LNG Terminal Design

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BRADWOOD LANDING TERMINAL

Resource Report 13

Engineering and Design Material

SUBMITTED BY NORTHERN STAR NATURAL GAS LLC

Rev 2

16th May 2006


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RESOURCE REPORT 13

ADDITIONAL INFORMATION RELATED TO LNG PLANTS

CONTENTS

13 INTRODUCTION 13-1

13.1 SITE PLAN 13-113.1.1 Siting 13-213.1.2 Thermal Radiation Protection 13-2

13.1.3 Flammable Vapour Dispersion Protection 13-213.1.4 Seismic Design Investigation and Design Forces 13-3

13.1.5 Flooding 13-5

13.1.6 Soil Characteristics 13-5

13.1.7 Wind Forces 13-613.1.8 Other Severe and Natural Conditions 13-713.1.9 Adjacent Activities 13-7

13.1.10 Separation of Facilities 13-813.1.11 Site Development 13-8

13.1.11.1 Grading and Excavation 13-8

13.1.11.2 LNG Tank Impoundment 13-913.1.11.3 Drainage and Storm Water Run-off 13-9

13.1.11.4 Spill Containment 13-1013.1.11.5 Foundations 13-10

13.1.11.6 Roads 13-11

13.1.11.7 Site Surface Treatment 13-11

13.2 FIRE PROTECTION SYSTEM 13-1213.2.1 Firewater System 13-12

13.2.1.1 Firewater System Components 13-1213.2.1.2 Firewater Piping 13-14

13.2.2 Dry Chemical Extinguishers 13-1413.2.3 High Expansion Foam System 13-14

13.2.4 Portable Fire Extinguishers 13-15

13.2.5 Fireproofing and Siren 13-15


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13.3 HAZARD DETECTION SYSTEM 13-1513.3.1 General 13-15

13.3.2 Monitoring Equipment 13-17

13.3.2.1 Gas Detectors 13-1713.3.2.2 Low Temperature Detectors 13-17

13.3.3 Fire Detectors 13-17

13.3.3.1 General 13-1713.3.3.2 Smoke Detectors 13-1813.3.3.3 High Temperature Detectors 13-18

13.3.3.4 Visual Monitoring 13-18

13.3.4 Fire and Hazardous Gas Detection System 13-18

13.4 SPILL CONTAINMENT SYSTEM 13-1913.4.1 Spill Containment Tanks 13-19

13.4.2 Spill Containment Tank and Vaporizer Area 13-1913.4.3 Spill Containment Jetty Area 13-20

13.4.4 Spill Containment General 13-20

13.5 SHUT-OFF VALVES 13-20

13.6 DESIGN PLANNING 13-21

13.7 MAJOR PROCESS COMPONENTS 13-2213.7.1 Marine Facilities 13-2213.7.1.1 Carrier Unloading Arms 13-25

13.7.2 LNG Un-loading Operation 13-26

13.7.2.1 Vapour Return Blowers Knockout Drum 13-2713.7.2.2 BOG and Vapour Handling System 13-27

13.7.2.3 Boil-off Gas Compressor 13-2913.7.2.4 BOG Condenser 13-30

13.7.3 LNG Sendout System 13-31

13.7.3.1 In-tank LNG Pumps 13-3113.7.3.2 Sendout Pumps 13-32

13.7.3.3 Submerged Combustion Vaporizers 13-3213.7.3.4 Operation and Control 13-33

13.7.4 Vent 13-3413.7.5 Buildings and Piping Structures 13-34

13.7.5.1 New Buildings Scope of Work 13-34

13.7.5.2 Structural Piperacks 13-37

13.8 LNG STORAGE TANKS 13-3713.8.1 General 13-37

13.8.2 Tank Foundation 13-3913.8.3 Outer Tank 13-39

13.8.4 Inner Tank 13-40

13.8.5 Seismic Loads on Inner and Outer Tanks 13-4013.8.6 Wind Loads on Outer Tank 13-41

13.8.7 Insulation System 13-41


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13.8.8 Tank Instrumentation 13-4213.8.8.1 Cooldown Sensors 13-42

13.8.8.2 Temperature Sensors 13-43

13.8.8.3 Liquid Level Instruments 13-4313.8.8.4 Tank Gauging, Density and Overfill Protection Requirements 13-43

13.8.8.5 Density Monitoring 13-43

13.8.8.6 Liquid Temperature Measurements 13-4413.8.8.7 Pressure & Vacuum Relief Systems 13-4413.8.8.8 Settlement Monitoring 13-44

13.8.8.9 Inner and Outer Tank Relative Movement Indicators 13-44

13.8.9 Fittings, Accessories, Tank Piping 13-4413.8.9.1 Roof Platforms 13-44

13.8.9.2 Cranes / Hoists 13-4513.8.9.3 Intank Pump Columns 13-45

13.8.9.4 Tank Internal Piping 13-4513.8.9.5 Tank External Piping 13-45

13.8.10 Stairways and Platforms 13-46

13.8.10.1 Access to Platform and Roof 13-4613.8.10.2 Internal Tank Ladder 13-46

13.8.10.3 Walkways and Handrails 13-4613.8.11 Cryogenic Spill Protection 13-47

13.8.12 Painting 13-47

13.8.13 Tank Lighting and Convenience Receptacles 13-4713.8.14 Electrical Grounding 13-47

13.8.15 Welding 13-4713.8.16 Testing and Inspection 13-48

13.8.16.1 Alloy Verification 13-4813.8.16.2 Radiography 13-48

13.8.16.3 Liquid Penetrant Examination 13-4813.8.16.4 Vacuum Box Testing 13-4813.8.16.5 Hydrotesting of Inner Tank 13-49

13.8.16.6 Pressure and Vacuum Testing 13-4913.8.17 Procedures for Monitoring and Remediation of Stratification 13-49

13.9 PIPING AND INSTRUMENTATION 13-4913.9.1 Piping and Instrumentation Drawings 13-49

13.9.2 Process Control 13-4913.9.2.1 Distributed Control System 13-50

13.9.2.2 Control Communication Network 13-52

13.9.3 Emergency Shutdown System 13-5313.9.4 Analysis Instrumentation 13-54

13.9.4.1 Gas Chromatograph 13-54

13.10 ELECTRICAL SYSTEMS 13-5413.10.1 General 13-54

13.10.2 Area Classification 13-5513.10.3 Voltage Levels 13-55

13.10.4 Utility and Generator Power Supply 13-55


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13.10.5 Switchgear and Motor Control Centres 13-5613.10.6 Load Shedding 13-56

13.10.7 Wiring 13-57

13.10.8 Electric Motors 13-5713.10.9 Exterior Lighting 13-57

13.10.10 Grounding 13-57

13.10.11 Lightning Protection 13-5813.10.12 Uninterruptible Power Supply 13-58

13.11 DESIGN CODES AND STANDARDS 13-59

13.12 PERMITS AND APPROVALS 13-59

13.13 REGULATORY COMPLIANCE 13-5913.13.1 49 CFR Part 193 13-5913.13.2 NFPA 59A 13-59

13.13.3 Additional Responses to 49 CFR Part 193 13-59

13.13.3.1 193.2051 Scope 13-5913.13.3.2 193.2199 Records 13-59

13.13.3.3 193.2155 Structural Requirements 13-6013.13.3.4 193.2187 Non-metallic Membrane Liner 13-60

13.13.3.5 193.2301 Scope 13-60

13.13.3.6 193.2303 Construction Acceptance 13-6013.13.3.7 193.2304 Corrosion Control Overview 13-60

13.13.3.8 193.2321 Non-destructive Tests 13-6013.13.3.9 193.2401 Scope 13-60

13.13.3.10 Sub-part F Operations 13-6113.13.3.11 193.2511 Personnel Safety 13-61

13.13.3.12 193.2521 Operating Records 13-6113.13.3.13 Sub-part G Maintenance 13-6113.13.3.14 193.2619 Control Systems 13-62

13.13.3.15 193.2639 Maintenance Records 13-6213.13.3.16 Sub-part H Personnel Qualifications and Training 13-62

13.13.3.17 Sub-part I Fire Protection 13-6213.13.3.18 Sub-part J Security 13-62

13.13.4 Additional Responses to NFPA 59A 13-63

13.13.4.1 2-4 Designer and Fabricator Competence 13-6313.13.4.2 2-5 Soil Protection for Cyrogenic Equipment 13-63

13.13.4.3 2-6 Falling Ice and Snow 13-63

13.13.4.4 2-7 Concrete Materials 13-6313.13.4.5 3-1 Process Systems General 13-63

13.13.4.6 3-2 Pumps and Compressors 13-6413.13.4.7 3-3 Flammable Refrigerant and Flammable Liquid Storage 13-64

13.13.4.8 3-4 Process Equipment 13-6413.13.4.9 4-1 Stationary LNG Storage Containers General 13-64

13.13.4.10 4-2 Metal Containers 13-6413.13.4.11 4-3 Concrete Containers 13-64

13.13.4.12 4-4 Marking of LNG Containers 13-64


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13.13.4.13 4-6 Container Purging Procedures 13-6513.13.4.14 4-8 Relief Devices 13-65

13.13.4.15 5-6 Products of Combustion 13-65

13.13.4.16 6-1 Piping Systems and Components General 13-6513.13.4.17 6-2 Materials of Construction 13-65

