LNG Terminal Design

BRADWOOD LANDING TERMINAL

Resource Report 13 Engineering and Design Material

SUBMITTED BY NORTHERN STAR NATURAL GAS LLC

Rev 2 16th May 2006

RESOURCE REPORT 13 ADDITIONAL INFORMATION RELATED TO LNG PLANTS CONTENTS 13

INTRODUCTION

13-1

13.1 13.1.1 13.1.2 13.1.3 13.1.4 13.1.5 13.1.6 13.1.7 13.1.8 13.1.9 13.1.10 13.1.11 13.1.11.1 13.1.11.2 13.1.11.3 13.1.11.4 13.1.11.5 13.1.11.6 13.1.11.7

SITE PLAN Siting Thermal Radiation Protection Flammable Vapour Dispersion Protection Seismic Design Investigation and Design Forces Flooding Soil Characteristics Wind Forces Other Severe and Natural Conditions Adjacent Activities Separation of Facilities Site Development Grading and Excavation LNG Tank Impoundment Drainage and Storm Water Run-off Spill Containment Foundations Roads Site Surface Treatment

13-1 13-2 13-2 13-2 13-3 13-5 13-5 13-6 13-7 13-7 13-8 13-8 13-8 13-9 13-9 13-10 13-10 13-11 13-11

13.2 13.2.1 13.2.1.1 13.2.1.2 13.2.2 13.2.3 13.2.4 13.2.5

FIRE PROTECTION SYSTEM Firewater System Firewater System Components Firewater Piping Dry Chemical Extinguishers High Expansion Foam System Portable Fire Extinguishers Fireproofing and Siren

13-12 13-12 13-12 13-14 13-14 13-14 13-15 13-15

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13.3 13.3.1 13.3.2 13.3.2.1 13.3.2.2 13.3.3 13.3.3.1 13.3.3.2 13.3.3.3 13.3.3.4 13.3.4

HAZARD DETECTION SYSTEM General Monitoring Equipment Gas Detectors Low Temperature Detectors Fire Detectors General Smoke Detectors High Temperature Detectors Visual Monitoring Fire and Hazardous Gas Detection System

13-15 13-15 13-17 13-17 13-17 13-17 13-17 13-18 13-18 13-18 13-18

13.4 13.4.1 13.4.2 13.4.3 13.4.4

SPILL CONTAINMENT SYSTEM Spill Containment Tanks Spill Containment Tank and Vaporizer Area Spill Containment Jetty Area Spill Containment General

13-19 13-19 13-19 13-20 13-20

13.5

SHUT-OFF VALVES

13-20

13.6

DESIGN PLANNING

13-21

13.7 13.7.1 13.7.1.1 13.7.2 13.7.2.1 13.7.2.2 13.7.2.3 13.7.2.4 13.7.3 13.7.3.1 13.7.3.2 13.7.3.3 13.7.3.4 13.7.4 13.7.5 13.7.5.1 13.7.5.2

MAJOR PROCESS COMPONENTS Marine Facilities Carrier Unloading Arms LNG Un-loading Operation Vapour Return Blowers Knockout Drum BOG and Vapour Handling System Boil-off Gas Compressor BOG Condenser LNG Sendout System In-tank LNG Pumps Sendout Pumps Submerged Combustion Vaporizers Operation and Control Vent Buildings and Piping Structures New Buildings – Scope of Work Structural Piperacks

13-22 13-22 13-25 13-26 13-27 13-27 13-29 13-30 13-31 13-31 13-32 13-32 13-33 13-34 13-34 13-34 13-37

13.8 13.8.1 13.8.2 13.8.3 13.8.4 13.8.5 13.8.6 13.8.7

LNG STORAGE TANKS General Tank Foundation Outer Tank Inner Tank Seismic Loads on Inner and Outer Tanks Wind Loads on Outer Tank Insulation System

13-37 13-37 13-39 13-39 13-40 13-40 13-41 13-41

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13.8.8 13.8.8.1 13.8.8.2 13.8.8.3 13.8.8.4 13.8.8.5 13.8.8.6 13.8.8.7 13.8.8.8 13.8.8.9 13.8.9 13.8.9.1 13.8.9.2 13.8.9.3 13.8.9.4 13.8.9.5 13.8.10 13.8.10.1 13.8.10.2 13.8.10.3 13.8.11 13.8.12 13.8.13 13.8.14 13.8.15 13.8.16 13.8.16.1 13.8.16.2 13.8.16.3 13.8.16.4 13.8.16.5 13.8.16.6 13.8.17

