tonne crude oil processed, the Haifa refinery is situated slightly higher than the 50 percentile. This means that more than 50 percent of the European refineries had a lower SO2 emission factor per tonne crude oil in 2003 compared to the emission data of HR in 2005.

3.2.2 Flares

Flaring is intended to be a safety system. It is therefore only used occasionally and it is as such not easy to assign emission limit values. The following table gives an overview of the ratio of flaring to production in HR and some European refineries. The difference in flaring ratios could be attributed to a number of factors: the type of crude processed, different processing operations, more operability problems (upsets) etc. [SDCEA_05]. Refinery Kilograms of gas flared / tons of crude

processed per day

Shell, Denmark 0.644 Statoil, Denmark 1.29

Haifa Refinery 0.87 Belgian Refinery 2.41 Because emission monitoring is not easy to realize, emission values can be estimated on the base of emission factors. Emission factors result from extrapolating emission measurements on equivalent lab scale installations. They express the relationship between the flare gas characteristics and their corresponding emission values.


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Therefore estimates on emission values can only be made if the operator has a continues flow rate and caloric value monitoring system. If sulphur-rich gases are flared, more accurate SO2 emission can be determined by monitoring the H2S load. Estimation of the flue gas composition is made by VITO on basis of following data:

vol% Paraffines CH4 10.0% C2H6 6.0% C3H8 3.0% Olefines C3H6 3.0% Aromats C6H12 0.0% Hydrogen H2 72.0% Carbonmonoxyde CO 0.2% Nitrogen N2 5.0% Hydrogensulphide H2S 1.0% 100%

Estimate of flue gas:

Old flare New flare Ton flare gas/year 2371 4407 Million Nm3 flare gas/year 30 55 Ton SO2/year 45 83

3.3 NOx

3.3.1 Refinery wide (bubble concept)

In contrast to SO2, few refineries in EU have a bubble for NOx. Figure 4 shows a comparison of the emission of HR in 2005 with the emission data of EU refineries in 2003.


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Figure 4: Comparison of HR NOx load bubble of 2005 to emissions EU refineries 2003

Concerning the NOx emissions per tonne crude oil processed, the Haifa refinery is situated higher than the 90 percentile. This indicates that about 90 percent of the European refineries have a lower NOx emission factor per tonne crude oil. In other words, there is a considerable improvement potential.

3.3.2 Flares

Estimate of flue gas:

Old flare New flare Ton flare gas/year 2371 4407 Million Nm3 flare gas/year

30 55

Ton NOx/year 3 5


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3.4 SO2 and NOx in Flanders and the Netherlands

The measured and expected of emissions in Flanders [VMM 06] and the Netherlands [INFOMIL 06] for, respectively, 2005 and 2010 for SO2 and NOx indicate a large emission reduction potential for HR. The concentration bubbles for Flanders (SO2 and NOx) and the Netherlands (SO2) are derived from legislation. In 2005, the load bubbles for Flanders and the Netherlands are calculated from emission inventories. In 2010, also a load limitation is applicable in Flanders. For HR, all data is calculated from emissions in 2005.

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Figure 5: Comparison of the emissions of SO2 and NOx of HR in 2005 with situation in Flanders and the Netherlands in 2005 and the expected situation for 2010.






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3.5 VOC

European Emissions found in European refineries (including storage farms) range from 600 to 10000 tons of VOC emitted per year. The specific emission range found is situated between 50 and 6000 tons of VOC per million tones of crude oil processed. Haifa refinery

The VOC emissions from HR:

VOC source VOC emission tons/year

Storage Blow down Flares Process drains Ejectors Cooling towers Vessel relief valves Miscellaneous Stacks Valves, flanges Pumps seals Compressor seals

337 1500

20 2400

60 120 270 270 730 710 950 130

TOTAL VOC +/- 7500

3.6 Energy use

World data In 2002, the first decile (10% best refineries) had a Solomon index of 76. Almost all Belgian refineries have a lower (better) index. Haifa refinery HR has a Solomon index of 953. Even taking the specific situation (configuration) into account, this index is not good. The oxygen content in flue gases confirms the low energy efficiency at HR.

3 Full utilization


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Chapter 5 Cost curves with multipollutant costing model

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In this chapter the current situation at HR is described and checked for its BAT compliance as it is described in the BREF document on “Mineral Oil and Gas Refineries”. If BAT-associated emission levels are suggested in the BREF document, they are also compared with the current HR performance. For each process/activity a table which gives an overview of its current BAT compliance. The implementation of the suggested BAT is evaluated “Yes” if the measure is applied in HR, “NO” if the measure is not applied in HR, “NI” if there was no information available about its application in HR, or “NA” if the measure is not applicable in HR.

4.1 Refinery wide

4.2 Process/activity

4.2.1 Fluidized Bed Catalytic Cracker

4.2.2 Cooling systems

BAT implementation at HR: The suggested BAT are applied in HR.

BAT implementation in HR: SNCR nor SCR are applied. The BAT for the reduction of PM-emissions from the FCC regenerator gas are not applied. An ESP or scrubber installation should be installed.

BAT implementation in HR: An environmental management system is implemented but no annual report is published. The specific reduction measures are checked below.


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4.2.3 Energy system

4.2.4 Gas separation processes

4.2.5 Hydrogen consuming processes

4.2.6 Hydrogen production processes

4.2.7 Isomerisation

4.2.8 Natural Gas Plant

BAT implementation in HR: This plant is not in operation at HR, and is therefore not evaluated.

BAT implementation in HR: The suggested BAT are applied in HR.



BAT implementation at HR: Energy efficiency is hard to compare. From bottom-up information, we hardly know how energy recuperation, integration,.. is applied. We do know from top-down that the oxygen concentration indicates that the energy efficiency is very low. Also the Solomon index has a low benchmark. Emissions SO2, NOx and PM are discussed in chapter 3 and 6.


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4.2.9 Polymerisation

4.2.10 Primary Distillation Units

4.2.11 Product Treatments

4.2.12 Visbreaking

4.2.13 Amine treating

BAT implementation in HR: This plant is not yet in operation at HR and is therefore not evaluated.

BAT implementation in HR: This plant is not yet in operation at HR and is therefore not evaluated.



BAT implementation at HR: This topic will be further discussed below (spent caustic)

BAT implementation at HR: The suggested BAT are applied in HR. Additional information on the maximisation of the liquid ring vacuum pump and surface condensers is required. It is also not known if crude distillation units are used as an alternative to reprocess slop.