13.13.4.18 6-3 Installation 13-66

13.13.4.19 6-4 Pipe Supports 13-6613.13.4.20 6-5 Piping Identification 13-6613.13.4.21 6-6 Inspection and Testing of Piping 13-66

13.13.4.22 6-7 Purging of Piping Systems 13-66

13.13.4.23 6-8 Safety and Relief Valves 13-6713.13.4.24 6-9 Corrosion Control 13-67

13.13.4.25 7-7 Electrical Grounding and Bonding 13-6713.13.4.26 8-2 Piping System 13-67

13.13.4.27 8-3 Pump and Compressor Control 13-6813.13.4.28 8-4 Marine Shipping and Receiving 13-68

13.13.4.29 8-5 Tank Vehicle and Tank Car Loading and Unloading Facilities 13-68

13.13.4.30 8-9 Communications and Lighting 13-6813.13.4.31 9-7 Maintenance of Fire Protection Equipment 13-68

13.13.4.32 9-9 Personnel Safety 13-6813.13.4.33 9-10 Other Operations 13-68

13.13.4.34 4-7 Cooldown Procedures 13-69

13.13.4.35 9-7 Ignition Source Control 13-69

13.14 SEISMIC REVIEW 13-69


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TABLES

Table 13.3-1 ESD Isolation Points

Table 13.3-2 Gas DetectorsTable 13.3-3 Fire Detectors (UV/IR)

Table 13.3-4 Low Temperature Sensors

Table 13.13-1 Index to Terminal Code Compliance 49 CFR 193 (10-1-2000

Edition)

Table 13.13-2 Index to Terminal Code Compliance NFPA 59A (2001 Edition)

APPENDICES

Appendix A13 Drawings and Reports

Appendix B13 Specifications

Appendix C13 Manufacturer Data

Appendix D13 Geotechnical Studies

Appendix E13 Permits, Approvals, and Regulatory Requirements

Appendix F13 Shipping Studies


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RESOURCE REPORT 13

ADDITIONAL INFORMATION RELATED TO LNG PLANTS

13 INTRODUCTION

This resource report, required for construction of proposed new liquefied natural gas(LNG) facilities, provides engineering and design information on the Northern Star

Natural Gas LLC (NSNG) proposed LNG Terminal Project (Project). The overviewinformation provided in this resource report is based on the current design of the

Project. The detailed engineering of each aspect of the Project will be addressed in

the detailed design phase of the Project. In order to provide a safe and compliantdesign, the proposed LNG facilities will comply with the provisions of Title 49 of the

Code of Federal Regulations (CFR) Part 193 and National Fire Protection Association(NFPA) 59A. The Project will import, store and vaporize (LNG) for supply to U.S.

natural gas markets. The Project will be located in Bradwood, Clatsop County,Oregon, United States of America.

The terminal will be designed so that it can be expanded to a daily sendout rate of

1.5 bscfd of pipeline natural gas with three LNG storage tanks, however, NSNG will

initially build sendout capacity for 1.0 bscfd and two LNG storage tanks. Theadditional 0.5 bscfd of sendout capacity and third storage tank will be built to satisfy

market demand. A pipeline system will be built to transport 1.5 bscfd of natural gasfrom Bradwood Landing to the Williams Northwest Pipeline. A separate Section 7(c)

application for the pipeline is being filed concurrently under separate cover.

13.1 SITE PLAN

The Project will include the construction of new dock facilities, associated piping,

LNG storage and sendout equipment. A single LNG carrier berth will be located in anew marine basin. A maneuvering area to turn and move the LNG carriers into the

berth will be created. The new marine basin will be connected to the Columbia River

Channel, but oriented so that LNG carriers will be well away from other ship traffic,and to facilitate emergency egress. The new marine basin and berth will be able to

accommodate both currently operating LNG carriers over 100,000 cubic meters (m3)and future carriers, which will be capable of holding up to 200,000 m3 of LNG.

Bradwood Landing will have the capability of unloading in the order of 180 carriersper year.

The LNG from the carriers will be pumped by ship pumps into two full containment,

top entry, nominal 160,000 m3 (1,006,400 barrel) LNG storage tanks. Space has beenallocated for a third LNG tank of identical size for future expansion to 1.5 bcfd


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sendout capacity. The LNG will then be pumped from the tanks up to pipeline

pressure, vaporized, and sent to the existing natural gas pipeline systems.

The major features of the Project are shown on a computer generated site layout,

which is included as drawing W00031-011-CI-LO-002 in Appendix A13.

13.1.1 Siting

The considerations prescribed in 49 CFR Part 193 Subpart B and NFPA 59A, together

with other criteria, have been used for selecting the site of the Project. Compliancewith these codes and rules reasonably assures the public safety in the vicinity of the

Project, provides design contingency, and provides adequate access in the event of anemergency situation. Drawings referenced in this section are included in Appendix

A13. Factors considered during site selection and design, as listed in 49 CFR 193Subpart B and NFPA 59A include:

Thermal radiation protection; Flammable vapor gas dispersion protection; Seismic design investigation and design forces; Flooding; Soils characteristics; Wind forces; Other severe and natural conditions; Adjacent activities; Separation of facilities; Site development.

13.1.2 Thermal Radiation Protection

Calculations have been made, by Whessoe Oil and Gas Limited, in relation to thermalradiation (W00031-000-PR-DR-001 Vapor Dispersion and Thermal Radiation Report).

The results are presented in Resource Report 11.

13.1.3 Flammable Vapor Dispersion Protection

The calculations for the vapor dispersion zones (W00031-000-PR-DR-001 Vapor

Dispersion and Thermal Radiation Report) have been performed by Whessoe Oil andGas Limited. The results are presented in Resource Report 11.


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13.1.4 Seismic Design Investigation and Design Forces

Site specific seismic response spectra have been determined by URS Consulting, Inc.for the Project per the requirements of NFPA 59A and 49 CFR Part 193. The

numerical and graphical seismic data are included in the report, Draft Report,

Seismic Hazard Analysis for LNG Import Terminal, Bradwood Oregon included inAppendix D13.

The summary conclusions of this report are as follows:

Work Scope

Seismic hazard analyses were performed for a proposed Liquefied Natural Gas (LNG)

Import Terminal at Bradwood, Oregon. The analysis initially consisted of thecollection and review of available information on the geology, tectonics, seismicity,

and tsunami potential of the region. The information was used to (1) determine thepresence and character of any potentially active faults and the potential for surfacerupture at the terminal site, (2) develop a regional seismic source model for

probabilistic seismic hazard analysis (PSHA) and determine seismic hazard analysis(DSHA) of the LNG site, and (3) assess the tsunami and seiche hazard at the site. The

results of the PSHA and DSHA were used to obtain peak ground accelerations (PGA)

and response spectra for the Operating Basis Earthquake (OBE) and Safe ShutdownEarthquake (SSE) for the LNG Terminal per the criteria in the 2001 Edition of the

National Fire Protection Association (NFPA) Standard, NFPA 59A.

PGA values and response spectra were also determined for the design of otherstructures comprising the Terminal per State of Oregon requirements in the 2004

Oregon Structural Speciality Code.

The contents of this report and the companion URS (2005) Geotechnical Report

together satisfy the relevant requirements in State of Oregon Standards OAR 345-021-0010 (Site Characterisation Exhibits H and I), OAR 345-022-0020 (Structural

Standard), and OAR 345-022-0022 (Soil Protection). These reports also comply withthe State of Oregon Open-File Reports 0-00-04, Guidelines for Engineering Geologic

Reports and Site-Specific Seismic Hazard Reports.

Local Fault Evaluations

No evidence of active faults were found within 1 mile (1.6 km) of the site based on (1)

a review of relevant literature, (2) examination of aerial photographs, (3) review of

boring logs and cross sections, and (4) site reconnaissance.


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Tsunami waves may enter the Columbia River from distant circum-Pacific

earthquakes, local offshore earthquakes, or submarine landslides in the adjacentPacific Ocean offshore area. However, the historical data and estimates of run-up

wave height along the southern bank of the Columbia River indicate a low potential

for inundation at the site, which is approximately 30.5ft Columbia River Datum (CRD).

Although seiches have been observed in the Pacific Northwest during the 1949 Queen

Charlotte Islands, Canada, and the 1964 and 2002 Alaskan earthquake of

approximately moment magnitude M8 or greater, seiches have not been reported inthe Columbia River, except in the reservoir directly behind the Grand Coulee Dam

farther upstream. In our judgement, the seiche potential in this river near the site isminimal, and the potential for damage from any seiche that might occur is considered

remote.

13.1.5 Flooding

Federal Emergency Management Agency (FEMA) Q3 Flood Map indicates that the

Bradwood Site is an area that is inundated by 100 year flooding, for which no BFEs(Base Flood Elevation) have been determined. Processing areas will be at an elevation

of 30.5 ft above the Columbia River Datum (CRD). The processing area and the tanksare also surrounded by a tertiary bund that has an elevation of 35.5 ft above CRD.

13.1.6 Soil CharacteristicsAn initial geotechnical investigation of the Bradwood Landing site was conducted by

URS Consulting, Inc. The results of this investigation are included in the report, DraftPreliminary Geotechnical Report, Proposed LNG Import Terminal Development,

Bradwood Oregon Included in Appendix D13

The summary conclusions of this report are as follows:

A Geotechnical investigation was performed to develop design recommendations forthe proposed Liquefied Natural Gas (LNG) Import in Bradwood, Oregon. The

development will include two 75-meter (246-foot) diameter LNG storage tanks withinfrastructure for a possible future third tank, and other major structures and support

facilities. The project site is bounded by the Columbia River to the east and north, byhigh bluffs of Columbia River Basalt to the south, and by the historical drainage of

Hunt Creek to the west.