Tank Instrumentation Cooldown Sensors Temperature Sensors Liquid Level Instruments Tank Gauging, Density and Overfill Protection Requirements Density Monitoring Liquid Temperature Measurements Pressure & Vacuum Relief Systems Settlement Monitoring Inner and Outer Tank Relative Movement Indicators Fittings, Accessories, Tank Piping Roof Platforms Cranes / Hoists Intank Pump Columns Tank Internal Piping Tank External Piping Stairways and Platforms Access to Platform and Roof Internal Tank Ladder Walkways and Handrails Cryogenic Spill Protection Painting Tank Lighting and Convenience Receptacles Electrical Grounding Welding Testing and Inspection Alloy Verification Radiography Liquid Penetrant Examination Vacuum Box Testing Hydrotesting of Inner Tank Pressure and Vacuum Testing Procedures for Monitoring and Remediation of Stratification

13-42 13-42 13-43 13-43 13-43 13-43 13-44 13-44 13-44 13-44 13-44 13-44 13-45 13-45 13-45 13-45 13-46 13-46 13-46 13-46 13-47 13-47 13-47 13-47 13-47 13-48 13-48 13-48 13-48 13-48 13-49 13-49 13-49

13.9 13.9.1 13.9.2 13.9.2.1 13.9.2.2 13.9.3 13.9.4 13.9.4.1

PIPING AND INSTRUMENTATION Piping and Instrumentation Drawings Process Control Distributed Control System Control – Communication Network Emergency Shutdown System Analysis Instrumentation Gas Chromatograph

13-49 13-49 13-49 13-50 13-52 13-53 13-54 13-54

13.10 13.10.1 13.10.2 13.10.3 13.10.4

ELECTRICAL SYSTEMS General Area Classification Voltage Levels Utility and Generator Power Supply

13-54 13-54 13-55 13-55 13-55

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13.10.5 13.10.6 13.10.7 13.10.8 13.10.9 13.10.10 13.10.11 13.10.12

Switchgear and Motor Control Centres Load Shedding Wiring Electric Motors Exterior Lighting Grounding Lightning Protection Uninterruptible Power Supply

13-56 13-56 13-57 13-57 13-57 13-57 13-58 13-58

13.11

DESIGN CODES AND STANDARDS

13-59

13.12

PERMITS AND APPROVALS

13-59

13.13 13.13.1 13.13.2 13.13.3 13.13.3.1 13.13.3.2 13.13.3.3 13.13.3.4 13.13.3.5 13.13.3.6 13.13.3.7 13.13.3.8 13.13.3.9 13.13.3.10 13.13.3.11 13.13.3.12 13.13.3.13 13.13.3.14 13.13.3.15 13.13.3.16 13.13.3.17 13.13.3.18 13.13.4 13.13.4.1 13.13.4.2 13.13.4.3 13.13.4.4 13.13.4.5 13.13.4.6 13.13.4.7 13.13.4.8 13.13.4.9 13.13.4.10 13.13.4.11 13.13.4.12

REGULATORY COMPLIANCE 49 CFR Part 193 NFPA 59A Additional Responses to 49 CFR Part 193 193.2051 – Scope 193.2199 – Records 193.2155 – Structural Requirements 193.2187 – Non-metallic Membrane Liner 193.2301 – Scope 193.2303 – Construction Acceptance 193.2304 – Corrosion Control Overview 193.2321 – Non-destructive Tests 193.2401 – Scope Sub-part F – Operations 193.2511 – Personnel Safety 193.2521 – Operating Records Sub-part G – Maintenance 193.2619 – Control Systems 193.2639 – Maintenance Records Sub-part H – Personnel Qualifications and Training Sub-part I – Fire Protection Sub-part J – Security Additional Responses to NFPA 59A 2-4 Designer and Fabricator Competence 2-5 Soil Protection for Cyrogenic Equipment 2-6 Falling Ice and Snow 2-7 Concrete Materials 3-1 Process Systems – General 3-2 Pumps and Compressors 3-3 Flammable Refrigerant and Flammable Liquid Storage 3-4 Process Equipment 4-1 Stationary LNG Storage Containers – General 4-2 Metal Containers 4-3 Concrete Containers 4-4 Marking of LNG Containers

13-59 13-59 13-59 13-59 13-59 13-59 13-60 13-60 13-60 13-60 13-60 13-60 13-60 13-61 13-61 13-61 13-61 13-62 13-62 13-62 13-62 13-62 13-63 13-63 13-63 13-63 13-63 13-63 13-64 13-64 13-64 13-64 13-64 13-64 13-64