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4.2.14 Sulphur recovery units

4.3 Flares

Flares are used for safety and environmental control of discharges of undesired or excess combustibles and for surges of gases in emergency situations or upsets. Actual flare gases in normal conditions could be:

- Low continuous flow from pressure relief valves, drainages and pressure regulators, and storage tanks.

- Waste gases from regeneration of catalysts in cracking units. - Process gases (C3/C4) which do not fulfil product specifications (off-spec) as far as

they are not reprocessed. Gas recuperation systems should minimize these streams. - Flushing gases from reactor and pumps before release for maintenance, during

replacement of absorbers. - Hydrogen-rich streams from planned absorber replacements during the production

process. As a consequence of the following occasions a large amount of gases can be sent to the flare system in a short timeframe:

- A complete close down of the cracking unit (planed maintenance or process failure) - Malfunctioning of compressor during cracking, desulphurisation,… - Malfunctioning of cooling unit (e.g. cooling unit from ethylene storage tanks) - Malfunctioning of sulphur recuperation units. H2S-rich streams are sent to the flare

leading to a large amount of SO2-emissions - Malfunctioning of desulphurisation unit by which a sulphur-rich stream needs to be

flared. As flaring is intended to be a safety system and thus used only occasionally, it is not easy to assign emission limit values. Description of HR Flare system HR has an integrated flare system which consists of two connected elevated flares. They are used in a planned continue regime. The largest flare (F1) has a flare tip of 106.7 cm and a flow rate of 25 GJ/h. The other one (F2) has a flare tip of 91.4 cm and a flow rate of 12 GJ/h. Both flares have 4 pilot burners and are provided with an automatic steam control system. BAT according to BREF Mineral oil and gas refineries

BAT implementation at HR: If an efficiency of 99.5% is attained, BAT is implemented. The SRU capacity is enough for further recovery of sulphur.


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Description BAT

1. Use flaring as a safety system (start-up, shutdown and emergency)

The easiest way to decrease the flare emissions is to reduce the amount of flare gas. This can be accomplished by using it as a safety system only. Burning waste gasses or by-products that are not economical retainable or using it as a general pressure relief system should be avoided.

2. Ensure smokeless and reliable operation

The flare is required to be smokeless for the gas flows that are expected to occur from normal day-to-day operation. This gas flow is usually designed at 15 to 20% of the maximum design flow.

Well operated refinery flares typically obtain a conversion of 98% to CO2 (this figure is used by the Flemish environmental authority), 1.5% to partially combusted products (almost all CO) and 0.5% remains unconverted.

In Flemish refineries the flare system is designed to cover 30% of the maximum design flow. In case of maximal flaring (total shutdown, including the power plant) smokeless flaring can be assured after 10 minutes at the latest. To ensure maximal smokeless flaring Flemish refineries have made recently investments to increase the flaring capacity and to spread the flare gas amount in time by bringing into use additional buffering tanks. The steam injection system and the pilot burners are optimised as well. Steam is produced in the independently operated cogeneration units.

a) Pilot Burners

The use of pilot burners leads to a more reliable ignition of the vent gases because they are designed not to be extinguished by a powerful wind. The number of burners depends on the diameter of the flare tip, the composition of the vent gases and the wind conditions. A relationship between tip diameter and number of pilot burners is given in the table below.

Diameter flare tip (cm) Number of pilot burners 1 – 25 1 30 – 60 2 76 – 150 3 > 150 4

b) Steam injection

Steam controlled elevated flares are the best suitable installations for flaring high calorific gases containing small hydrocarbon chains. Considering the unlimited availability of steam, this type of flare can be seen as best available technique within refineries.

BAT implementation at HR: Flares are used as a safety system. However the flare system is used in a planned continuous programme which may also include continuous flaring of pressure relief gases or off-spec gases.


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Technical background

Steam injectors placed around the burner head will raise the gas turbulence within the flame. Therefore more combustion air is drawn towards the flame which improves the combustion efficiency.

Steam injection reduces the formation of soot. This can be explained by the fact that water vapour reacts with solid carbon particles forming CO, CO2 and H2. In consequence carbon will be removed before it cools down to form soot.

An additional effect of steam addition is the lowering of the flame temperature. This will reduce the formation of thermal NOx. A lower flame temperature will also extend the life of the flare tip. However, the temperature needs always to be above the ignition temperature of the carbon particles.

Drawbacks of steam injection are the high costs and noise nuisance. The noise level can be reduced by using multiple small steam injectors and additional sound insulation.

Recently a malfunction of the HR led to a non-smokeless flaring operation because – due to its malfunction – no steam was available. To avoid this situation in future, the refinery connected the flare system to an external steam source which ensures the supply of steam also during emergency situations in which there is a total shutdown.

The two large Flemish refineries have cogeneration units installed which work independently from the refinery plant. The cogeneration plants are connected with the flare system, so steam can be applied in emergency situations (total shutdown).

c) Calorific value

The waste gas must have a heating value of at least 11 MJ/Nm³ for complete combustion, otherwise fuel must be added to the flare to obtain complete combustion [TAUW_01]. In general the heating value of refinery flare gases will exceed this value.

3. Minimise flaring by a suitable combination of

a) Balancing the refinery fuel gas system

Refinery fuel gas pressure has to be kept within a safety range. If more fuel gas is delivered then consumed, pressure will rise in the fuel gas header. If this situation continues the fuel gas flare valve will have to open eventually in order to prevent the pressure from exceeding maximum safety limits. To minimize fuel gas flaring, the occurrence of these conditions should be avoided by balancing the refinery fuel gas system.

BAT implementation at HR: Both F1 and F2 have four pilot burners to ensure reliable ignition. Flares are provided with an automatic steam control system and the flare system is attached to an external steam source as well and thereby ensuring the steam supply during total shutdown emergency situations. The calorific value of the HR is sufficient to ensure complete combustion. In total shut down situations, smokeless flaring should be ensured within 10 minutes.


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In HR the fuel gas system is balanced using an advanced control system. The pressure is kept constant by adding LPG gas during under pressure and by collecting excess gases in buffer tanks when overpressure occurs.

b) Installing a gas recovery system

In a gas recovery system, the flare gas is captured and compressed for other uses. Usually recovered flare gas is treated and routed to the refinery fuel gas system. The practice of flare gas recovery offers many benefits, including an increase in overall plant efficiency, reduced fuel gas costs, reduced emissions, and reduced auxiliary flare utilities (pilot gas, steam, etc. ).

