Original Shell E&P Ireland Limited

Corrib House

52 Lower Leeson Street

Noeleen Roche Administration Officer Office of Licensing & Guidance Environmental Protection Agency Regional Inspectorate Iniscara County Cork Ireland

13 June 2005

Our Ref: CciR-L-16-898

Dublin 2

Ireland

Tel +353 1 669 4100

Fax +353 1 669 4101

Dear Ms. Roche

I am writing to respond to the request under Article 11(2)(b)(ii) of the EPA (Licensing Regulations 1994 received by Shell from the EPA on 7 May 2005 for further information in support of our Application with respect to the BeIlanaboy Bridge Gas Terminal.

This response is in compliance with the request from the EPA of 29 April 2005 that such information is provided in two instalments, the first of which is to be supplied by 13 June 2005.

The information provided in this instalment addresses a number of the subjects raised by the EPA in its letter of 7 February 2005. Th ese are listed in the table below. Five copies of the responses are included.

The outstanding queries, including those raised in the EPA letter of 01 March 2005 will be addressed in the second instalment that is due by 8 August 2005.

We would welcome the earliest opportunity to confirm with you the suitability of the responses that we have provided here, especially with a view to ensuring that the second instalment is appropriate for your requirements.

Registered Office.

Corrib House,

52 Lower Leeson Street,

Dubllr 2, Ireland

Registered I” Ireland

Number, 3 16588

VAT Number I E.6336588 P

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June13,2005 Table of Queries Responded to in this Instalment

) B.a 1 Clarify if the lands upon which the activity is situated is now owned bv Shell E&P Ireland , Limited. If this is the case, update section Bl of the application.

D.b Give details of the pressures and temperatures at each process unit operation. D.c Give details of any isolation valves on the gas line from the Corrib field. D.d Clarify the ‘level control’ used in hydrocarbon condensate and aqueous phase removal. Is there a

sumD/tank? D.e Give the mechanism of operation for the inlet filter separator and coalescer. D.h Give details of the compression engines- spark or compression ignition. E.b Having regard to the Large Combustion Plant Directive (Council Directive 2001/80/EC) and

Gothenburg protocol, justify the NOx emission rates presented in Table E.l (iii) for the gas I I turbines and comuression engines.

Es Given that maintenance flaring can occur from depressurising areas prior to the mercury removal bed, quantify the mercury emissions under these conditions.

F.e Describe the management of the produced water treatment system during conditions of maximum hydrocarbon condensate slug arrival at the plant.

F.j Using shading or colour, distinguish areas on the gas plant footprint that are drained to the surface water run-off treatment system (open drains) from those areas drained to the uncontaminated surface water drainage system. List the areas that will be drained to the open drain sump and justify those areas that are not routed to the open drain sump. Describe bunding arrangements for the diesel tank, distillation column and reflux tank. Clarify if the firewater will be fed under gravity to the firewater retention facility. Describe the - .

J.C operation of the system in the event of a fire. Give the capacity of this system. The rainfall allowance is restricted to 6 hours in the firewater calculation whereas EPA guidance recommends 24 hour rainfall event, justi .

Yours sincerely,

Mark Carrigy Terminal Manager

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Bellanaboy Bridge Gas Terminal

IPPC Application. Reg No. 738

Tranche 1 for 13 June 2005

Response presented according to headings in EPA letter of07 February 2005

Section B - General

07/02/05 B.a Clarify if the lands upon which the activity is situated is now owned by Shell E&P Ireland Limited. If this is the case, update section Bl of the application.

Response

Shell E&P Ireland Limited purchased the Bellanaboy Bridge terminal site from Coillte Teoranta on 21 December 2004

The replacement page 31 of 272 of the original application is provided as Attachment 1 overleaf.

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Attachment 1 - Replacement page 31 of 272 of original Application

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IPPC Application Form

(4 m (4

Certified Copies of Certificates of Incorporation are included in Attachment B. 1 Company’s Number in Company’s Registration Office is 3 16588 Registered Office of the Company is at: Corrib House

52 Lower Leeson Street Dublin 2

Name and address of the proprietor(s) of the Land on which the Activity is situated ( if different from applicant named above).