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13.13.4.13 13.13.4.14 13.13.4.15 13.13.4.16 13.13.4.17 13.13.4.18 13.13.4.19 13.13.4.20 13.13.4.21 13.13.4.22 13.13.4.23 13.13.4.24 13.13.4.25 13.13.4.26 13.13.4.27 13.13.4.28 13.13.4.29 13.13.4.30 13.13.4.31 13.13.4.32 13.13.4.33 13.13.4.34 13.13.4.35

4-6 Container Purging Procedures 13-65 4-8 Relief Devices 13-65 5-6 Products of Combustion 13-65 6-1 Piping Systems and Components – General 13-65 6-2 Materials of Construction 13-65 6-3 Installation 13-66 6-4 Pipe Supports 13-66 6-5 Piping Identification 13-66 6-6 Inspection and Testing of Piping 13-66 6-7 Purging of Piping Systems 13-66 6-8 Safety and Relief Valves 13-67 6-9 Corrosion Control 13-67 7-7 Electrical Grounding and Bonding 13-67 8-2 Piping System 13-67 8-3 Pump and Compressor Control 13-68 8-4 Marine Shipping and Receiving 13-68 8-5 Tank Vehicle and Tank Car Loading and Unloading Facilities 13-68 8-9 Communications and Lighting 13-68 9-7 Maintenance of Fire Protection Equipment 13-68 9-9 Personnel Safety 13-68 9-10 Other Operations 13-68 4-7 Cooldown Procedures 13-69 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 Detectors

Table 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 overview information 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 compliant design, 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. The additional 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 gas from 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 a new 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 carriers per 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 been allocated for a third LNG tank of identical size for future expansion to 1.5 bcfd Northern Star 13-1

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. Compliance with 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 an emergency situation. Drawings referenced in this section are included in Appendix A13. Factors considered during site selection and design, as listed in 49 CFR 193 Subpart B and NFPA 59A include: • • • • • • • • • • 13.1.2

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. Thermal Radiation Protection

Calculations have been made, by Whessoe Oil and Gas Limited, in relation to thermal radiation (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 and Gas 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 in Appendix 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 the collection and review of available information on the geology, tectonics, seismicity, and tsunami potential of the region. The information was used to (1) determine the presence and character of any potentially active faults and the potential for surface rupture 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 Shutdown Earthquake (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 other structures 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 345-0210010 (Site Characterisation – Exhibits H and I), OAR 345-022-0020 (Structural Standard), and OAR 345-022-0022 (Soil Protection). These reports also comply with the 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. Northern Star 13-3

Recommended OBE and SSE The OBE and SSE design response spectra were established per the requirements in the 2001 NFPA 59A Standard. The response spectra are for horizontal and vertical components of motion and damping ratios ranging from 0.5% to 20%. These response spectra represent a bedrock outcrop motion at the top of the Columbia River Basalt Unit underneath the site. The 5% damped OBE design response spectrum recommended for horizontal components had a zero-period ordinate of 0.20 g, which is the PGA, and a constant spectral acceleration of 0.50 g for periods between 0.1 and 0.4 sec. In the period ban, 0.1 to 2.0 sec, this design response spectrum is approximately 30 to 70 percent greater than the site-specific, 475-yr uniform hazard spectrum computed for the site. Vertical-component (V) response spectra equal to two-thirds (2/3) of the horizontal component (H) response spectra are recommended. This V/H ratio is conservative based on ground motions recorded during subduction-zone earthquakes which indicate V/H ratios of around one-half (1/2). Scale-factor formulas are presented to convert the 5% damped design response spectra to response spectra at other damping ratios. The average 0.5% damped OBE spectral displacement of 50 cm was recommended for periods T ≥ 8 sec, and is to be used in response calculations associated with the fundamental convective mode of the LNG fluid. The recommended SSE design response spectra are twice the corresponding OBE response spectra. Recommended OSSC Parameters Seismic ground-motion parameters, SDS = 0.54 and SDI – 0.41, were determined per the provisions of the 2004 Oregon Structural Specialty Code (OSSC), which is essentially the 2003 International Building Code (IBC). The values were recommended based on the results of site-response analysis with the ProShake and FLAC computer codes. The representative soil profile for this analysis was constructed from data collected during the URS (2005) Geotechnical Investigation. Tsunami and Seiche Evaluation Northern Star 13-4

Tsunami waves may enter the Columbia River from distant circum-Pacific earthquakes, local offshore earthquakes, or submarine landslides in the adjacent Pacific 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 in the 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 is minimal, 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 BFE’s (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 tanks are also surrounded by a tertiary bund that has an elevation of 35.5 ft above CRD. 13.1.6