At the moment of writing the implementation of a gas recovery system is planned but not yet executed at HR.

c) Using high-integrity relief valves

According to the BREF document [BREF 03], valves are the type of equipment that causes most of the leaks (40-65%) Valves with rising stems and in particular control valves are an important source of leaks. To minimise flaring, the BREF document recommends to implement high-integrity relief valves. However, no exact definition or associated emission factor is described.

According to HR, modern valves which have a emission performance of about 300 ppm are installed. Therefore, the valves connected to the flare system are not considered as a relevant source of flare gas losses.

d) Applying advanced process control

Refinery flares have to deal with highly variable amounts of flare gases in time. Therefore, some control and monitoring systems need to be applied to ensure safe and optimal combustion conditions.

Control measures applied in Flemish refineries are [TAUW_01]: - Control measures on incoming flare gas: Implemented in

HR? o Flare gas flow rate monitoring Yes o Flare gas temperature monitoring No o Supply pipe pressure monitoring Yes o Flare stack oxygen monitoring No o Water seal Yes o Knock-out drum Yes o Nitrogen rinsing No

- Control measures on flare emissions: o Camera control Yes o Steam injection (see above) Yes o Steam flow rate monitoring Yes o Flare stack temperature monitoring No o Pilot flame monitoring Yes o Backfire protection Yes

HR has implemented most of the control measures, except for flare gas temperature monitoring, flare stack oxygen monitoring and nitrogen rinsing.


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In some installations the flare sulphur-rich incoming gas streams are monitored additionally for H2S content and molecular weight. This leads to a better insight in total SO2 emission. The H2S concentration of flare gases in Flemish refineries vary between 0-10%. The average value for flare gases in the USA is 2.4%. At HR the flare gases have an average H2S content of about 1%, which is considered to be rather low. [TAUW_01]

4.4 Odour

Different potential sources of refinery odours are known:

- wastewater treatment facilities - fugitive emissions from leaking process components (e.g. valves, pump seals,

flanges) - sulphur recovery unit - bitumen processing unit and storage tanks - bulk storage tanks - vapour emissions from transferring liquids

It is recognized that odour abatement is linked to VOC (typically sulphur-rich compounds and phenols) and H2S abatement. BAT according to BREF Mineral oil and gas refineries The BREF on refineries does not tackle the problem of odour by proposing odour specific measures (expect for the bitumen processing). However the odour problem in refineries is linked to VOC emissions. Therefore all BATs on VOC abatement can be recognized as odour abatement techniques. To reduce emissions from storage and transfer, the BREF document on emissions from storage suggests some general BAT. These BAT are specified for the specific situation of refineries in the BREF on refineries.

BAT implementation at HR: The refinery fuel gas system is balanced and high-integrity valves are used. A flare gas recovery system is planned but not yet implemented. Some additional advanced process control measures can be applied also: flare gas temperature monitoring, flare stack oxygen monitoring, nitrogen rinsing and flare stack temperature monitoring. The average H2S content of the flare gases is considered to be rather low compared to other refineries.


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Description BAT

1. Process emissions – Quantifying VOC emission sources

VOC emissions can be estimated by USAEPA Method 21 (emission factors for different types of equipment) or by mass balance (feedstock – products). Other methods for the monitoring of VOC emissions as well as the locating sources of VOC emissions have been developed and proven in recent years. Typically they make use of laser absorption techniques (DIAL) of considerable sophistication. Based on the EPA AP-42 emission factors HR estimated their current VOC emissions to be 7500 tons/year. Recent VOC estimations tend to give significantly lower emission levels (no detailed data available yet). This can be explained by the implementation of some VOC abatement measures combined with the use of another estimation method.

2. Process emissions – Executing LDAR campaigns or equivalent

Uncontrolled emission due to the leaking of relief valves, safety valves, bypass valves, and control valves can lead to heavy losses of gases towards the flare system. LDAR (Leak Detection And Repair) compromises the detection and reparation of flare pipe shutoff valves. A portable instrument is used to detect VOC leaks during regularly scheduled inspections. Leaks are then repaired immediately or scheduled for reparation as quickly as possible. A LDAR contains the following elements: - Type of measurement, - Frequency, - Type of components to be checked, - Type of compound lines, - Which leaks should be repaired and how fast the action should be taken. In the future this labour intensive programme (on-site detection) may be replaced by a ‘smart’ LDAR system. This device is able to detect (using laser technology) fugitive hydrocarbon emissions by real time video imaging of the equipment under surveillance. It allows the user to identify at a refinery the zones where the largest emissions are located so that an LDAR using sniffing techniques can focus on the high emission items. A specific BREF is dedicated to the principles of monitoring.

3. Process emissions – Technical measures

A detailed description of the various technical measures can be found in the BREF on mineral oil and gas refineries, pages 352-353. HR has implemented or is implementing the required technical measures to reduce VOC emissions.

BAT implementation at HR: The VOC emissions from HR are determined based on EPA AP-42 emission factors.

BAT implementation at HR: There is no LDAR system implemented.


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In February 2006, 50-60% of the maintenance drain-out system was adopted, including the FCC, CCR, Gasole, HDS, and the Crude unit. All new units are provided with double sealed low leakage pumps. All remaining pumps are planned to be replaced by 2009.

4. Process emissions – Minimising flaring

See 4.3.

5. Process emissions – Waste water treatment plant

Several potential sources of odours related to waste water streams can be distinguished:

- Acids have the potential to form hydrogen sulphide (H2S) in wastewater which is a volatile product. Spent sulphuric acid, for example, produced in the alkylation unit could result in increased sulphide emissions if it is discharged to the sewers as it reacts with the wastewater.

- Spent caustics contain odorous substances such as dissolved sulphides, reduced sulphide compounds (e.g. mercaptans) and phenols.

- Tank dewatering contains odorous substances such as dissolved sulphides, reduced sulphide compounds (e.g. mercaptans) and phenols.

- Sour water contains sulphides, ammonia, phenols and volatile organics.

- Hot streams (e.g. boiler blow down, desalter effluent and steam condensate) though not necessarily odorous in themselves, can be source of odour as high temperatures increase volatilisation of organics and sulphides.