Following a review of historic site development through aerial photography, URS

performed a preliminary site investigation including 7 exploratory borings, 4 cone


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penetration tests, and seismic-velocity testing. The installation of driven wood piles

along the northeast shoreline in the early 1960s resulted in deposition that currently

forms the portion of the site outboard of the log pond at the Bradwood site. Most ofthe project site has existed in a similar geometry and topography since the earliest

aerial photographs from 1929. The present ground surface of the site is mantled bystockpiles of poorly grade dredge sands placed by the US Army Corps of Engineers

during historical dredging of the Columbia River Channel.

Subsurface conditions generally consist of softer compressible soils that represent the

larger historic log pond areas and surficial fills used in site development. These softfills mantle an upper alluvial sand unit consisting of relatively uniform, medium to

find grained, poorly grained sand and ranging in depth up to 86 feet below the groundsurface (bgs). The upper sand unit is uniformly underlain by up to 59 feet of soft,

compressible estuarine silts and clays (from approximately 85- to 135- feet bgs). Thispackage of silts and clays is in turn underlain across the majority of the site by a

lower sand unit consisting of a medium dense to dense sands. These materials are

underlain the weathered surface of the Columbia River Basalt bedrock at depths

ranging from 113 to 181 feet across the site.

The site liquefaction potential was evaluated for an Operating Basis Earthquake (OBE)

and a Safe Shutdown Earthquake (SSE); conservatively postulated horizontal peak

ground accelerations ranging between 0.2g to 0.5g and corresponding magnitudes ofbetween 7.5 and 9.0, respectively. The results of our analyses indicate that, without

soil improvement, the upper 75 to 85 feet of loose to medium dense granularmaterials below groundwater would liquefy, with estimated post-earthquake

settlements on the order of 1 to 2 feet for the OBE and SSE events, respectively.

The results of our foundation analyses indicate that ground improvement in addition

to deep pile foundations are recommended to avoid liquefaction related damage fromlateral spreads in addition to meeting the stringent static-settlement criteria for the

proposed LNG tanks and other major structures. Foundation options satisfying theserequirements include driven steel pipe piles, augercast piles, and driven grout pile

systems. The analysis results and recommendations provided herein should be furtherrefined for purposes of the final-design phase of the project.

13.1.7 Wind Forces

All critical structures and facilities for the Project are being designed to withstand

150 mph sustained winds per 49 CFR Part 193.2067.

Non-critical portions of the terminal are being designed to withstand the wind speedsreferenced in ASCE 7.


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13.1.8 Other Severe and Natural Conditions

The Project site and facilities have been evaluated for potential severe impacts fromother weather and natural forces which may predictably occur in the Project area.

Refer to Resource Report 11 section 11.2.1 for details. This analysis concludes that no

other severe conditions could impact the Project operations. The Project is designedfor a minimum temperature of -5Fahrenheit (F).

13.1.9 Adjacent Activities

The site is largely surrounded by forest. The potential for a forest fire in the area of

the terminal will be controlled by establishing a forest free zone around the Terminaland by maintaining adequate trained personnel and firefighting equipment onsite. The

northern boundary of the site is the Columbia River. The western boundary is a cliffface that is sparely vegetated. Any forest fire on top of the cliff would likely stop

there and the heat from that fire would radiate up and out over the cliff rather thandown to its base where the LNG facilities are located. Additionally, there will be a

200 foot wide vegetation free zone maintained between the base of the cliff and the

terminal fence line. The southern boundary of the site currently has more thanadequate separation between the forest and the terminal fence line. Much of the

vegetation opposite the southern boundary is within the Hunt Creek estuary, which isbasically a wetland several hundred feet wide that is not prone to drying out and

becoming a fire hazard. Between the Hunt Creek estuary and the terminal is a

vegetation free zone. In the unlikely event that the Hunt Creek estuary were to catchfire, it would burn as a brush fire that would be extinguished at the vegetation free

zone that surrounds the fence line. The eastern fence line is bordered by an extension

of the Hunt Creek estuary and the Columbia River. If a fire in the forest were toapproach the facility, the plant personnel would have the required training andfirefighting equipment to extinguish a fire outside the fence line of the Terminal.

Train tracks run outside the terminal fence line along the southwestern boundary.

These tracks are very seldom used. There is currently no train traffic between theWauna Mill paper mill and the end of the line in Astoria. Bradwood Landing is

physically located between Wauna Mill and Astoria.

The Columbia River shipping channel runs past the site. On average, approximately

1500 ships per year transit pass Bradwood on their way to ports upstream. Thechannel is over 1200 feet from the terminal at it closest point. The possibility for a

transiting vessel losing propulsion or steerage and contacting the Bradwood dock isextremely small because of the physical orientation of the channel and thesurrounding geographical features of the river bed. Please see the extensive

Maneuverability Simulation, Attachment D-1 and D-2.

The closest airport to the facility is Karpens, a private grass air strip off Hwy 30, by

the Knappa High School, which is more than 5 miles away.


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13.1.10 Separation of FacilitiesAs depicted on the site plan drawing W00031-0011-CI-LO-002, included in AppendixA13, the following minimum distances between structural and process components of

the Project meet or exceed the requirements of NFPA 59A:

Roads

An all weather road will be provided around and through the

entire facility.

SpillContainment

Will be provided under all piping and equipment handling

LNG throughout the facility

SpillContainment

All impoundment areas will be at least 50 feet from the

property line or a navigational waterway

SpillContainment

All ignition sources will be at least 50 feet from any

impoundment area.

Equipment All process equipment containing LNG, refrigerants,

flammable liquids, or flammable gases will be at least 50

feet from sources of ignition, property lines, control room,offices, shops and other occupied structures.

Vaporizers Will be located at least 100 feet from the property line and

at least 50 feet from any source of ignition.

13.1.11 Site Development

13.1.11.1 Grading and ExcavationThe areas within the Project site required for the construction of the terminal will beleveled and graded as shown on drawing W00031-011-CI-LO-OO5 included in Appendix

A13. The design is such that the impact to the natural conditions at the site will beminimized.

The following is a general description of the sitework necessary to fill and grade theexisting site to the proposed levels above Columbia River Datum (CRD). Site filling

requirements will be as specified in the geotechnical investigation reports by URSCorporation, included in Appendix D13.

Preparation will begin with the cutting of existing surface vegetation down to a height

of 6 to 8. All heavy debris, stumps, etc, will be removed at that time.


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The existing site consists of several mounds of imported, previously dredged material,

which is to be redistributed around the project site area.

Dredged material (approximately 650,000 cubic yards) removed from the river to

create the LNG carrier maneuvering and turning area will also be deposited and

distributed on the site area.

The site will then be finish graded to approximately 25 feet 2 inches above NAVD88

using a layer of compacted crushed stone fill or other appropriate fill.

Site grading will include finish grading only as required for roadways, culverts,

ditches, concrete LNG spill collecting swales, etc. Finish grading will include asphaltsurfaced roads, gravel surfaced roads, general gravel surfacing and application of top

soils, seeding and mulching for grass areas. Wherever possible the existing drainagepatterns will be retained.

NSNG will adopt FERCs Upland Erosion Control, Revegetation and Maintenance Plan(Resource Report 7, Appendix G.1) and the Wetland and Waterbody Construction Plan

and Mitigation Procedures (Resource Report 2, Appendix B.3) to ensure that potentialeffects on soils due to construction are minimal. The specifications developed for

the proposed NSNG Terminal exceed the above guidelines. Project specification

W00031-000-CI-SP-004 Earthworks and Site Preparation is included in Appendix B13.

13.1.11.2 LNG Tank Impoundment

A full containment LNG storage tank with 9% Ni steel inner and prestressed concreteouter container is proposed. The outer concrete container of the LNG storage tank

will be the LNG tank impoundment and will hold 110% of the volume contained. Allpenetrations will be through the concrete dome roof.

In addition a Tertiary earth bund will be provided with storage capacity equal to thevolume of 1 no Tank.

13.1.11.3 Drainage and Storm Water Run-offThe facility is designed to provide drainage of surface water to designated areas fordisposal. Proper drainage and disposal of storm water is accomplished by a system of

ditches and swales, as shown on drawing W00031-0011-CI-LO-006, included in

Appendix A13. All storm water from within the tertiary bund will be collected viaswales and open channels and directed to the 2 no Spill impoundment basins.


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Storm water collected in the spill impoundment collection system will also drain to

the spill impoundment basins. The water collected in the spill impoundment basins

will be routinely pumped into drainage wells by the impoundment basin sump pumps.The flow rate for the storm water pumps shall be calculated for a 10-year storm. The

pumps will start and stop automatically on level control and are interlocked with lowtemperature sensors and switches to prevent operation of the pumps in the event of

an LNG spill. If the capacity of the drainage wells is sufficient, the storm will drain tothe level of the water table by gravity.

Storm water that falls within the site area and not in the impoundment areas isexpected to drain into the loose sand layer as it does now. If not, additional drainage

wells will be installed.

The area of the facility parking lot will drain through an API separator and then to adisposal well.

Waste water generated from personnel use will be treated in a septic system.