Proprietor’s Name: __~ ! NC& ApplLc~tie

Address:

Name and address of the owner(s) of the building and ancillary plant in which the activity is situated ( if different from applicant named above).

Name: Not Applicable

Address:

IPPC Application 2004 V9 Page 31 of 272

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07/02/05 D.b Give details of the pressures and temperatures at each process unit operation.

Response

See Attachment 3.

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Attachment 3: Drawing L3882-020-11 O-01 35 Rev 01 “Simplified Gas Process Schematic showing Pressures & Temperatures”

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[ 07/02/05 1 DC 1 Give details of any isolation valves on the gas line from the Corrib

Response

Figure D.c-01 show in schematic form isolation valves from the offshore wells up to the Bellanaboy Gas Terminal perimeter.

The individual wells are provided with SSSV (sub-surface safety valves) and main and wing valves on the wellhead “Xmas tree” structures on the sea floor.

Isolation valves are also provided on the production piping linking each well to the subsea manifold, in which the flow from all the wells is commingled into the offshore pipeline to the Bellanaboy Terminal.

All the valves described above are remotely actuated and controlled from the Bellanaboy Gas Terminal Control Room, and are linked into the Terminal ESD system.

After making landfall the offshore pipeline passes through the Beach isolation valve, marking the transition to the onshore pipeline that runs to the Terminal. This valve is locally operated, and is not part of the automatic ESD system.

After passing through the Terminal fence, and before the pipeline enters the first vessel, which is the slug catcher, another isolation valve is located on the line. This is an ESD valve and is therefore remotely actuated and controlled from the Bellanaboy Gas Terminal Control Room.

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- r t’ LAUNCHER

20” $ GAS/LIQUIDS

FROM OFFSHORE

ONSHORE

ilNE

8 SLOT SUBSEA

MANIFOLD

Figure D.c-01 Isolation valves between offshore well and the Terminal fence.

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07/02/05 D.d Clarify the ‘level control’ used in hydrocarbon condensate and aqueous phase removal. Is there a sump/tank?

Response

1. Level Control of hydrocarbon liquids in Sluq Catcher

The slug catcher has been designed to allow processing of slugs to a volume of up to 200 m3/hr. This value has been predicted by various hydraulic studies. This volume will be separated, in slugcatcher fingers, into a hydrocarbon liquid and an aqueous methanol phase. These liquid phases then flow to aqueous methanol and condensate processing facilities for further treatment.

Figure D.d-01 shows the main components of a slug catcher typical of the design that will be constructed for the Bellanaboy Gas Terminal.

GAS OUT (WET)

A WELLFLUIDS IN (MULTIPHASE)

GAS LIQUID SEPARATION

AQUEOUS PHASE OUT

REMOVE SLUGS

CONDENSATE PHASE OUT

METHANOL RECOVERY AND PRODUCED WATER TREATMENT

Figure D.d-01 Bellanaboy Gas Terminal Slug Catcher Schematic

A level control mechanism is employed in the slugcatcher for maintaining required phase levels and interface between the 2 phases for hydrocarbon and aqueous fluids.

The governing principle of operation of the separation is that when liquid horizontal velocity of separated liquid phase is reduced sufficiently then, by virtue of density

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difference between heavier aqueous and lighter hydrocarbon phases, heavier aqueous phase will move in a “downward” direction and lighter hydrocarbon phase will move in an “upward“ direction resulting in phase separation. The lighter condensate stream overflows via a weir into a dedicated condensate compartment and is withdrawn under level control for processing in condensate treatment section. The aqueous phase is withdrawn under level control for downstream intermediate methanol storage, recovery and produced water treatment.

Therefore when the aqueous phase level controller detects an aqueous phase level in the slug catcher “boot”, a flow control valve will open in order to bring the aqueous level to the required setting in the slug catcher boot. The flow control valve will then close and will not open again until the aqueous level reaches a certain level that triggers the level controller to request the flow control valve to open again. The governing principle of operation of this controller is that it will permit aqueous phase to flow (via opening of the control valve) onward to the storage/methanol recovery/ produced water treatment sections only when the slug catcher interface level is above the slug catcher aqueous phase outlet nozzle ancJ a liquid level is detected above this nozzle.