In general a three-step waste water treatment unit, consisting of a gravity separation (primary treatment), an advanced physical unit separation (secondary treatment) and a biological reactor (tertiary treatment) is applied to treat the refinery wastewater streams.

To reduce malodorous emissions from the primary treatment, the oil/water separators (CPI, API) can be provided with covers, sometimes completed with off-gas treatment (biofilter or re-injected into the aeration basin).

The next level of control is to install water seals (traps) on sewers and drains and gas tight covers on junction boxes in the system. The use of covers on oil/water separators with good oil removal facilities will prevent or reduce evaporation of liquid hydrocarbons from exposed surfaces. Alternatively, incineration of the vapours coming from the API could be achieved by applying a covered API separator. In the secondary treatment waste water is processed for the removal of dispersed oil and solids by air flotation. Odorous emissions at this stage can be reduced by covering the air flotation units and if necessary followed with an off-gas treatment (biofilter or re-injected into the aeration basin). In a third step the water is routed to a biological reactor (usually an activated sludge unit) or to a trickling filter. In this step most of the odorous emission will be generated at the

BAT implementation at HR: HR has implemented or is still is implementing the required technical measures to reduce VOC-emissions..


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aeration basins of the biotreaters. Therefore the covering of these basins with a subsequent off-gas treatment will minimise these emissions. Covering will lead to accumulation of VOC, therefore safety aspects (explosiveness of VOC-air mixtures) are to be attended. Although at the HR most of the separators, basins and inlet bays are covered, the wastewater treatment plant remains a major odour source. This may be explained by the fact that a 30.000m³ ‘storm tank’ is not yet hermetically sealed. At this moment the tank is still completely open to the air. Process water containing hydrogen sulphide and ammonia is treated in a sour water stripper before it will be treated in the waste water treatment plant. Typical composition of odorous components of sour water is 900 mg/l H2S, 2000 mg/l NH3, 200 mg/l phenols. The effluent from a traditional sour stripper still will be loaded with about 10 mg/l H2S, 75-150 mg/l NH3, and 30-100 mg/l phenols. With a two stage stripping system effluent concentrations of 0.1-1.0 mg/l H2S and 1-10 mg/l NH3 may be reached. Sour off-gases from a stripper unit are preferred to be routed to a sulphur recovery unit instead of being routed to an incinerator or flare. At the HR sour water is drained in closed systems including total stripping.

6. Storage emissions – BAT determined in BREF on storage

BAT on storage of liquids apply on tank design, inspection and maintenance, location and layout, tank colour, emissions minimisation, VOC monitoring, and dedicated systems. All these aspects are well described in the BREF on storages.

7. Storage emissions – Refinery specific measures:

A common technique for tank cleaning is to dissolve the majority of the tank bottoms with hot diesel fraction at temperatures of around 50°C. VOC emissions arise during natural or mechanical ventilation. Applying modern cleaning techniques combined with primary measures (as defined in the BREF-document) should result in less then 0.5 kg VOC emissions per square meter cleaned tank bottom area. With secondary measures (e.g. installation of mobile flares, which are currently under development for cleaning crude oil and product tanks) further emission reductions of VOC up to 90% can be expected. For liquids containing a high level of particles (e.g. crude oil), BAT is to mix the stored substance to prevent deposition so an additional cleaning step can be avoided.

BAT implementation at HR: According to the first questionnaire this should be the fact. Double sealing is mentioned and because the light end vapours are a major source of VOC emissions, HR started to place domes above the floating roofs.

BAT implementation at HR: Most of the separators, basins and inlet bays of the waste water treatment plant are covered and the vapour is treated. However, the waste water treatment plant remains a major odour source probably due to the 30.000m³ ‘stormtank’. Sour water from all units is treated in a closed system including total stripping.


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It is important to operate in closed conditions to prevent VOC emissions during operation, transportation and/or disposal. Trucks should be designed with gas scrubbers to capture unwanted emissions. At HR, storage tanks are double sealed which should avoid VOC emissions during cleaning. The removed sludge is treated at an innovative land farming site (in corporation with a local research institute). The transportation of the sludge should be executed in a closed system and trucks should be equipped with gas scrubbers. The need for certain tanks can often be eliminated through improved production planning and more continuous operations. For example in-line blending reduces the total number of handling operations with respect to feed and product streams – less filling and emptying of tanks and thus reduced total emission to the atmosphere. According to HR information all required measures to minimize the use of storage tanks are taken. Tanks for vaporous refinery products should have external floating roofs or fixed roofs with an internal floating roof or with a vapour treatment installation. Using an external floating roof with liquid mounted primary seals and rim mounted secondary seals, can lead to a reduction in air emissions of up to 99.5% (compared to a fixed roof tank without measures). A dome can be BAT for adverse weather conditions (high winds, rain or snowfall). All HR storage tanks are provided with double sealed coverage. HR also started with the placing of domes. Vapour balancing can be used for both the loading and unloading of transporters. During loading, the vapours displaced from transporter are collected through pipe work installed on the transporter (or through specially designed loading arms) and displaced via vapour balancing pipe work back to the storage tank from which the products are pumped. Vapour balancing of non-pressurized storage tanks and transporters is only applicable to fixed roof tanks. This system is applied for the road-tanker filling station only. Other potential applications at HR should be investigated. Vapour recovery units (VRUs) are installations designed for the emission reduction of VOC which are emitted during loading and unloading operations of vaporous products. Several commercial techniques are available for the recovery of VOC. Those techniques can be divided in two large groups according to the type of separation. One group includes techniques which separate the VOC from the air due to pressure swing adsorption on activated carbon, absorption by lean oil washing (kerosene), selective membrane separation or condensation by cooling or compression (this is a special case because separation and re-condensation are both achieved in a single process). The other group comprises the techniques in which the VOC are separated by condensation to liquid state. It includes re-absorption into the gasoline or crude oil, condensation and compression. VRU technique VOC removal efficiency (%)


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Absorption 99 – 99.95 Adsorption 99.95 – 99.99 Membrane gas separation 99 – 99.9 Refrigeration/condensation 99.8 – 99.95 The latter method can result in low exit concentrations if the applied refrigeration temperature is low enough. A great advantage of condensation is that the vapours are recovered as pure liquids (no waste), which can easily be returned directly to the storage tank. Ranges are caused by the use of 1 or 2 stages. Higher removal efficiencies are only reached with high inlet loads. At HR, this system is only installed at the truck terminal, not on the storage tanks themselves.