13.1.11.4 Spill ContainmentConstruction activities will be performed in a manner to avoid or minimize the impact

on the environment in the event of a spill of fuel, lubricant, or other hazardousmaterial within 100 feet of any water body or wetland. A spill prevention control and

countermeasures (SPCC) plan for the construction activities will be developed inaccordance with 40 CFR Parts 122 through 124.

13.1.11.5 FoundationsBuildings, process equipment, and pipe rack foundations will be supported with massconcrete foundations. Materials for the concrete will conform to the American

Society for Testing and Materials (ASTM) and other recognized standards whereapplicable.

Design and quality requirements for concrete materials will be in accordance with

American Concrete Institute (ACI) 318 and ACI 301. Concrete with design strength of

4,000 psi as defined in ACI 318 will be used for the foundations. Proportioning will beaccording to the methods outlined in ACI 301. The maximum water-cement ratio will

be 0.50 for structural concrete.

All settlement sensitive equipment, buildings and structures will be supported as

specified in the geotechnical investigation reports for the tank, process area,piperack, waterline and berth areas by URS Corporation, Inc., included in Appendix

D13.


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Tank Foundation Drawing W00031-0011-CI-LO-017 is included in Appendix C13.

Piling for the marine structures will be tubular steel piles, with reinforced concrete

pile caps.

Specifications, W00031-000-CI-SP-004, W00031-000-CI-SP-005, W00031-000-CI-SP-011are included in Appendix B13.

13.1.11.6 RoadsBradwood Landings roads will consist of gravel surfaced and asphalt surfaced roads asshown on drawing W000-011-CI-LO-006 included in Appendix A13. All plant roads and

vehicle parking will comply with specifications W00031-000-CI-SP-007 included inAppendix B13.

13.1.11.7 Site Surface TreatmentSurface treatment drawings will be prepared, which will designate treatments foreach area. Final grading and landscaping will consist of the following:

Gravel surfaced area; Asphalt surfaced area; Concrete paved surfaces; Seed and mulch area.

Site work shall conform to the following specifications:

W00031-000-CI-SP-004 Earthworks and Site Preparation;

W00031-000-CI-SP-008 Unpaved Areas;

W00031-000-CI-SP-007 Roads and Paving;

W00031-000-CI-SP-012 Plant Fencing.

Copies of the above referenced specifications are included in Appendix B13.

Trees will be planted along the shoreline to enhance the visual impact of BradwoodLanding from the river.


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13.2 FIRE PROTECTION SYSTEM

The proposed terminal has a number of independent fire protection systems. These

include

i) A fire water main capable of servicing hydrants, monitors, the jettyspray curtain, and individual equipment spray protection.

ii) High expansion foam system for protection of the spill impoundmentbasins.

iii) Dry chemical extinguishers to enable a fire within the relief valvedischarge piping to be extinguished automatically.

iv) Portable fire extinguishers throughout the terminal, along withFireproofing.

These four systems are described below.

13.2.1 Firewater System

The description of the firewater system below should be read in conjunction with the

Firewater Network P&ID, drawing number W00031-000-PR-PI-053 included in AppendixA13 and the Fire Protection Evaluation Philosophy, document number W00013-000-PR-

DB-008. The following codes were referred to in the design of the fire water system:

NFPA 13 Installation of Sprinkler Systems NFPA 14 Installation of Standpipe, Private Hydrants and Hose Systems NFPA 15 - Water Spray Fixed Systems for Fire Protection NFPA 20 Standard for the Installation of Stationary Pumps for Fire

Protection

NFPA 24 Installation of Private Fire Service Mains and their Appurtenances API 2030 Application of Fixed Water Spray Systems for Fire Protection in

the Petroleum Industry

13.2.1.1 Firewater System Components

Refer to the Firewater and Monitor layout drawings W00031-030-PI-LO-007 andW00031-030-PI-LO-008 included in Appendix A13

The main components of the Firewater system are:-


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One diesel engine and one electric driven Firewater Pump, 761-P-001/2 Two Firewater jockey pumps 761-P-003/4 taking suction from Service Water

Storage Tank 766-D-002

Nineteen fire monitors, two elevated monitors at the Jetty Sixteen Fire Hydrants Fourteen Fire Hose Reels within the Control room, warehouse and

administration building

Sixteen portable extinguishers for liquid, gas or electrical fires. Nine dry chemical extinguishers, one positioned on the jetty and eight

positioned on the tanks.

Underground / above ground firewater piping distribution system.The firewater ring main is supplied directly from the two main firewater pumps.

These pumps are located on the jetty and take suction directly from the river. Eachfirewater pump is designed to supply 4400 gpm (1000 m/h) of firewater, one pump

operating and one pump on standby. Discharge pressure of the main firewater pumps

is set at 150 psi g (10 bar g) and a check has been carried out to ensure that at theextremities of the system the hydrant / monitor nozzle pressure is a minimum of

90 psi g (6 bar) before throttling.

Action of the firewater pumps is to automatically start when the system pressuredrops too low. Normally the pressure is maintained in the system by the two firewater

jockey pumps. These pumps have a similar discharge pressure to that of the main

firewater pumps but have a rated flow of 60 gpm. In the event of a fire the pressurewithin the firewater main will drop as the usage rate of the firewater is greatly in

excess of the jockey pump discharge. Before the pressure reduces below the minimumpressure required at each spray system / monitor the main firewater pumps are

activated.

Bradwood Landing is divided into fire areas. Single spray systems and monitorsconnected to the firewater main are required to protect only one fire area. It is

considered that a number of systems and fire areas may be affected simultaneously.

These scenarios have been evaluated by considering possible flow of burning liquids,either before or during the application of firewater, gas jet fires, activation of

automatic systems from gas or heat detection, and reasonable manual operation ofmultiple systems. The worst of these cases has then determined the required design

firewater flow rate.

The diesel firewater pump has an independent diesel tank capable of keeping the

firewater pump running for a period of 8 hours. It is considered that additional dieselcan be supplied either from storage or from an offsite supply (tanker) within this


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period should further running of the firewater pumps be required. The minimum

stated by NFPA20 section 11.4 is that the diesel tank capacity is 1 gallon per HP plus

10%, and the tank is sized accordingly.

13.2.1.2 Firewater Piping

The materials selected for the firewater piping system are as identified inspecification W00031-030-PI-SP-002, Index of Piping Material Classes, included in

Appendix B13, whereby the underground part of the system shall be in high density

polyethylene (HDPE) material, and galvanized carbon steel shall be used for allaboveground firewater pipework.

The layout of the firewater distribution is design in a modular loop configuration to

ensure that if there was any blockage at any point within the firewater main pipingthen water can be supplied from either direction and still service all parts of the

distribution. Multiple post indicator valves are provided to allow isolation of sections

of the system if required. This complies with NFPA 24.

13.2.2 Dry Chemical Extinguishers

Each LNG Storage tank is fitted with 4 over pressure relief valves, with each PRV

discharge piping being vented to atmosphere at safe location high above the LNGtank. Should the discharge from one of these PRVs become ignited a jet flame will be

induced. Dry chemical extinguishers are fitted to each of the PRVs discharge pipes(8 in total). They provide a manually activated burst of chemical extinguisher into the

discharge piping designed to put out the jet flame at the venting point. Eachextinguisher is charged for two applications.

One dry chemical extinguisher is also positioned at the jetty.

13.2.3 High Expansion Foam

There are two high expansion foam packages, 760-A-003/4, one for each of the spillimpoundment basins. Both of the packages will comprise:-

2 x 100% water turbine powered foam concentrate pumps A foam concentrate tank capable of storage of enough concentrate to

supply the spill impoundment basin with the initial layer of foam within aone minute period, followed by continual replenishment up to an eight hour

period. This equates to a concentrate tank capacity of 250 gallons.

Concentrate to water mixer. Associate piping and control panel.


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When the foam packages are initially turned on they are designed to cover the spill

impoundment basins completely in a 6ft depth of foam within the first minute.Thereafter, the foam rate can be reduced to meet the replenishment requirement of

the foam layer. Each impoundment basin is 60ft x 60ft (~400m) in area. Bothpackages include the ability to be tested periodically.

13.2.4 Portable Fire Extinguishers

Approximately 16 portable fire extinguishers will be provided throughout theterminal. Their type will be dependant on the individual location of each fire

extinguisher point e.g. carbon dioxide type extinguishers next to electrical cabinets,but generally of the 30 lb water type located at utility stations and / or accessareas

to allow easy access in the event of an emergency. In addition approximately 15wheeled hose reel units will be distributed around the perimeter of Bradwood

Landing.

13.2.5 Fireproofing and Siren

Fireproofing will be used for protection of steel structures, equipment, electrical

components and motor / air operated valves that may be exposed to a liquid fire.

Fireproofing will only be used where the structures, equipment or components cannotbe protected by other means.

Bradwood Landing will include siren(s), which will be audible in all locations. This

siren(s) will have a distinctive mode, for easy recognition between alarms andemergency events.

13.3 HAZARD DETECTION SYSTEM

13.3.1 General

49 CFR Part 193 and NFPA 59A both require all areas, which have a potential forcombustible gas concentrations of LNG or flammable refrigerant spills, to be

monitored for combustible gas concentrations.

Control and monitoring of the facility will be performed by an integrated distributed

control system (DCS) consisting of package units with local control panels, numerousfield mounted instruments connected to remote input/output (IO) cabinets and

operator interface stations (HMI) located in the control rooms.


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Fire and Gas area monitoring equipment will be installed to provide detection of

flammable hydrocarbon releases or ignitions.