The aqueous phase flows into a methanol recovery unit via the Methanol Flash Drum D- 4001 and the Raw Methanol Storage Tanks T-4001 A/B/C.

The hydrocarbon phase level controller operates in the same manner. The governing principal of operation of this controller is that it will permit condensate to flow (via opening of the control valve) onward to the condensate treatment section only when the slug catcher aqeous-condensate interface level is below the slug catcher condensate outlet nozzle and a liquid level is detected above the condensate nozzle.

During periods of slugging when large quantities of liquid may arrive at the slug catcher through the offshore pipeline, liquid levels of both the hydrocarbon and aqueous phases will rapidly rise. There are two types of slugging potentially relevant to the Corrib field export pipeline and Terminal design:

1) Terrain slugging - where liquid tends to collect in the low points of the pipeline until it is forced forward by the pressure of the gas behind it.

2) Ramp up slugging - accumulation of liquid pockets in a pipeline at transient operating conditions (start up, ramp up, pigging)

Following extensive study work, it has been concluded that the only type of slug expected at the Bellanaboy Gas Terminal are ramp-up slugs. These slugs are controllable in the manner described below.

VVhen a slug arrives in the slug catcher, if the overall high liquid level (HLL) is reached then a HHL level alarm will be activated in the Control Room, the level controller will open the aqueous flow control valve and route all flow to the Raw Methanol storage tanks (T-4001 A/B/C) until interface levels in the slug catcher are restored to normal.

2. Sump /Tank The slug catcher consists of an inlet header, several long tubes (or “fingers”), and a liquid outlet boot. (Ref to drawing D.d-01). During normal operation liquid is retained and its level is controlled in the boot. During ramp up any increase in liquid level is held within the fingers for separation prior to being fed to the Raw Methanol Storage Tanks T- 4001/I/B/C via the Methanol Flash Drum D-4001.

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07/02/05 D.e Give the mechanism of operation for the inlet filter separator and coalescer.

Response

The primary function of the Inlet Filter Separator is to filter the gas stream by removal of the liquids and any entrained particles before the gas is subject to further processing and compression for export. The Inlet Filter Separator is a three phase separator fitted with proprietary vessel internals including inlet guide vanes, a mesh pad (coalescer) and vortex breakers to aid in efficient separation of the three phases of the incoming fluid stream from the slug catcher. The incoming stream consists predominantly of gas with some entrained liquids as an aerosol comprising mainly hydrocarbon condensate, and a methanol-water mix (the aqueous phase).

Liquids are separated from the incoming gas stream and settle out into aqueous and condensate layers separated by a liquid-liquid interface. The lighter condensate stream overflows via a weir into a dedicated condensate compartment and is withdrawn under level control for processing in the condensate treatment section. The aqueous phase is withdrawn under level control for downstream methanol treatment/recovery and produced water treatment.

The governing principle of operation of the separation is that when liquid horizontal velocity of separated liquid phase is reduced sufficiently then, by virtue of density difference between heavier aqueous and lighter hydrocarbon phases, heavier aqueous phase will move in a “downward” direction and lighter hydrocarbon phase will move in an “upward” direction resulting in phase separation.

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07/02/05 D.h Give details of the compression engines- spark or compression ianition.

Response

The following table summarizes all equipment using compression engines and their ignition types.

Emergency Generator G-8802 Diesel Engine Compression Ignition

Main Generator G-8801 A/B/C Gas Engine Spark plug

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07/02/05 E.b Having regard to the Large Combustion Plant Directive (Council Directive 2001/80/EC) and Gothenburg protocol, justify the NO, emission rates presented in Table E.l (iii) for the gas turbines and compression engines.

Response

Annex VI of the Large Combustion Plant Directive (Council Directive 2001/80/EC) provides emissions limit values (ELV) for gas turbines. Article 2 (7) j. para 2 states that “Plants powered by diesel, petrol and gas engines shall not be covered by this Directive”. The gas compression engines at Bellanaboy Gas Terminal are therefore considered not to be affected by this Directive.