4.5 Spent caustic

Caustic treatment is a process applied to gases, naphtha and kerosene, either with liquid caustic to remove small amounts of hydrogen sulphide or on impregnated solid catalysts to turn corrosive mercaptans into harmless disulphides. The latter can be extracted if desired to reduce the sulphur content of the stream. The aqueous spent caustic solution from these treatments is loaded with various contaminants including sulphides, mercaptans, naphtenates and phenols (cresylates), as well as emulsified hydrocarbons. An overview of a typical refinery operation illustrating the production of spent caustics from various hydrocarbon fractions is given below: Source Stream Caustic produced

Off gas Saturated LPG LSR Naphtha

Sulfidic Caustic

Kerosene Crude distillation unit

Diesel Naphthenic Caustic

Unsaturated LPG Light FCC naphtha

Sulfidic Caustic FCC

Heavy FCC naphtha Cresylic Caustic Coker off gas Coker Light coker naphtha

Sulfidic Caustic

Use of caustic soda in Haifa refinery.

BAT implementation at HR: General BAT measures to reduce VOC emissions from storage are taken at HR. However, improvements can be made on the level of VOC recovery and/or recuperation units. Also the transportation and processing of sludge as a result of the tank cleaning process should be observed as these are potential VOC emissions (odour) sources.


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Four processes are making use of caustic soda:

- LPG MEROX: 2000 tons/year – NaOH 20.0% wt - Kerosene wash: 3000 tons/year – NaOH 5.0% wt - Naphta wash: 150 tons/year – NaOH 10.0% wt - Water treatment: 1200 tons/year – NaOH 45.0% wt

None of the generated spent caustic is reused within the refinery or sold to other companies. All spent caustic (except water treatment) is discharged after an oil separation pre-treatment. Discharges of spent caustic:

- LPG MEROX: 2000 tons/year – NaOH 10.0% wt - Kerosene wash: 3000 tons/year – NaOH 2.5% wt - Naphta wash: 150 tons/year – NaOH 5.0% wt - Water treatment: No discharges

Concentrations of other components were not given. At this moment spent caustics from HR are treated outside the Haifa region. In the future HR is planning to build a spent caustic treatment plant at their site. This plant will also treat spent caustic produced at the second Israeli refinery. The building of this treatment plant is currently a point of discussion because of it’s potential environmental impact (mainly odour). BAT according to BREF Mineral oil and gas refineries: Description BAT:

1. Implement a good management system of the caustic solutions with the aim of minimising the use of fresh caustic and maximising the use of spent caustic. Techniques that could be used:

a) for recycling are cascading of caustic solution and the re-use of spent caustic solutions by stripping:

Cascading:

Cascading of caustic streams from one unit to another provides an opportunity to optimise caustic use while reducing the quantity of fresh caustic needed as well as the total wastewater treatment load. A typical example of this procedure is the bleed of regenerated caustic (e.g. in mercaptan treaters for cat cracked gasoline or for removal of H2S or thiophenols) in a pre-wash step of the non-catcracked gasoline sweetening processes.

Re-use [CONCAWE_03]:

Within the refinery:

o Spent caustic can be reused instead of fresh caustic for corrosion control on distillation unit as part of an integrated caustic management system.

The applicability of this technology depends on the crude processed in the refinery. According to HR-information this option is technically not feasible.


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o Spent caustic can be added to the biological treatment plant for pH control. This option is feasible for HR but is not yet applied.

o Recycling of caustics towards sour water strippers. This technology is feasible for HR because the sour water is reused at the desalter.

o Caustics containing phenols can be recycled on-site by reducing the pH of the caustic until the phenols become insoluble thereby allowing physical separation. The caustic can then be treated in the refinery wastewater system.

This technology is feasible for HR, but this will involve that the waste is treated on site and odour reduction measures need to be undertaken. Also it should be examined if the local water emission limits will not be exceeded.

Outside the refinery:

o Sulphidic caustic solution can be sold as treating agents to pulp and paper plants or to the mining industry for purifying certain metal ores. To obtain the required quality the sulphidic caustic will usually be sold to an intermediate company.

Sulpidic caustic is mainly a waste product from the petrochemical industry and not an issue in HR. Also the local paper mill industry is not widespread therefore it is not clear if re-use for this purpose would be achievable.

o For the production of Na2SO3, cresylics and Na2CO3 sulphidic, cresylic and naphthenic caustics can be reused.

This has been done in the past, but had to be stopped because of the accompanying odour problems.

o Spent caustics may be saleable to chemical recovery companies if concentrations of phenol or hydrogen sulphide are high enough. Process changes in the refinery may be needed to raise the concentration of phenols in the caustic to make recovery of the contaminants economical.

This option becomes interesting when large volumes can be sold. According to HR it is not an option to store this spent caustic until a saleable amount is reached.

To obtain an optimal reuse of spent caustic following remarks should be considered:

o All types of spent caustic should not be mixed in the same storage vessel. This makes the entire mixture unsaleable.

o All types of caustics should not be treated in the treating plant designed for only one type.

o The pH in neutralizers needs to be monitored to obtain an effective contaminant removal.


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When spent caustics can not be reused because of their potential end-users are far away (resulting in high transportations casts) in-plant processing may be the most economical option.

For sulfidic caustic this might entail: o Neutralization: Neutralization to a pH below 4 is more appropriate than a

neutralization to a pH of 7 because at the latter level there is no significant reduction in contaminants.

o Oxidation to convert sulphides to thiosulphates (this avoids the risk of releasing unsafe, odorous H2S and mercaptans).

o Total oxidation of sodium sulphide to sodium sulphate for maximum removal of COD and BOD before the wastewater treating plant.

o Cascading to other treating systems where the caustic by-product is converted to a more valuable product such as cresylic caustic.

Direct transfer to the effluent treatment system is preferred over disposal to the sewer as this carries the risk of generating additional solids.

b) for destruction are injection to desalters or incineration of remaining spent caustic solutions when COD is high (e.g. > 100 g/l).

c) other minimization measures are:

o Use of amines which are regenerable and also save energy o Use of high efficiency contacting systems rather than a simple washing

optimising usage.