An independent Safety Instrumented System (SIS) will be installed to allow the safe

sequential shutdown and isolation of rotating equipment, field equipment and LNG

storage facilities.

The P&IDs included in Appendix A13 show the ESD isolation points (See Table 13.3-1).

Closed circuit television (CCTV) system monitors will be installed in the security officeand the main control room to provide selectable remote views for the operators.

Instrumentation will be rated to meet the area classifications. In general,

instrumentation will be provided to meet National Electrical Code (NEC) Class 1,Division 2, Group D.

The Instrument Plan drawings included in Appendix A13, shows the location andnumber of all detectors for flame, gas and smoke, also shows location of the CCTV

cameras, manual call points and Emergency Shutdown (ESD) pushbuttons.

a) Smoke Detection Layout W00031-840-IN-LO-001b) CCTV Layout W00031-840-IN-LO-002c) Macs (Call Points) Layout W00031-840-IN-LO-003d) Point Gas Detection Layout W00031-840-IN-LO-004e)

Open Path Gas Detection Layout W00031-840-IN-LO-005

f) Flame Detection Layout W00031-840-IN-LO-006g) Low Temp./ Cold Detection Layout W00031-840-IN-LO-007h) Water / Foam Delivery Layout W00031-840-IN-LO-008i) Fire Extinguishers Layout W00031-840-IN-LO-009j) ESD Shutdown Buttons Layout W00031-840-IN-LO-012

The schedules of Hazard Detection System Instrumentation is included in Appendix

B13

Hazard detection for the facility is designed on the following strategies:

Visual Monitoring; Automatic Detection (flame, gas, smoke and low temperature);

Centralized Alarm System;

Emergency Shutdown System (ESS).


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13.3.2 Monitoring Equipment

All fire and gas (F&G) area monitors will be hardwired from the field device to the

control room SIS panel as analog or discrete inputs as appropriate. Area monitors shallconsist of flammable gas and flame detection. Quantities and locations will be asdetailed on the Instrument Plan Drawings included in Appendix A13.

F&G detectors will only activate alarm systems and will not operate or initiate anyterminal shutdowns other than those associated with equipment room heating and

ventilation systems. Operators in any of the control rooms would take the appropriateactions to safeguard the equipment and the terminal.

Audible alarms will be provided throughout Bradwood Landing area to alert plant

operators.

13.3.2.1 Gas Detectors

Smart area monitors with splashguards and single person calibration feature to be

provided for monitoring flammable gases within the terminal. A portable calibration

equipment kit will be included for future field verification and calibration needs.Sensors will be located in the LNG storage tank area, vaporization area, jetty control

room, substation, compressor area, administration building etc. as detailed on theInstrument Plan Drawings included in Appendix A13.

13.3.2.2 Low Temperature DetectorsLow temperature sensors are located in the spill impoundment basin to shutdown andprevent start-up of the impoundment basin and storm water pumps in case of an LNG

spill.

13.3.3 Fire Detectors

13.3.3.1 GeneralSmart ultra-violet / infrared (UV/IR) monitors will be installed throughout the

terminal. A portable rechargeable battery operated test lamp will be included forfuture field verification and calibration needs. Sensors will be located throughout the

terminal as detailed on the Instrument Plan Drawings included in Appendix A13..


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13.3.3.2 Smoke Detectors

Smoke Detectors will be provided in buildings where early detection of smoke iscritical to safeguarding the equipment in the building or the terminal. Smoke

detectors will be incorporated into the fire detection alarm system. The detectors are

designed for classified areas in hazardous locations and equipped with self-checkingcircuitry to ensure a highly reliable operation with compensation for accumulation ofdust or other contaminates to prevent false alarm signals. The location of the smoke

detectors are detailed on the Instrument Plan Drawings included in Appendix A13.

13.3.3.3 High Temperature Detectors

High temperature detectors will be included to detect a fire on the vent pipes of the

LNG storage tanks (120-D-001 and 220-D-001) relief valves.

13.3.3.4 Visual MonitoringVisual monitoring of the process and offshore areas will be maintained. A security

video monitoring system will be used to monitor fence line and terminal entry.

High-resolution low light cameras will be located throughout Bradwood Landing.

Cameras will be mounted in places to afford a view of the process area, the unloadingarms, the carrier manifold, the LNG storage tanks and the marine areas. As a

minimum, the cameras will be located to provide viewing of the following areas:

Main gate; Administration building; Process areas; LNG tanks; LNG relief valves; Jetty operations; Carrier manifold.

13.3.4 Fire and Hazardous Gas DetectionF&G area monitoring equipment will be installed to provide detection of flammablehydrocarbon releases or ignitions. The F&G system will be integrated into the SIS.


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13.4 SPILL CONTAINMENT SYSTEM13.4.1 Spill Containment TanksLNG tanks will be of the full containment design. A 9% nickel steel inner tank is

surrounded by a prestressed outer concrete container. The outer concrete containeris sized to hold the contents of the tank and acts as the tanks impoundment. Allpenetrations will be through the domed roof of the outer concrete tank and the

suspended deck of the inner tank.

A tertiary earth bund will be constructed which will be able to contain the contents of

a single LNG tank within the site boundary. Ref drawing W00031-0011-CI-LO-005 andW00031-0011-CI-LO-006 included in Appendix A13

13.4.2 Spill Containment Tank and Vaporizer Area

Two full containment LNG tanks will be installed initially at Bradwood Landing. A

third tank of the same design may be installed in the future.

The tank and vaporizer area includes the LNG tanks, a portion of the unloading lineand recirculation line and the sendout area. In order to comply with the relevant

standards, it is required to determine the most severe design spill likely to occur in

this area, in order to design a suitable containment system. Spills are routed to theimpoundment basin by a series of collection troughs.

The vaporizer area includes the sendout pumps, vaporization area and sendout line.

The area around the vaporizer area will be curbed and graded so that a spill will berouted to the impoundment basin by a collection trough.

The largest LNG volume in the tank area is from the unloading line during anunloading operation. A spill from this line over a 10-minute period (as per NFPA 59A

Section 2.2.2.2), would give a spill volume of 529,091 gallons at the maximumunloading rate of 52,834 gpm (12,000 m3/hr).

This volume was used in the sizing of the tank area impoundment basin. The basin

dimensions were determined to be 60ft x 60ft x 20ft which gives an available sump

capacity of 538,632 gallons. The capacity of the sump is therefore acceptable forcontainment of a tank area design spill.

The spill containment is in shown on drawing LNG Spill Containment Plan

W00031-0011-CI-LO-007 included in Appendix A13.


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13.4.3 Spill Containment Jetty Area

The jetty area includes the larger portion of the unloading and recirculation

lines. In order to comply with the relevant standards, it is required todetermine the most severe design spill in order to design a suitablecontainment system.

The largest LNG volume in the jetty area is from the unloading line during anunloading operation. A spill from this line over a 10-minute period (as per NFPA 59A

Section 2.2.2.2), would give a spill volume of 529,091 gallons at the maximumunloading rate of 52,834 gpm (12,000 m3/hr).

This volume was used in the sizing of the jetty area impoundment basin. The basin

dimensions were determined to be 60ft x 60ft x 20ft which gives an available sumpcapacity of 538,632 gallons. The capacity of the sump is therefore acceptable forcontainment of a vaporizer area design spill.

The spill containment is in shown on drawing LNG Spill Containment Plan

W00031-0011-CI-LO-007 included in Appendix A13.

13.4.4 Spill Containment General

The sacrificial concrete screed to the troughs and impounding systems will have a

thickness varying from 75 to 150mm and will have a characteristic cube strength of40N/mm2. The thermal conductivity will be 1.6 W/m degC and the density will be

2400kg/m3. The sacrificial concrete screed and underlying structural concrete will

have a polythene membrane separating them. The screed will have nominal anti-crack reinforcement.

Following annual inspections it is expected that the sacrificial screed layer will

require minor repairs to areas of weathering five years following the end of plantconstruction and more substantial repairs and areas of replacement every 15 years

subsequently. However, this is dependent both upon the quality of design, detailing

and construction.

13.5 SHUT-OFF VALVESThe jetty will have isolation valves, which will be closed on ESD. The valves will befire safe valves with piston actuators. The valve actuator will be pneumatically

powered. A spring will close the valve upon loss of pneumatic air. Actuation will


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involve energizing a solenoid valve, which will put pneumatic pressure on the valve

operator opening the valve.

When an ESD is activated the pneumatic pressure is vented and the fail close spring

closes the valve. A manual reset is required to reopen the valve. This assures that an

operator will have first hand knowledge of the condition of the facilities prior toreactivation. The valves will also be equipped with position switches, which willdisplay the position of the valves in the control room.

The ESD valves will be supplied with manual reset solenoid valves, on-line test panels,open/close position switches, local air receivers for 3 cycles, fireproof enclosures,

and fail close operation. Valves shall be tested for Class 6 leakage, fire safe, andcryogenic service.

All cryogenic ESD valves will be butt-welded to process piping.

The ESD valves are shown on the P&IDs included in Appendix A13. and in Table 13.3-1.

13.6 DESIGN PLANNINGThe general design approach to the Project is to provide a safe, efficient, easilyoperable and maintainable facility that will minimize effects on the environment.

This involves the use of and compliance with standards and codes for any new

facilities, including 49 CFR Part 193, as well as applicable codes of NFPA, AmericanPetroleum Institute (API), American Society of Mechanical Engineers (ASME), American

National Standards Institute (ANSI), American Society of Testing Materials (ASTM),American Institute of Steel Construction (AISC), American Concrete Institute (ACI),

and Occupational Safety and Health Administration (OSHA).