The gas turbines at Bellanaboy will be fired by natural gas, constituting at least 80% methane by volume. The turbines will be used to power mechanical drives to compress the product gas for export. They will therefore be subject to the ELV for NOx of 75mg/Nm3. During normal operations the gas turbines are calculated to emit 51 mg/Nm3 NOx.

The Gothenburg protocol forms a part of the Convention on Long-range Transboundary Air Pollution. Within the EU, the National Emission Ceilings Directive sets emission ceilings for 2010 for each Member State for the same 4 pollutants as in the Gothenburg Protocol. NOx is one of these pollutants, and Ireland has committed to an annual emission ceiling of 65000 tonnes for 2010.

Under normal operating conditions, the gas turbines will emit an estimated 36.79 tonnes of NOx annually. This is therefore equivalent to only 0.06% of the Irish national ceiling for NOx emissions by 2010. This can be considered an insignificant contribution in view of the strategic significance of the new gas supply that the Bellanaboy Gas Terminal will provide.

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07/02/05 E.g Given that maintenance flaring can occur from depressurising areas prior to the mercury removal bed, quantify the mercury emissions under these conditions.

Response

The following table shows the anticipated range of activities that would require depressurisation of vessel or pipework, depicted in Figure E.g-01, within the Terminal upstream of the mercury filter N-1001.

Event Frequency

Trip testing of ESD/EDP systems

Trip testing of ESD/EDP systems

Hg Filter N-l 001 absorbent change- out

EDP event

Plant Commissioning (pre-initial Plant start-up) Estimated average of once every 3 years beginning at end of Year 1 of production Once after min. 3 years (based on max throughput 350MMscf/d). Estimated 1 in 10 year event 35,980 :::

Note: The explanation of “Design” and “Expected” cases is given below in the discussion on Mercury Content

Gas inventory

(m3)

35,980 1.22 0.075

35,980 1.22 0.075

871

Hg Emitted (g) Design Expected Case for Hg Case for Hg in gas phase in gas phase (34pg/Nm3) (2.lpg/Nm3)

“Expected” case mercury emissions to flare from this section of the Plant upstream of the mercury filter N-1001 during the first five years of production are therefore calculated as follows:

Production Year Hg Emitted (g) Source / Activity 1 0.075 Commissioning pre-Initial Plant startup 2 4

0.075 0.077

ESD/EDP system trip test ESD/EDP system trip test; Hg filter N-l 001 absorbent changeout

The values provided in the above table are based on the following design assumptions and calculations.

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Inventory

The volume contained in process equipment and pipework located between ESDV-1001 located at terminal inlet and ESDV-1022 located downstream of the mercury filter N- 1001 has been calculated as follows:

Actual System Volume = 245.9 m3 or 35,980 Nm3 Pressure = 139 bar A Temperature = 4 “C Normalised Volume = 35,980 Nm3 Mass of gas = 27,294 kg

I N-1001

D- 1003 I

ri 8 6” P F- 1 OOZA/B

- r-l s 10’. T

F-lOOlA/B

+

Figure E.g-01 Vessels and main gas pipeing upstream of the mercury filter N-1001.

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Mercurv Content in the Gas lnventorv Uostream of the Mercurv Filter N-1001

Incoming wellfluids contain a quantity of mercury that is soluble up to equilibrium quantities in the gas, condensate and aqueous phases. A correlation has been developed by Shell that will predict equilibrium mercury solubility levels in gas &. hydrocarbon condensate systems and can be used to calculate the mercury concentration in liquid hydrocarbon phase. This value in turn is used in combination with various design conditions (flow, inlet mercury content, temperature) to calculate the mercury split between gas and liquid condensate phases and then the mercury content in the relevant gas inventory prior to a blowdown event.