Current state at Flemish refineries In a Flemish refinery, with a yearly crude throughput of more than 14 million tons, following processes are making use of caustic soda:

- LPG MEROX: 3125 tons/year - Kerosene MEROX: 6250 tons/year - Gasoline MEROX: 2500 tons/year - Gas plant: 625 tons/year

The NaOH solutions contain around 20% of NaOH. The spent caustic is a corrosive solution that contains 5% NaOH, sulphides, phenols,… An analysis of 1997 described following spent caustic quality: - Total alkalinity (NaOH) 3 - 13 % - MDEA (Methyl Diethanol Amine) 0 - 5 % - Sulphides (as S) 5000 - 70000 ppm - Mercapatans (as S) 500 - 5000 ppm - Phenols 2000 - 30000 ppm

BAT implementation at HR: At the HR no management system with the aim of minimizing the use of fresh caustic and maximising the use of spent caustic is implemented. Also the feasibility of potential options for re-use of spent caustic should be further investigated.


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- Naphtenates 0 - 10000 ppm - Hydrocarbons 50 - 700 ppm The caustic is re-used as much as possible within the refinery. The unusable spent caustic is treated in the refineries wastewater treatment plant. To avoid odour problems the complete process occurred in a closed system. The spent caustic from different units is collected and acidified. HCl is added so that the solution reaches a pH of 4. As a result, all sulphides in the mixture are converted into H2S. This H2S is scrubbed. The acidified caustic is now send to sedimentation tanks to separate the cresols and organic acids from the aquatic phase. Recently the discharge of treated spent caustic in the WWTP is restricted because of stricter water emission limit values. When the yearly emission limit values for nitrogen (amine containing residues in spent caustics) are reached, the refineries have to stop the treatment. The spent caustic is then collected by waste treatment companies. The removal and the transportation of the spent caustic also occurs in closed system to avoid odour problems. Trucks are applied with gas scrubber installations. Treatment of spent caustics with a wet air oxidation unit In some refineries, which needed to dispose their spent caustics (e.g. RPDM Rio De Janeiro, Brazil) a wet air oxidation system is applied. Wet air oxidation is a well known technology for the treatment of spent caustics from ethylene plants. Since about 10 years, the technology is also applied for the treatment of refinery spent caustic streams. Wet air oxidation detoxifies the spent caustic by oxidising the sulphides and mercaptans to sulphate and breaking down the toxic naphthenics and cresylics. Hereafter the oxidized spent caustic can be sent to the refinery’s (biological) waste water treatment system for final treatment. The implementation of a wet air oxidation system, which instantly treats the spent caustic waste stream, can eliminate the odour problems of temporal storage before off-site disposal.


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33

CCCHHHAAAPPPTTTEEERRR 555 CCCOOOSSSTTT CCCUUURRRVVVEEESSS AAANNNDDD BBBUUUBBBBBBLLLEEESSS WWWIIITTTHHH MMMUUULLLTTTIIIPPPOOOLLLLLLUUUTTTAAANNNTTT CCCOOOSSSTTTIIINNNGGG MMMOOODDDEEELLL

5.1 Multipollutant costing model

The Multi-pollutant Environmental Costing Model is a tool to determine the costs of environmental policy and contributes to a more efficient environmental policy by indicating how environmental targets can be realized in a cost effective way. Cost efficiency plays a key role in the Environmental Costing Model. If only one environmental objective, one pollutant and a few emission sources, has to be taken into account, the cost efficiency analysis is a straightforward exercise. In this case, it would be sufficient to rank possible abatement measures based on their (marginal) costs and reduction potentials and select the cheapest measure or combination of measures to realize the environmental objective. Usually, however, the analysis involves multiple emission sources, pollutants, abatement measures, interactions and trade-offs. The least cost solution can not be determined by a simple overview of the (marginal) costs and emission reduction potentials of abatement measures. The core of the Environmental Costing Model is a database of emission sources and abatement measures with their associated emission reduction potential and annual costs. All installations of the Haifa refinery that are documented in the enquiry are individually modeled. Abatement measures are described by means of their investment costs, operating costs, lifetime, capacity and reduction efficiency. All applicable and quantifiable BAT measures not yet implemented in the Haifa refinery and

which are discussed in chapter 4 have been put into the model (see

Figure 6) . This includes reduction measures which have interactions with other techniques and reduction measures which have no interactions at all. Furthermore, the reduction technique database is completed with information from literature, surveys and contacts with e.g. experts and federations in Belgium. The format of the database makes it possible to describe process-integrated measures (e.g. fuel switch) and end-of-pipe techniques


34

(e.g. flue gas cleaning). A list of all installations, devices and their reduction measures is included in annex 2.

Figure 6: All quantifiable BAT measures in the model

The Environmental Costing Model is used in this project: - For generating cost curves for the most important pollutants in the Haifa refinery. Cost

curves describe the most cost effective combination of abatement measures for various emission reductions for one pollutant. The bonus effect on other pollutants can be examined as well. A cost curve shows the cost (Y-axis in k$/ton) to reduce an extra ton of emission (X-axis in tonne pollutant). Marginal cost curves can be used to compare different companies or sectors depending on their cost per tonne reduction that can be achieved.

- For generating certain load level bubble emissions. Bubble emissions have to be implemented on the company level. Therefore the bubble concept is less strict in that not all the individual installations have to meet given emission or concentration values. The model simulations were performed by enforcing a certain load level for SO2 and NOx.

5.2 General model assumptions

5.2.1 Fuel prices

The price of crude oil corresponds to the price for an average crude with a cost of 60$/bbl. The price of natural gas is fixed at 8,5 $/GJ. This corresponds to a price for gas of approximately 8,5 $ per million BTU. Fuel Price

($2006/GJ) Crude 9.80

All applicable BATmeasures missing

Impossible to quantify

Possible to quantify

No interaction

Interaction with other techniques


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Heavy fuel oil (0.99% S) 7.94 Heavy fuel oil (0.70% S) 8.10 Heavy fuel oil (0.50% S) 8.22 Natural gas 8.50 Gas oil 12.75 LPG 10.78 Refinery gas 8.50 The prices for the heavy fuel oil (HFO) are a result of VITO calculations, based on mathematical relations of the price of crude oil and the percentage of sulfur [ESMAP 05]. The price of HFO with 1% sulphur is derived from the cost of the crude oil with the help of an empirical relation. Low sulphur oil can be produced by using different crude mixes or by excessive desulphurization. VITO used the switch to another crude as an estimation of cost. The price difference of fuels with lower S (0.7% and 0.5%) is also calculated with empirical data. In [ESMAP 05] a statistical analysis found a significant relation between crude oil price differentials and differences in oil qualities. One of those qualities is the sulphur content. The price difference for a heavy fuel oil with 0.5% sulphur is 0.28$/GJ compared to a heavy fuel oil with 1% sulphur, assuming a crude oil price of 60$/bbl. VITO also checked this price with the average cost of flue gas desulphurization and found that it is with in the same order of magnitude. As is shown in chapter 6, the uncertainty on price differences is not so relevant for the total annual cost.