An over and under pressure safety review has been undertaken by the Whessoe Oil and

Gas Limited Study Team. The minutes of this review are included in Appendix A13.The review verified the preliminary facility design and actions for the implementation

in the next phases of the project were identified.

HAZOP analysis will be conducted during the detailed design phase of the Project.

A list of Code references used in the preparation of the preliminary design of the

Project, are included in Appendix A13.


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13.7 MAJOR PROCESS COMPONENTSDuring the initial Engineering Design the major considerations taken with regard thetype of equipment selection for the Project are:

Safety Reliability Emissions Quality Ease of maintenance Energy efficiency Ease of operability Capital cost

Major process components are shown on the Process Flow Diagram (PFD) W00031-000-PR-PF-001 and P&IDs referenced in each section, the drawings are included in

Appendix A13.

13.7.1 Marine Facilities

The Project will include the construction of an LNG Carrier unloading facility

consisting of a dredged basin with an LNG Carrier berth and a berth for the temporarymooring attending tugs or mooring craft. The LNG unloading facility will have the

capability of unloading in the order of 180 ships per year. Each tanker will have anapproximate unloading time of 18 hours at Bradwood Landing and full turnaroundtime of up to 36 hours (from open sea to open sea).

The LNG berth will be located at, approximately, river mile 39 of the Columbia River.

The location of the berth is such that it is over 1000 ft from the main river navigationchannel providing a significant clear safety distance from the main channel for a

passing vessel.

All maneuvering and docking of the LNG Carriers at the berth will be under tug

assistance and pilot supervision. All berthing and mooring operations will be closelymonitored by the Berthing Master/Jetty Controller from a berth control office located

on the Jetty Head to ensure safety of operations.

The Columbia River navigation channel starts at the Columbia River bar and continues

five miles upriver at a depth of 55-feet and a width of 2,640-feet. It then maintains adepth of 40-feet and a width of 600-feet to beyond the berth site. The channel passes

under Astoria Bridge with 205-feet air clearance and 1070-feet clear width. A project


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(the US Army Corps of Engineers Columbia River Federal Navigation Channel

Improvement Project) is currently underway to deepen the existing 40-foot deepshipping channel by 3 feet to allow continued navigation access. Work to deepen thenavigation channel began in June 2005. Additional work is expected to take place in

2006 and 2007.

A dredged maneuvering and turning area will connect the berth with the navigationchannel. This dredged area will be approximately 2000 feet by 2000 feet and will be

dredged to a depth of at least 42 feet below Columbia River Datum (CRD).

Construction of the marine basin will require the dredging of approximately 650,000cubic yards of material. The dredge disposal method to be used will be approved by

the US Army Corps of Engineers (USACE).

The unloading facilities will be sized to handle LNG Carriers with a capacity of100,000 m3 up to 200,000 m3 and drafts up to 40 feet. Carriers with larger capacities

may be evaluated in the future. Four breasting structures and four mooring structures

will be provided at the berth, consisting of steel pipe piles with concrete caps. Thebreasting structures will be equipped with fenders suitable to safely berth and moor

the full range of vessel sizes being considered. Access catwalks will be provided ateach berth to connect the breasting structures to the jetty head and to the mooring

structures. For the safety of personnel emergency egress catwalks will provide an

alternative route to shore should the primary route be blocked. Mooring pointscomprising Quick Release Hooks (QRH) will be provided at each berth on the mooring

dolphin structures for bow & stern breast lines (holding the vessel onto the berth) andon the berthing dolphin structures for spring lines (maintaining the vessels position

along the berth).

Mooring structures will be provided with ladders to provide access from small craft on

the Columbia River and protective hand railing around the working surface of thestructures except on the mooring line faces. Floodlighting to the QRH moorings will be

provided, angled downwards and shielded to ensure that there is no danger to thesafe navigation of vessels on the Columbia River.

The mooring hooks will be provided with strain gauges enabling measurement of theforces arising in the mooring lines to be displayed on a screen located within the

Berth Control Office. This will enable the safe mooring of the Carrier to be monitoredat all times. There will also be fitted to the berth face a display screen enabling the

velocity and angle of approach of the berthing vessel to be continuously monitoreduntil the Carrier is safely berthed.

The two extreme up and downriver mooring dolphins will each be provided with anavigation light marking the extent of the structure in the river.


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The jetty head will be a reinforced concrete beam structure, approximately 115 feet

wide by 125 feet long supported on steel pipe piles. Outside the LNG pipework area

the slab will be sloped to drain storm water into the marine basin. Operational andpipework areas will be curbed and laid to slopes such that any liquid that falls into

the curbed area below the pipes will flow to the onshore containment pit. Drainagefrom this point will be via the LNG spill collection trough along the approachway to an

onshore spill impoundment basin.

The approachway will be approximately 20 wide (24 feet over safety barriers and

curbs) to permit a small mobile rubber tired crane to pass to the unloading arm area.The pipeway will be 16 feet wide (19 feet overall width) located over the spill

collection troughsuch that any liquid escape dropping into the trough will be directedto the onshore spill containment pit.

The surface of the trough will be lined with a sacrificial layer of concrete designed to

minimize thermal shock to the underlying structural concrete in the event of an LNG

leak or spill.

Onboard ship pumps will deliver the LNG to the LNG storage tanks. A total of fourmarine unloading arms will be installed on the unloading arm platform, three for

liquid delivery to the LNG storage tanks and one for vapor return to the ship. One of

the liquid lines can be valved to flow vapor return to the ship in the event of aproblem with the primary vapor return arm. Space for a possible future fifth arm will

be reserved on the platform. The unloading arms will be designed with swivel jointsto provide the required range of movement between the ship and the shore

connections. Each arm will be fitted with powered emergency release coupling (PERC)valves to protect the arm and the ship. The PERC valves also minimize spillage of

LNG in their operation. Each arm will be operated by a hydraulic system and a

counterbalance weight will be provided to reduce the deadweight of the arm on theshipside connection and to reduce the power required to maneuver the arm into

position. The unloading arms will be a nominal 16-inch diameter capable of acombined unloading rate of 12,000 m3/hour. The LNG will then be transferred to the

storage tanks onshore by a 32-inch diameter liquid (cryogenic) transfer line.

Maneuvering and docking of the LNG tankers can be accomplished with no more than

three Z-drive tugs under most weather conditions of weather, current, tide, etc. Theberth layout was first reviewed by experienced pilots, and changes made based on

their recommendations. The final berth layout was then successfully confirmed incomputer simulations of the maneuvering and berthing conducted at the U.S. Army

Corps of Engineers Engineering Research and Development Center's (ERDC) Ship and

Tow Simulator located in Vicksburg, Mississippi. A full report can be found inResource Report 11.


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The facilities have been designed to provide safe berths for the receipt and support of

LNG Carriers and to ensure the safe transfer of LNG cargoes from the ships to on-

shore storage facilities. Design is in accordance with applicable codes and standards,including but not limited to Oil Companies International Marine Forum (OCIMF),

Society of International Gas Tanker and Terminal Operators (SIGTTO), InternationalNavigation Association (PIANC), American Petroleum Institute (API), and American

Society of Civil Engineers (ASCE).

13.7.1.1 Carrier Unloading Arms

Refer to P&IDs W00031-000-PR-PI-004/005/006/007.

A set of four unloading arms (2 liquid unloading arms, 1 hybrid arm, normally used in

liquid unloading service and 1 vapor return arm) will be provided on the jetty. Thetransfer of LNG from carrier to shore will be by means of these four articulated arms.

Each unloading arm will be provided with two isolating valves and a Powered

Emergency Release Coupling (PERC). The PERC system will protect the arm and thecarrier in the event of excessive movement of the arm, and help to minimize spillage

of LNG if emergency uncoupling of an arm occurs. The arms will be operated bymeans of an hydraulic system and counter-weights will be provided to facilitate rapid

disconnection and to reduce the deadweight of the arms on the shipside connections.

The unloading arms are designed for an unloading rate of 52,834 gpm (12,000 m3/hr).

Operating conditions will be in the region of 95 psia and 255 oF.

In case of non-availability of the vapor return arm, one LNG unloading arm (the hybridarm) can be changed to vapor service. A DB&B connection between the vapor return

arm and the hybrid arm is provided for this purpose. In this event, the unloading

flowrate is decreased by 33% and the unloading time increased correspondingly.

The main technical characteristics of the unloading arm set are as follows:

Manufacturer: FMC Energy Systems or similar Service: Natural Gas / LNG Unloading Arm Size: 16 in Design Temperature: 274 oF / +99 oF Range of Carrier Capacities: 26.4 52.8MM gallons (100,000 m3

200,000 m3)

The unloading arms manufacturer will be selected based on compliance to

specifications and will have prior experience with LNG operations.


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See Appendix B13 for LNG Unloading Arms Datasheet (W00031-664-PR-DS-011).

3.7.2 LNG Un-loading Operation

The LNG from the carrier will be unloaded by means of the carriers on-board pumps.

Cool-down of the unloading arms and the auxiliary equipment will be started from thecarrier, after which the LNG pumping rate will gradually be ramped-up until themaximum unloading flowrate of 52,834 gpm (12,000 m3/h) is obtained.