The table below summarizes the finding of this correlation tabulated for range of summer & winter Bellanboy arrival gas conditions

emp Solubility of Hg in HC Liquid

*c gmol Hg/kg I-ICI g/kg HC( m/kg HC

0 2.040E-06 0.000409 409

4 2.653E-06 0.000532 532

10 3.882E-06 0.000779 779

15 5.266E-06 0.001056 1,056

The Table below summarise the relevant mercury design limits as per Basis of Design document. Mercury Design Data

Mercury arriving in Wellfluid (sample), normal

Mercury in Formation Water (sample), min

Max Mercury concentration

The Table below summarises the cases looked at, the total mercury coming into terminal from offshore wells, how the mercury will be split between the gas and hydrocarbon phases and finally the calculated mercury content of the enclosed volume between the ESDVs.

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Assumptions

Note:

of 2.1 pg/Nm3.

Design Case = Worst Case when mercury content of arrival gas is 34 pug/m3 Hg, with all Hg assumed to be in gas phase. The mercury content is very conservative.

Case 1 = No condensate case = All reservoir mercury is present in incoming wellfluids Gas Phase as no condensate being produced. This is a highly unlikely case.

Case 2 = Design Condensate Case = Condensate produced at 0.5 bbl/MMscf with mercury content in condensate phase in equilibrium with that of gas phase.

Shell Correlation

Ln (4 = 5.105848 - (4970.898/T)

; = solubility of elemental Hg in the hydrocarbon liquid (gram mole Hg / kg HC) = absolute temperature (deg K)

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07/02/05 F.e Describe the management of the produced water treatment system

I I thAIant. during conditions of maximum hydrocarbon condensate slug arrival at

Response

The management of the Produced Water Treatment Plant will not be affected during conditions of maximum hydrocarbon slug arrival at the plant. During normal operation, the condensate production rate is low and the condensate is routed to the condensate handling system. The condensate handling system is designed to handle normal operation and slugging operation.

When a slug arrives in the slug catcher, if the overall high liquid level (HLL) is reached then a HHL level alarm will be activated in the Control Room, the level controller will open the aqueous flow control valve and route all flow to the Methanol flash drum until interface levels in the slug catcher are restored to normal. All liquids, both hydrocarbon condensate and the aqueous phase will routed to the T-4001 tanks.

The T-4001 tanks also function as buffers in the feed to the Produced Water Treatment Plant. The feed rate from these tanks to the Methanol Still and from there into the Produced Water Treatment Plant is set by the Control Room Operator and is therefore maintained within design limits.

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07/02/05 1 F,j 1 Using shading or colour, distinguish areas on the gas plant footprint that are drained to the surface-water run-off treatment-system (open drains) from those areas drained to the uncontaminated surface water drainage system. List the areas that will be drained to the open drain sump and justify those areas that are not routed to the open drain sump.

Response

Refer to diagrams in Attachment 4

The areas on the gas plant footprint that are drained to the surface water run-off treatment system (open drains) are highlighted in light grey dotted shading and hatching on the attached drawings. The grey dotted shading identifies paved kerbed areas on the footprint that go to the open drain system. The hatched areas on the plot identifies the paved areas where drainage is controlled to the open drain system. The open drains system captures all areas where potential spills could occur. The rest of the footprint (left un-shaded) drains to the uncontaminated surface water drainage system.

The below listed areas have open drains which drain to the open drain sump. These are gravity drains.

1. Slug catcher area (including tanker unloading area) 2. Process area 3. Waste storage area 4. Access road to administration building

The following areas also drain to the open drains sump but drainage is controlled and only released by unlocking a normally closed valve:

Condensate Storage Tanks T-3001 A/B Off-spec Condensate Storage Tank T-3002 Raw Methanol Storage Tanks T-4001 A/B/C Product Methanol Storage Tanks T-4002 A/B Methanol Still Acid Wash Tank T-4003 Heating Medium Storage Tank T-5001 Diesel Storage Tank T-8803 Firewater retention pond

Rainwater drainage from all other areas is routed via the piped perimeter (surface water) drainage system via the emergency holding tank to the settlement ponds. The drainage comprises rainfall that falls on the roads and non-paved areas. Some water will fall on plot building roofs (excluding the compressor house which drains to the open water drains system, and the administration building area) and these will also be served by the perimeter drains. These areas are considered very low risk to being subject to accidental contamination, as there are no process or utility sources for hydrocarbon or chemical leaks or spills to directly enter these drained areas. In the highly unlikely circumstance of a pollution event affecting the perimeter surface water drains, the outlet of the emergency holding tank would be closed and the contaminated water would be pumped back to the Terminal’s oily water treatment system for clean-up.