5.2.2 Discount rate and lifetime

All calculations take 5% for the discount rate. All cost data are reported in 2006$ (i.e. annual total reduction cost). Economical lifetime (depreciation time) is assumed to be 15 years.

5.3 SO2

Installation Reduction measure

Reduction %

Investment cost [k$]

Operational cost

[k$/year] Power plant FGD (De-SOX) 80

(SO2, PM) 30 000 1 912

Power plant + CU3 + CU4 + FCC

FGD (De-SOX) 80 (SO2, PM)

45 000 3 248

FCC De-Sox additive in catalyst

50 / 350

All heavy fuel oil burners

Fuel switch (HFO 0.985 %S → HFO 0.5 %S) (HFO 0.7 %S →

HFO 0.5 %S)

20 - ± 50 / Difference in fuel price: 0.12 – 0.28

$/GJ


Fuel switch (HFO → nat.gas

with low NOx burners)

100 (60% NOx) (100% PM)

2 MWth = 36.6 4 MWth = 45.2 6 MWth = 51.5

Difference in fuel price: 0.55 $/GJ


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A more detailed description of the reduction techniques and their costs is given below: FGD (De-Sox): VITO used own study work for the cost information for FGD. In [VITO 05], cost information is described from a study on the possibility for the refinery sector to reduce pollutants causing acidification. This study used data from Europem NV4, Jacobs Engineering5 and [BREF 03] and comments from the Belgian refineries on the investment and operational cost of FGD. VITO also compared the cost data with a comparable case in the electricity sector in Belgium in [VITO 04]. Investment costs are channels, exhaust ventilation, purge treating unit (PTU), … inclusive and depend on the flow which has to be treated. - Flow: 90 000 Nm³/h : 9 360 k$ - Flow: 220 000 Nm³/h : 16 800 k$ - Extrapolated flow: 350 000 Nm³/h : 24 240 k$ - Extrapolated flow: 610 000 Nm³/h : 39 120 k$ For the Haifa refinery the investment cost was calculated using a linear extrapolation starting from the given data. - 2 682 MNm³/yr (PP) → 333 km³/h, 8 053 operating hours → 30 000 k$ - 4 861 MNm³/yr (PP, CU3,CU4, FCC) → 604 km³/h, 8 053 operating hours → 45 000 k$ The operational costs include the use of Ca(OH)2 and maintenance costs, electricity use, chemicals for PTU: - Ca(OH)2: 4.43 ton per ton SO2-reduction at a cost of 54 $/ton. - Maintenance cost: 3% of investment cost - Electricity PTU: 0.033 GJ/(Nm³/h) at a cost of 16.5 $/GJ - Chemicals PTU: 0.27 $/(Nm³/h) The Rhineland refinery at the Cologne-Godorf site in Köln invested from 2002 in building a flue gas desulphurization on their power plant. This power plant has almost the same yearly flow of flue gases as HR. Oral communication with the company who installed the FGD confirmed that the cost for the FGD is around 30 M€. The cost is 40 M€ if also the SCR and the waste water treatment plant are taken into account [STEAG 06]. De-Sox additive: VITO used information from [Davey 00]. The additive binds SO2 in the regenerator of the FCC (oxidizing circumstances) and releases the SO2 as H2S in the reactor (reducing circumstances). The H2S has to be washed in an amine column before it goes to a Claus unit. Assuming that the amine columns have the right dimensions there will be no investment cost. The operational cost is estimated at 1 338 $/ton SO2 reduced. Fuel switch: 4 http://www.euro-pem.com/indexEN.htm 5 http://www.jacobs.com

http://www.euro-pem.com/indexEN.htmhttp://www.jacobs.com


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VITO calculated the average S content (year 2005) of the heavy fuel oil that is used in the HR. - All installations (except power plant) : average 0.985% S in HFO - Power plant: average 0.7% S in HFO An important measure to reduce SO2 emissions is the use of fuels with a lower S content. There are no additional investment costs bounded to fuel switch as long as there is no switch from liquid to gaseous fuels. The existing burners can be used. There are operational costs as HFO with lower S content is more expensive to produce. Low S fuels can be produced by using different crude mixes or by excessive desulphurization. In addition to a switch to HFO with lower S content, a switch to natural gas has also been taken up in the model. We assume that the existing burners will have to be replaced when changing from liquid to gaseous fuels. Therefore low NOx burners on natural gas are proposed with the above mentioned investment costs. A switch to natural gas implies also a higher fuel price, which was estimated at 0.55 $/GJ. A fuel switch to gas is probable for the refinery in the future. Therefore cost curves with and without this option have been calculated.


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5.3.1 Cost curve SO2 with the option to switch to natural gas

SO2 cost curve with bonus effect on NOx- and PM-emissionswith natural gas option

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Figure 7: SO2 cost curve with bonus effect on NOx and PM emissions with the option to

switch to natural gas

The cost curve for SO2 starts at an emission level of 6 881 ton for the year 2005. Emissions can be reduced to 928 ton: there is a maximum reduction potential of 86.5% (see Figure 7). The numbers that are shown on the cost curve above point to the most important reduction steps. A detailed survey of the pathway is given below.