The LNG storage tanks will be maintained at an operating pressure of up to 3.5 psigduring the unloading process. The unloading arms will be manifolded to a 32

unloading line and a 6 recirculation line. The LNG will be transferred into each ofthe storage tanks via 32 pipes. The tanks can either be top or bottom filleddepending on the compositions of the tank contents and the fresh cargo from thecarrier. The LNG unloading rate will be controlled from the carrier as agreed with the

terminal.

The unloading operation will continue until the LNG tanker is almost empty at which

point the pumping rate will be ramped down. The jetty facilities and unloading lineswill be designed to unload the contents of a 42.3 MM gallons (160,000 m3) carrier with

adequate rail elevation and pumping capacity at a rate of 52,834 gpm (12,000m3/h) in

approximately 14 hours, excluding time for docking, cooling and undocking.

The pressure in the carrier during unloading will be maintained by means of a vaporreturn system, which will enable the required vapor to flow from the storage tanks to

the carrier. With the line pressure into the carrier controlled, the volumetric flowwill adjust itself naturally to match the carriers liquid displacement. A

desuperheater will be installed on the jetty in order to control the temperature of the

vapor returned to the carrier to about -220F by injecting LNG into the vapor.

LNG for desuperheating will be supplied from the jetty transfer line. A vapor returnKO drum will be provided to prevent liquid slugs downstream of the desuperheater,

ensuring single-phase vapor flow to the vapor return arm. The KO drum will also actas a drain pot for the unloading arms.

The carriers tank level gauges will be used for the fiscal measurement of the totalcargo transferred from the carrier to the storage tanks. The LNG unloaded at

Bradwood Landing from a carrier will be sampled on-line and analyzed forcomposition. The density, calorific value, and Wobbe Index of the unloaded LNG will

also be determined from the on-line samples. An LNG sampling package will beinstalled on the unloading line to accomplish this.


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A 32 unloading line will connect the jetty and the storage area. The size of this line

is based on an unloading flowrate of 52,384 gpm (12,000 m3/h). A recirculation

cooldown line (6) will also be provided. The recirculation line is sized for no greaterthan a 4F delta temperature rise or 114 m3/h (500 gpm) minimum, whichever is

controlling.

The transfer lines coming across the jetty will be equipped with emergency isolationvalves for isolating the carrier supply in case of an emergency situation.

During normal operation (when no carrier is berthed), the unloading lines will be keptcold by circulating LNG liquid from the send-out system to the jetty head via the re-

circulation and unloading lines.

3.7.2.1 Vapor Return Blowers Knockout Drum

Refer to P&ID W00031-000-PR-PI-007.

A vapor return KO drum will be located on the jetty. Once the unloading activities

have been completed and before re-circulation is started, LNG will be drained fromthe unloading arms to the vapor return KO drum and back to the LNG carrier by

pressurizing with gaseous nitrogen. After the carrier has disconnected, the vapor

return KO drum will be drained into the unloading line, again by pressurizing withnitrogen.

The main technical characteristics of the vapor return KO drum are as follows:

Service: Natural Gas / LNG Design Pressure: Full vacuum / 174 psig Design Temperature: 274 oF / +99 oF Dimensions: 9 ft 6 in dia x 28 ft 6 in ht

See Appendix B13 for Vapor Return Knockout Drum datasheet (W00031-666-PR-DS-

013).

13.7.2.2 BOG and Vapor Handling System

The BOG and vapor handling system is detailed in P&IDs W00031-000-PR-PI-008/009/010/011.

The vapor handling system will be essentially comprised of:-


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Vapor handling pipework BOG compressors BOG condenser

The function of the vapor handling pipework is to provide a safe conduit for thevapors generated within the LNG storage tanks. These vapors are generated as a

result of heat leakage into the system and the resulting vaporization of the LNG.During the unloading operation, these vapors (BOG) are displaced by the LNG entering

the tanks and therefore need to be safely removed in order to maintain the correct

tank pressure.

Both LNG storage tanks are connected to a BOG vapor header line (24) which isequipped with a connection to the process vent. Normally, the BOG is routed to the

carrier (during unloading operations, to offset the unloaded LNG volume) or to the

BOG compressors (where the BOG is compressed and subsequently condensed back

into liquid form by mixing with a volume of LNG).

The function of the BOG compressors is to raise BOG pressure to a level at which it

can be condensed in the BOG condenser. The BOG compressors will also serve tocontrol tank pressure during carrier off-loading and periods of low send-out.

The function of the BOG condenser is to condense the boil-off vapors. This isnecessary to avoid the high compression costs that would result if the boil-off vapors

were simply compressed to export line gas pressure. The condensed boil-off (as liquid)is then raised to export pressure by pumping rather than compression.

During carrier unloading, vapor displaced from the LNG storage tanks will be returned

to the LNG carrier via the vapor return line. The pressure control valve installed on

this line will maintain the required pressure at the vapor return arm.

The energy of pumping the LNG out of the carrier and the heat leak into theunloading arms, unloading and fill lines will increase the vapor pressure of the LNG.

Hence, during carrier off-loading the LNG storage tanks will be operated towards theupper end of their pressure range to suppress flash from this increased vapor

pressure. Normal tank boil-off and any extra boil-off gas from the unloading operation

(nominally equivalent to the carriers boil-off) will flow to the vapor recovery system.

When there is no carrier unloading, the volume of LNG sent out from the storagetanks will frequently exceed the quantity of boil-off gas generated and padding gas

will be used to maintain low tank pressure. At lower send-out rates, boil-off gas

production will exceed the LNG displacement and boil-off gas will flow out of thetanks to the vapor recovery system.


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The tank vapor balance lines will be manifolded to the BOG header so that both tanks

are at the same pressure. High tank pressure will be controlled by the action of theBOG compressors.

In the BOG condenser, the boil-off gas will be contacted with LNG from the in-tankpumps and, at the higher pressure of the BOG condenser, be re-condensed.

If the pressure of the boil-off gas header rises beyond the ability of the BOG

compressors to control, the relief policeman controller will act to route excess gasto the process vent stack for disposal. The relief policeman controller will operate

before the storage tank pressure rises to the set point of the tank pressure safetyvalves.

In the event of an LNG tank being isolated from the BOG header, the individual tank

pressure safety valves will maintain a safe operating pressure in the tank.

13.7.2.3 Boil-Off Gas Compressor

The terminal design includes 2x50% reciprocating BOG compressors. The sizing of the

compressors is based on the minimum send-out case (maximum BOG case) during start

of carrier unloading. The thermal mass of the jetty line, which warms during periodsof no off-loading means that at start of off-loading, the capacity of the system is

reduced. The compressors will operate in a duty / standby arrangement. The BOGCompressors are sized for a maximum capacity of 7.68 MM actual cf/d.

A desuperheater will be installed on the BOG compressor suction line. This is to

ensure that the compressor suction temperature will always be below -250F to avoid

unacceptably high discharge temperature when the compressor is operating at itsmaximum discharge pressure. (There are times, due to prolonged periods of high

sendout, when there is no flow of BOG to the compressors and the compressor suctionpipework, with considerable thermal mass, could warm up to close to ambient

temperature, resulting in warm suction gas to the compressors.)

A knock-out drum will be provided on the BOG compressor suction to separate any

injected liquid that is not vaporized in the compressor suction flow.

The main technical characteristics of the BOG compressor are as follows:

Manufacturer: Burckhardt Corporation/IHI or similar Service: Natural Gas Suction Pressure: 18.2 psia at 251 oF


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Rated Discharge Pressure: 116 psiaSee Appendix B13 for BOG Compressor datasheet (W00031-562-PR-DS-006).

13.7.2.4 BOG Condenser

The BOG condenser will perform two functions: a) it will condense boil-off gas using

the cold capacity in the LNG from the in-tank pumps; and b) it will provide NPSHA andbuffer capacity to the send-out pumps.

The upper section of the vessel will contain a packed section, which will be wetted by

the downward flowing LNG. The packing will provide a large surface area for contactwith the boil-off gas flowing co-currently through the packing. The LNG supply to the

BOG condenser will be under pressure control and will increase if the BOG condenser

pressure rises and vice versa. Additional pressure control valves will allow excess

pressure to be vented or padding gas to return from the send-out line.

The BOG condenser normally operates with the two objectives in the first paragraph

above. However, there will be instances when there will be no boil-off gas comingfrom the LNG tanks to the BOG Compressor and BOG Condenser. In particular when

the send out is at a high flow rate and its suction effect in the LNG storage tank due

to the withdrawal of liquid from the tank exceeds the boil-off gas flow rate due toheat leak into the tank and associated pipework.

This situation will occur when there is no unloading from a carrier. In effect the BOG

Condenser will not have any gas to condense, but LNG will be maintained in thecondenser in order to keep it cold and to provide the required suction head for the

send out pumps. When there is no boil-off gas flowing to the condenser there is no

need to maintain its normal operating pressure. Padding gas which is normally used tomaintain the pressure will not be required during this mode of operation and it can be

considered to be operating in flooded mode. Padding gas will be utilized to restorethe vessel to pressure and level control after flooded operation, providing the motive

force to empty the vessel and the pressure to inhibit flashing of hot liquid from the

previously flooded condenser.

The lower part of the vessel will be of larger cross-section and will act as the liquidbuffer volume for the send-out pumps. It will be sized for the future send-out rate(1,500 MMSCFD) and a liquid hold-up time of 30 seconds at that rate.

The elevation of the BOG condenser will be set to provide the send-out pumps withadequate NPSHA assuming the handling of boiling liquid.