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Attachment 4: Drawings L3882-050-11 O-SKI 5-SHTOl & L3882-050-l lo-SK1 5-SHT02 “Catchment Area Plan, Sheets 1 & 2”

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07/02/05 J.a Describe bunding arrangements for the diesel tank, distillation column and reflux tank.

Response

The Diesel Tank T-8803 has its own bund. The bund has been sized as 8.4m width x 8.4m length x 1.65m bund height. The bund has its own sump chamber for collection of spillages which will be removed by a gully sucker. The capacity of the bund is 100.9 m3, compared to the normal operating volume in the tank of 71.6 m3.

The distillation column, C-4001 Methanol Still, and the Methanol Reflux Drum D-4002 are not storage tanks and therefore do not require to sit inside a bunded area. They are however located in the Process areas of the plant which is paved and has an upstand around the paved area. The paved area is drained by the Open Drains, which feed into the Open Drains Sump. Drainage from this area is therefore treated prior to discharge in the Terminal’s Primary Surface Water Treatment Package. Any liquid spills that could occur during maintenance activities on the C-4001 or D-4002 and which are not caught locally in drip drays would therefore be drained to this treatment system.

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07/02/05 J.b Clarify if the firewater will be fed under gravity to the firewater retention facility. Describe the operation of the system in the event of a fire. Give the capacity of this system.

Response

In the unlikely event of a fire on the site that necessitates fire fighting, the firewater run- off causes the level in the Open Drains Sump (T-8301) to rise significantly above normal. Should this occur, the excess water is pumped out to the Contaminated Firewater Pond (T-8306). The pump is connected to the Emergency Generator to ensure its availability.

Report Document No. L3847-000-I IO-0042 “Contaminated Firewater Retention Report” provides details of the capacity of the firewater system and its design basis.

The Report is attached to this response as Attachment 5.

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07/02/05 J.c The rainfall allowance is restricted to 6 hours in the firewater calculation whereas EPA guidance recommends 24 hour rainfall event, justify.

Response

Report Document No. L3847-000-l lo-0042 “Contaminated Firewater Retention Report” provides full responses to these queries.

The Report is attached to this response as Attachment 5.

The Environmental Protection Agency Guidance Note EPA LCIO recommendation for designing for a 24-hour rainfall event has been adhered to in the measures described in the attached Report L3847-000-11 O-0042.

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Attachment 5: Repot-t Document No. L3847-000-11 O-0042 ‘Contaminated Firewater Retention Report”

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CORRib

I I

ASI Project L3847 Enterprise Contract No. 101.24.15

OCUMENT TITLE:

DOCUMENT NUMBER: L3847-000-11 O-0042

SHEET NO.:

co REPORT

1 of7

EElL DOCUMENT NUMBER :

l-his document is confidential and is the exclusive property of ASI JV. No unauthorized use, copy or disclosure of the document is to be made. It is to be returned whenever required.. Manufacture and zonstruction are to be carried out strictly in accordance with the requirements of this document. No :hanges are to be made without the prior agreement of the Project Manager.

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CONTENTS

1 .O BNTRODUCTION .............................................................................................. 3

2.0 DESIGN CASE FIRE SCENARIO .................................................................... 3

3.0 CONTAMINATED FIREWATER ...................................................................... 4

4.0 FIREWATER DEMANDS ................................................................................. 4

5.0 RAINWATER ................................................................................................... 4

6.0 REQUIRED PUMP CAPACITY ........................................................................ 5

7.0 REQUIRED RETENTION VOLUME OF T-8306 ............................................... hi

8.0 PUMPING REQUIREMENTS ........................................................................... 6

TAMINATED FIRE ...................................... 7

............................................ ERROR! BOOKMARK NOT DEFINED.