Soil Characteristics

An initial geotechnical investigation of the Bradwood Landing site was conducted by URS Consulting, Inc. The results of this investigation are included in the report, “Draft Preliminary 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 for the proposed Liquefied Natural Gas (LNG) Import in Bradwood, Oregon. The development will include two 75-meter (246-foot) diameter LNG storage tanks with infrastructure 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, by high 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 Northern Star 13-5

penetration tests, and seismic-velocity testing. The installation of driven wood piles along the northeast shoreline in the early 1960’s resulted in deposition that currently forms the portion of the site outboard of the log pond at the Bradwood site. Most of the 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 by stockpiles 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 soft fills 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 ground surface (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). This package 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 of between 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 granular materials 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 from lateral spreads in addition to meeting the stringent static-settlement criteria for the proposed LNG tanks and other major structures. Foundation options satisfying these requirements include driven steel pipe piles, augercast piles, and driven grout pile systems. The analysis results and recommendations provided herein should be further refined 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 speeds referenced 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 from other 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 designed for a minimum temperature of -5° Fahrenheit (°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 Terminal and by maintaining adequate trained personnel and firefighting equipment onsite. The northern boundary of the site is the Columbia River. The western boundary is a cliff face 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 than down 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 than adequate separation between the forest and the terminal fence line. Much of the vegetation opposite the southern boundary is within the Hunt Creek estuary, which is basically 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 catch fire, 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 to approach the facility, the plant personnel would have the required training and firefighting 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 the Wauna 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. The channel 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 is extremely small because of the physical orientation of the channel and the surrounding 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 Facilities

As depicted on the site plan drawing W00031-0011-CI-LO-002, included in Appendix A13, 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.

Spill Containment

Will be provided under all piping and equipment handling LNG throughout the facility

Spill Containment

All impoundment areas will be at least 50 feet from the property line or a navigational waterway

Spill Containment

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. Will be located at least 100 feet from the property line and at least 50 feet from any source of ignition.

Vaporizers

13.1.11

Site Development

13.1.11.1

Grading and Excavation

The areas within the Project site required for the construction of the terminal will be leveled 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 be minimized. The following is a general description of the sitework necessary to fill and grade the existing site to the proposed levels above Columbia River Datum (CRD). Site filling requirements will be as specified in the geotechnical investigation reports by URS Corporation, 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 asphalt surfaced roads, gravel surfaced roads, general gravel surfacing and application of top soils, seeding and mulching for grass areas. Wherever possible the existing drainage patterns will be retained. NSNG will adopt FERC’s 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 potential effects 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 concrete outer 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. All penetrations will be through the concrete dome roof. In addition a Tertiary earth bund will be provided with storage capacity equal to the volume of 1 no Tank.

13.1.11.3

Drainage and Storm Water Run-off

The facility is designed to provide drainage of surface water to designated areas for disposal. 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 via swales and open channels and directed to the 2 no Spill impoundment basins. Northern Star 13-9

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 low temperature 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 to the level of the w ater table by gravity. Storm water that falls within the site area and not in the impoundment areas is expected 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 a disposal well. Waste water generated from personnel use will be treated in a septic system. 13.1.11.4

Spill Containment

Construction 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 hazardous material within 100 feet of any water body or wetland. A spill prevention control and countermeasures (SPCC) plan for the construction activities will be developed in accordance with 40 CFR Parts 122 through 124. 13.1.11.5

Foundations

Buildings, process equipment, and pipe rack foundations will be supported with mass concrete foundations. Materials for the concrete will conform to the American Society for Testing and Materials (ASTM) and other recognized standards where applicable. 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 be according 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. Northern Star 13-10

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-011 are included in Appendix B13. 13.1.11.6

Roads

Bradwood Landing’s roads will consist of gravel surfaced and asphalt surfaced roads as shown 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 in Appendix B13. 13.1.11.7

Site Surface Treatment

Surface treatment drawings will be prepared, which will designate treatments for each 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 Bradwood Landing from the river.

Northern Star 13-11

13.2

FIRE PROTECTION SYSTEM

The proposed terminal has a number of independent fire protection systems. These include i) ii) iii) iv)

A fire water main capable of servicing hydrants, monitors, the jetty spray curtain, and individual equipment spray protection. High expansion foam system for protection of the spill impoundment basins. Dry chemical extinguishers to enable a fire within the relief valve discharge piping to be extinguished automatically. Portable fire extinguishers throughout the terminal, along with Fireproofing.