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Under normal operating conditions, the majority of the LNG flow will bypass the BOG

condenser. The level of liquid in the BOG condenser will be used to control this

bypass flow (unless the condenser is flooded). At minimum send-out conditions,almost all of the LNG flow will be routed through the top of the BOG condenser.

The main technical characteristics of the BOG condenser are as follows:

Service: Natural Gas / LNG Design Pressure: Full vacuum / 200 psig Design Temperature: 270 oF Dimensions: 12 ft 6 in dia x 26 ft 3 in ht

See Appendix B13 for BOG Condenser datasheet (W00031-566-PR-DS-009).

13.7.3 LNG Sendout System

13.7.3.1 In-Tank LNG Pumps

Refer to P&IDs W00031-000-PR-PI-067/069.

LNG from the storage tanks will be pumped by the vertical, submerged in-tank LNG

pumps located in the storage tanks (three pumps per tank, six in total in the two LNGtanks to be installed initially) to the BOG condenser (or bypass) and on to the send-

out pumps. The in-tank LNG pumps will each be capable of pumping 2353 gpm of LNG

at a pressure of 145 psia. At the normal send-out rate of 1,963,390 lb/h, four pumpswill be required to operate (leaving one spare pump per tank).

Each in-tank LNG pump will be provided with a recycle (kick-back) loop back to the

LNG storage tank to ensure the pumps do not operate below their minimum safe flow.

All in-tank pumps shall be capable of simultaneous operation on total kick-back fortank mixing in case of stratification.

The main technical characteristics of the in-tank LNG pumps are as follows:

Manufacturer: Ebara or similar Service: LNG Suction Pressure (min/max): 17.3 / 43.8 psia Rated Discharge Pressure: 145 psia


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Motor Size 265 HPSee Appendix B13 for LNG In-Tank Pumps datasheet (W00031-161-PR-DS-002).

13.7.3.2 Sendout Pumps

Refer to P&IDs W00031-000-PR-PI-013/014/015/016/017.

The five send-out pumps will take their feed from the BOG condenser LNG outlet orbypass line. The send-out pumps will discharge the LNG at approximately 1,320 psia

to the vaporizers. At the normal send-out rate of 1,963,390 lb/h, four send-out

pumps (each capable of pumping 2398 gpm of LNG) will be required to operate(leaving one pump as spare).

The send-out pumps will be designed to provide vapor send-out from BradwoodLanding to deliver to the Williams Northwest Pipeline at a pressure of 960 psig.

Each send-out pump will be provided with a recycle (kick-back) loop back to the

LNG storage tanks to ensure the pumps do not operate below their minimum safeflow.

The main technical characteristics of the send-out pumps are as follows:

Manufacturer: Ebara or similar Service: LNG Suction Pressure (min/max): 116 / 225 psia Rated Discharge Pressure: 1320 psia Motor Size: 2335 HP

See Appendix B13 for Sendout Pumps Datasheet (W00031-561-PR-DS-004).

13.7.3.3 Submerged Combustion Vaporizers

Refer to P&ID W00031-000-PR-PI-020 as typical.

The Terminal operates using 7 submerged combustion vaporizers to re-gasify the LNG.The vaporizers are arranged in parallel. Under normal operation, only 6 units are in

operation. The remaining unit, acts as a spare to enable ongoing maintenance, change

out of water baths and to cover single unit downtime without impacting on terminalsend-out capacity.


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LNG is converted to natural gas in the vaporizers, which operate at approximately

1,291 psia. (NOTE. Due to the fact that the vaporizers operate at a pressure abovethe critical point, there is no vaporization in the conventional sense and no 2-phase

region in the vaporizers.)

The minimum gas send-out temperature from the terminal is 40F. At minimum send-out rates where send-out pressure is throttled (reduced pipe friction losses) the LNG

outlet temperature of the SCVs can be increased to compensate for Joule-Thompson

cooling by increasing the water bath temperature. No trim heating system is required.

The SCVs are fuelled by send-out gas. A fuel gas system controls the pressure andsupply of the fuel gas to ensure continuous SCV operation. Approximately 1% (w/w)

of the LNG send-out is used in the vaporization of the LNG. Fuel gas is burnt undertemperature control in order to maintain the temperature of a water bath. The

combustion products of the fuel gas are forced through the water bath, thus heating

the bath. The LNG passes through the water bath in high-pressure tubing and

approaches the water bath temperature (typically 68F). A typical design of thecontrol system and piping layout along with a general arrangement of the actual heatexchange water bath is shown on pages 16 and 17. The individual gas lines at the inlet

and discharge of each SCV unit each have emergency shutdown values to prevent

unwanted discharge of gas. These valves are synchronized to prevent LNG beingtrapped.

As the combustion products are forced through the water bath, carbonic and nitric

acid are formed. The water of combustion condenses, increasing the volume of waterin the bath. This excess water passes to an overflow. The caustic recirculation system

doses caustic to the overflow from each of the SCV water baths under pH control from

a sensor in each SCV water bath to counteract the fall in pH resulting from thedissolved acids. This creates sodium carbonate and sodium nitrate in solution. The

water bath continuously overflows into the effluent pit, where the pH levels aremonitored, before pumping the effluent into the river via a diffusion pipe.

Should the pH drop in the effluent pit, the effluent pumps are switched off and

caustic solution is manually added and the agitator is started. Once the pH is neutral,

the pumps can be restarted.

Manufacturer: Selas or Similar Service: LNG Design Pressure (min/max): FV / 274 psig Design Temperature: -274 / 99 oF Flowrate: 186 MMSCFD Heat Duty: 108.9 MMBTU/hr


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See Appendix B13 for SCV Datasheet (W00031-563-PR-DS-007).

13.7.3.4 Operation and Control

The vaporizers are arranged in parallel. Under normal operation, only 6 units are inoperation. The remaining unit, acts as a spare to enable ongoing maintenance, change

out of water baths and to cover single unit downtime without impacting on terminal

send-out capacity.

It is intended that the sequencing of the vaporizer duty cycles will be performedautomatically within the plant DCS.

13.7.4 Vent

Refer to P&ID W00031-000-PR-PI-048.

The vent system is composed of one ignitable vent stack. In normal operation,there will be zero hydrocarbon emissions from the vent; only inert purge gas

(nitrogen) will be vented.

The majority of gas phase pressure reliefs at Bradwood Landing will relieve into the

BOG header. The exceptions are the storage tanks relief valves and the vaporizer

relief valves, which will relieve directly to atmosphere. The advantage of thissystem is that emissions to atmosphere will be minimized.

The ultimate over-pressure protection of the BOG header will be via the tank relief

valves. However, to avoid lifting the tank relief valves and generating a coldrelease, the BOG header will be protected by a pressure controller, which will allow

relief to the process vent, if required.

The vent will be located in a safe (sterile) area to minimize the potential forignition.

The vent will be designed for a maximum rate of 68,670 lb/h (based on minimumsendout case with carrier unloading and BOG Compressors off-line).

See Appendix B13 for Vent Stack datasheet (W00031-768-PR-DS-021).


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13.7.5 Buildings and Piping Structures

13.7.5.1 New Buildings Scope of Work

General

All buildings necessary for operation will be designed to maintain structural integrityin a 150 mph wind speed, exposure C per ASCE 7. All buildings will be designedusing common industry overpressure criteria for facilities of this type. Sanitary waste

will be piped to a separate packaged wastewater treatment units as required.

Seismic design of buildings shall be in accordance with the requirements of the

Uniform Building Code UBC 1997 (supplemented by ASCE Guidelines for SeismicEvaluation and Design of Petrochemical Facilities) and the Code for Seismic Design

of Buildings and the Code for Anti-Seismic Design of Special Structures. Structuralintegrity shall be maintained in the design i.e. the structures and components shall

not collapse or fail under the design basis ground motions.

Warehouse/Administration Building

(Drawing No W00031-800-CI-GA-001) in Appendix B13: 125 feet long by 100 feet wide.The Administration building is 15 feet to eaves and the Workshop building is 30 feet to

eaves. A steel framed building with metal sheeting to roof and sides. A 3 feet high

brick dado wall to be provided around the building perimeter. The Administrationbuilding section will include offices, restrooms, conference room, data storage and

kitchen. A 5-ton SWL electrically operated overhead traveling crane shall be providedin the Workshop/Warehouse area. The laboratory is located in the

Workshop/warehouse. A switchroom is to be provided in one corner of the Warehousewith Transformer pens located immediately outside. The Building will include interior

finishes, HVAC, fire protection (sprinkler system), lighting, building electrical and

plumbing.

Control Building

(Drawing No W00031-800-CI-GA-002) in Appendix B13: Blast resisting design, 75 feet

long by 63 feet wide single storey blast resisting designed building, elevated 6 feetabove grade. The building should comprise a reinforced concrete framed structure

with infill masonry panels (reinforced as necessary) rendered externally and plastered

internally. Flat roofs shall be designed to be waterproof using an inverted roof

system where the waterproof roofing membrane is positioned below an insulationlayer, protected from solar radiation and subject to minimum temperature variation.Building will include an I/O room switchroom/plantroom, battery room, control room,

restrooms, offices and kitchen area. Transformer Pens are to be located outside the

building adjacent the switchroom/plantroom. Building work will include all interiorfinishes, HVAC, lighting, building electrical, fire/smoke detection & protection and

plumbing.


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Instrument Air Package Shelter

(Drawing No W0

LNG Terminal Design

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