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-IAl INTRODUCTION

In the event of fire, firewater may become contaminated with hydrocarbon products and any material used to fight the fire such as AFFF. To protect the environment in view of the uncertain level of contamination of the used firewater, the operating philosophy will be to collect this water initially in the Open Drains Sump T-8301 and then to pump to the proposed new Contaminated Firewater Pond T-8306 using the Firewater Transfer Pump P- 8304. This sump will be located West of the Flare Stack outside the sterile area.

The purpose of this note is to define the controlling fire scenario and corresponding firewater demands to enable P-8304 and T-8306 to be sized and to prevent any possibility of T-8301 and/or T-8306 overflowing during an emergency leading to contamination of the surface water system.

2.0 DESIGN CASE FIRE SCENARIO

The following assumptions are made in this assessment:

0 The contaminated firewater to be retained follows the draft Environmental Protection Agency guidance note and is based on the maximum water likely to be used in fighting a fire. The proposed retention requirements assume a maximum fire emergency of six hours at the controlling deluge rate of 1200 m3/h, which corresponds to the capacity of the firewater pond provided at the Terminal .

0 Based on EPA guidance, the maximum volume of rainfall should be based on at least 50 mm of rainfall or if significantly different the 20 year, 24 hour rainfall event. In this report, a maximum daily rainfall of 67.8 mm over 24 hours equivalent to 2.828 mm/h has been used based on the General Information Specification L3847-01 O-l 1 O-0001 Rev Al which is more stringent than EPA.

8D Firewater deluge rate 1200 m3/h over 2, 4 or 6 hours.

@3 Controlling firewater scenario of 1200 m3/h is based on a condensate tank fire.

@a Condensate bund capacity is 899 m3.

B Paved areas 13,000 m2, Condensate bund area 1185 m’.

a Firewater Pond T-8701. Capacity 7,200 m3.

0 Both T-8301 and T-8306 will be at low level at start of event. This should be covered by operational procedures.

The design or extreme fire case scenario is based on a condensate tank fire with simultaneous deluge on the affected tank and adjacent tanks, the latter requirement to prevent escalation. It is assumed that the duration of the fire would last six hours at the peak demand . The deluge water application rate

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is based on the ‘NFPA 15’ recommended rate of 10.2 I/min/m2 for storage tanks. Also in this scenario it is assumed that three monitors would be utilised continuously during the fire. This design case scenario gives a peak firewater demand of 1200 m3/hr as detailed in Table 4 plus for comparative purposes the water demand for a product methanol tank and process area fires.

This peak demand is supplied from four 50% diesel driven fire pumps each sized for 600 m3/h. Normally two would operate with one on standby and one under maintenance. Also there are two electrically driven jockey pumps each of 60 m3/h capacity being 5% of fire pump capacity and sufficient for two hydrants.

3.0 CONTAMINATED FIREWATER

Contaminated firewater from the various collection points is routed to the Open Drains Sump T-8301 via the open drains collection system. In the event of a confirmed fire, the strategy would be to automatically start P-8304 to ensure T-8301 is kept at the lowest possible level to prevent any possibility of used firewater over-flowing to the surface water system. P- 8304 should be on the emergency board and hence available throughout an emergency.

4.0 FIREWATER DEMANDS

The firewater demands for fires in the bulk storage area and the process area are given in Table 4.

Firewater Demand

Table 4 Fire Scenario

Condensate Tank Product Methanol Process Area Fire Tank Fire Fire

m31h m3lh m3/h

Deluge 818.7 430.0 Foam 38.2 26.9 Monitors 342 (3 off) 342 (3 off) 456 (4 off)

Total demand 1200 800 456

5.0

A condensate tank fire corresponds to the maximum firewater demand of 1200 mYhr. RAINWATER

The rainwater handling capacity given in Table 5 is based on the maximum daily rainfall of 67.8 mm over 24 hours given in the General Information Specification (L3847-01 O-l 1 O-0001 Rev A Page 4).