1. Fuel switch power plant: 1 955 PJ HFO 0.7% S → HFO 0.5% S Additional reduction: 264 ton SO2 Marginal cost: 1 $/kg

2. Implementation of FGD on power plant. CU3. CU4. FCC Fuel switch HFO burners: 1 363 PJ HFO 0.95% S → HFO 0.5% S No fuel switch: HFO 0.7% Additional reduction: 4 992 ton SO2 Marginal cost: 1.25 $/kg

3. Fuel switch HFO burners: 5 710 PJ HFO 0.95% S → Low NOx burners natural gas Additional reduction: 463 ton SO2 Marginal cost: 2-4 $/kg

4. Complete fuel switch HFO burners: remaining HFO 0.95% and all 0.7% S → HFO 0.5% S


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Additional reduction: 229 ton SO2 Marginal cost: 6-7 $/kg

To interpret this marginal cost curve correctly the following description can be used. The runs generated by the model are not sequential, in other words, a reduction technique chosen at a given marginal cost does not have to be chosen at a higher marginal cost, as long as another reduction measure can reduce more at this marginal cost. An example can be found at the second step of the cost curve. The first reduction measure that the model selects is a fuel switch of the HFO 0.7% S from the power plant to HFO 0.5% S at a marginal cost of 1 $/kg. By choosing this fuel switch the total SO2 emissions of the refinery can be reduced to 6 617 ton, or 3.8% reduction. At a marginal cost of 1.25 $/kg two reduction measures are selected by the model. The implementation of a Flue Gas Desulphurization (FGD) unit can be found on the combined chimney of the power plant, the atmospheric distillation unit 3 and 4 and on the Fluidized Bed Catalytic Cracker (FCC). Another reduction option selected is a fuel switch from HFO 0.95% S to HFO 0.5% S. The fuel switch chosen at the first reduction step is not chosen, so the power plant still uses the 0.7 % S. An additional reduction of 4 992 ton SO2 can be achieved. The remaining emission level amounts to 1 620 ton SO2. The third step in the cost curve exists of a few minor steps, all representing a fuel switch from HFO 0.95% S to low NOx burners on natural gas. Depending on the burner that could be replaced, the marginal cost varies from 2 to 4 $/kg. The additional SO2 reduction amounts to 463 ton. With a marginal cost between 6 and 7 $/kg the fourth step in the cost curve can be found. This step represents a complete fuel switch to HFO with 0.5% sulphur content. Installations with HFO 0.95% S burners are in step 3 not completely switched to natural gas burners, because when the SO2-reduction is relatively small the marginal cost of reduction will be high. These remaining HFO 0.95% S burners and all HFO 0.7% S burners can switch to HFO 0.5% S while reducing 229 ton SO2. Fuel switching to natural gas and the implementation of a FGD also have an effect on NOx and PM; the bonus effect on NOx and PM emissions is shown on the above graph. It is important to keep these bonus effects in mind, because in case both SO2 and NOx emissions have to be reduced, costs can be reduced by choosing the right reduction techniques.


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5.3.2 Cost curve SO2 without the option to switch to natural gas

SO2 cost curve with bonus effect on PM-emissionswithout natural gas option

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Figure 8: SO2 cost curve without the option to switch to natural gas. There is no bonus

effect on NOx or PM.

The cost curve for SO2 starts at an emission level of 6 881 ton for the year 2005. Emissions can be reduced to 1 319 ton: there is a maximum reduction potential of 81%. Without the option to switch to natural gas, the total reduction potential is about 5.5% less (see Figure 8). The numbers that are shown on the cost curve above point at the most important reduction steps. A detailed survey of the pathway is given below.

1. Fuel switch power plant: 1 955 PJ HFO 0.7% S → HFO 0.5% S Additional reduction: 264 ton SO2 Marginal cost: 1 $/kg

2. Implementation of FGD on power plant. CU3. CU4. FCC Fuel switch: 1 363 PJ HFO 0.95% S → HFO 0.5% S No fuel switch: HFO 0.7% Additional reduction: 4 992 ton SO2 Marginal cost: 1.25 $/kg

3. Complete fuel switch HFO burners: HFO 0.95% and 0.7% S → HFO 0.5% S Additional reduction: 283 ton SO2 Marginal cost: 6-7 $/kg

To interpret this marginal cost curve correctly the following description can be used:


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The model chooses for the first 2 steps of the cost curve the same techniques as for the situation described in 5.3.1. Because the fuel switch to natural gas is not possible in this scenario, the cost curve shows a very steep slope between step 2 and 3. With a very high emission reduction level the switch to HFO with a 0.5% S content has to be implemented completely. The additional reduction is 283 ton SO2, while the marginal cost increases to 6-7 $/kg. Because the reduction measures nor the fuel switch to HFO with lower sulphur content affects the NOx emissions, no effect on NOx emissions can be discovered.

5.4 NOx

Installation Reduction measure

Reduction %

Investment cost [k$]

Operational cost [k$]

All installations Air staging 30 7,2 k$/ MWth 0.12 $/MWh Atmospheric distillation furnace 3, 4

Low NOx-burners 30 2 MWth = 36,6 4 MWth = 45,2 6 MWth = 51,5

/


Fuel switch (HFO → nat.gas

with low NOx burners)

60 (100% SO2)

2 MWth = 36,6 4 MWth = 45,2 6 MWth = 51,5

Difference in fuel price: 0,55 $/GJ


SNCR 55 3 720 $/(1 000 Nm³/hour)

* 175% single installation cost

1 140 $/ton NOx reduced


SCR 90 23 700 $/(1 000 Nm³/hour)

* 175% single installation cost

2 700 $/ton NOx reduced

A more detailed description of the reduction techniques and their costs is given below: Air staging: Air staging technology requires the introduction of combustion air to be separated into primary and secondary flow sections to achieve complete burnout and to encourage as such the formation of N2 rather than NOx. Primary air (70-90%) is mixed with the fuel producing a relatively low temperature, oxygen deficient, fuel-rich zone and therefore moderate amounts of fuel NOx formed. The secondary (10-30%) of the combustion air is injected above the combustion zone through a special wind-box with air-introducing ports and/or nozzles, placed above the burners. The combustion is complete at this increased flame volume and the relatively low-temperature secondary stage limits the production of thermal NOx. The location of the injection ports and mixing of overfire air are critical to maintain efficient combustion. Low NOx burners:


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Low NOx burners are designed to control the fuel and air mix at each burner so larger and more branched flames can be created. Peak flame temperature reduces, which results in less NOx formation. The improved flame structure decreases also the availability of oxygen in the hottest part of the flame, which improves the burner efficiency. In a conventional low NOx burner combustion, reduction and burnout are achieved in three stages. In the initial stage, combustion occurs in a fuel rich, oxygen deficient zone where NOx is formed. This NOx can react with the hydrocarbons formed during the reduced conditions of the second stage. In the third stage internal air staging completes the combustion but may result in additional NOx formation. The latter production can, however, be minimized by completing the combustion in an air lean environment. The invest cost depends on the thermal capacity of the burners which are replaced (see table above). In the enquiry, the number of burners per installation was asked and based on the information from this enquiry the average thermal capacity per burner was calculated. Under th

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