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Table 5

Area m2

Rainfall m3/h (2.825 mm)

Paved Areas

13,000

36.7

Condensate Tanks Bund 1185

3.35

Total

14,185

40.05 m3/h

6.0 REQUIRED PUMP CAPACITY

The required size of pump P-8304 to prevent the Open Drain Sump T-8301 overflowing for fire scenarios lasting 2, 4 and 6 hours respectively are given in Table 6.

Table 6

Duration of Fire (h) In flow to T-8301 from:

Paved areas Condensate Bund * Total (m3)

Required pump rate ( m3/h)

2 4 6

73.4 146.8 220.2 220.2 1504 3911 6318 5618

1577 4058 6538 5838 280 870 1010 885

The last column of Table 6 gives the required pump rate when taking into account allowances of 200 m3 and 500 m3 for open drains hold up and evaporation losses respectively over the six hour event.

In all cases the condensate bund will overflow after 0.75 h from initiation of deluge.

*Values for inflow from condensate bund derived by: (Fire duration - Bund overflow duration) x (Deluge application rate + Rainfall rate).

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7.0 REQUIRED RETENTION VOLUME OF T-8306

The required retention volume of the Contaminated Firewater Sump Tank T- 8306 should cater for the assumed fire-fighting scenarios of 2, 4 and 6 hours at peak capacity and the assumed maximum daily rainfall of 67.8 mm over 24 hours.

Table 7

Overall event duration (h) 2 4 6 Pumping time (h) 1.25 3.25 5.25 5.25 Total firewater (m3) 1500 3900 6300 5800 Total rainwater (m3) 77.6 157.7 237.8 237.8

1577 4058 6538 6038 Less retained capacity of T- 8301 (m3) Less holdup capacity in Drains Systems, (m3)

1200 1200 1200 1200

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Rainwater falling in T-8306 (m3) 16 32 47 47

Hence required volume of T- 8306 (m3)

393 2890 5385 4685

The last column in Table 7 gives the required volume of the Contaminated Firewater Pond taking into account evaporation losses of 500 m3 , estimated by EEIL, and an open drains hold up volume of 200 m30ver six hour event.

8.0 PUMPING REQUIREMENTS

To prevent the Open Drains Sump T-8301 overflowing in any circumstances, the following pump capacities should be installed in T-8301 (see Table 8.1). The effective head difference between P-8304 and T-8306 is estimated to be 16 metres including frictional losses and an efficiency of 70% is assumed.

Table 8

1 General event duration 1 2 4 6 W-s) Pumping Capacity 280 870 1010 885 (m3/hr) Line Size 8” 12” 14” 1 2” T-8301 to T-8306 Pumping p ower kw 13 47

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9.0

During normal operation, the Open Drains Sump T-8301 will be kept at low level by intermittent use of the Tilted Plate Separator Feed Pumps P-8306 A/B, i.e. a capacity of 1200 m3 will always be available. In the event of a confirmed fire, the proposed Firewater Transfer Pump P-8304 will take over and be used to prevent T-8301 overflowing. The size of P-8304 depends on the duration of the time the condensate tank firewater deluge system has to be used. The overall duration is limited by the capacity of the firewater pond T-8701 which is 7200 m3, i.e. 6 hours at 1200 m3/hr.

The Contaminated Firewater Pond T-8306 has sufficient capacity to contain any contaminated firewater pumped from T-8301. At the end of an emergency, contaminated firewater will be distributed between the condensate bund, T-8301 and T-8306 as indicated in Table 7.

Following an emergency, the strategy will be to empty the affected bund by gravity to T-8301 and pump forward to T-8306 using P-8304. The disposal route of the contents of T-8306 will depend on the degree of contamination, i.e. on site treatment and return to firewater pond or disposal offsite. Based on the capacity of the water treatment plant (2 x 30 m3/hr), it is estimated that the contaminated fire water could be treated in 50, 90 and 130 hrs for a fire event lasting 2, 4 and 6 hours respectively.

10.0 SUMMARY

The Firewater Transfer Pump P-8304 will have a capacity of 1000 m3/h and the Contaminated Firewater Pond T-8306 a capacity of 5000 m3 , both figures including a 10% allowance.

Additionally, P-8304 will be on the Emergency Board so that it is always available.

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