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 Appendix A13 and the Fire Protection Evaluation Philosophy, document number W00013-000-PRDB-008. The following codes were referred to in the design of the fire water system: • • • • • •

13.2.1.1

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 Firewater System Components

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

The main components of the Firewater system are:Northern Star 13-12

• • • • • • • •

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. Each firewater pump is designed to supply 4400 gpm (1000 m³/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 the extremities 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 pressure drops 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 pressure within 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 minimum pressure required at each spray system / monitor the main firewater pumps are activated. Bradwood Landing is divided into fire areas. Single spray systems and monitors connected 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 of multiple 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 diesel can be supplied either from storage or from an offsite supply (tanker) within this Northern Star 13-13

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 in specification 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 all aboveground 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 piping then 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 LNG tank. Should the discharge from one of these PRV’s become ignited a jet flame will be induced. Dry chemical extinguishers are fitted to each of the PRV’s 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. Each extinguisher 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 spill impoundment 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 a one 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.

Northern Star 13-14

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 (~400m²) in area. Both packages include the ability to be tested periodically. 13.2.4

Portable Fire Extinguishers

Approximately 16 portable fire extinguishers will be provided throughout the terminal. 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 access areas to allow easy access in the event of an emergency. In addition approximately 15 wheeled 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 cannot be 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 and emergency 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 for combustible 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, numerous field mounted instruments connected to remote input/output (IO) cabinets and operator interface stations (HMI) located in the control rooms.

Northern Star 13-15

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&ID’s 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 office and 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 and number of all detectors for flame, gas and smoke, also shows location of the CCTV cameras, manual call points and Emergency Shutdown (ESD) pushbuttons. a) b) c) d) e) f) g) h) i) j)

Smoke Detection Layout W00031-840-IN-LO-001 CCTV Layout W00031-840-IN-LO-002 Macs (Call Points) Layout W00031-840-IN-LO-003 Point Gas Detection Layout W00031-840-IN-LO-004 Open Path Gas Detection Layout W00031-840-IN-LO-005 Flame Detection Layout W00031-840-IN-LO-006 Low Temp./ Cold Detection Layout W00031-840-IN-LO-007 Water / Foam Delivery Layout W00031-840-IN-LO-008 Fire Extinguishers Layout W00031-840-IN-LO-009 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). Northern Star 13-16

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 shall consist of flammable gas and flame detection. Quantities and locations will be as detailed on the Instrument Plan Drawings included in Appendix A13. F&G detectors will only activate alarm systems and will not operate or initiate any terminal shutdowns other than those associated with equipment room heating and ventilation systems. Operators in any of the control rooms would take the appropriate actions 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 the Instrument Plan Drawings included in Appendix A13. 13.3.2.2

Low Temperature Detectors

Low temperature sensors are located in the spill impoundment basin to shutdown and prevent 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

General

Smart ultra-violet / infrared (UV/IR) monitors will be installed throughout the terminal. A portable rechargeable battery operated test lamp will be included for future field verification and calibration needs. Sensors will be located throughout the terminal as detailed on the Instrument Plan Drawings included in Appendix A13..

Northern Star 13-17

13.3.3.2

Smoke Detectors

Smoke Detectors will be provided in buildings where early detection of smoke is critical 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-checking circuitry to ensure a highly reliable operation with compensation for accumulation of dust 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 Monitoring

Visual 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 unloading arms, 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 Detection

F&G area monitoring equipment will be installed to provide detection of flammable hydrocarbon releases or ignitions. The F&G system will be integrated into the SIS.

Northern Star 13-18

13.4

SPILL CONTAINMENT SYSTEM

13.4.1

Spill Containment Tanks

LNG 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 container is sized to hold the contents of the tank and acts as the tank’s impoundment. All penetrations 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 and W00031-0011-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 line and 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 the impoundment 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 be routed to the impoundment basin by a collection trough. The largest LNG volume in the tank area is from the unloading line during an unloading 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 maximum unloading 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 for containment 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. Northern Star 13-19

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 to determine the most severe design spill in order to design a suitable containment system. The largest LNG volume in the jetty area is from the unloading line during an unloading 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 maximum unloading 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 sump capacity of 538,632 gallons. The capacity of the sump is therefore acceptable for containment 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 of 40N/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 anticrack 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 plant construction 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 VALVES

The jetty will have isolation valves, which will be closed on ESD. The valves will be fire 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 Northern Star 13-20

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 to reactivation. The valves will also be equipped with position switches, which will display 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, and cryogenic service. All cryogenic ESD valves will be butt-welded to process piping. The ESD v alves are shown on the P&IDs included in Appendix A13. and in Table 13.3-1. 13.6

DESIGN PLANNING

The general design approach to the Project is to provide a safe, efficient, easily operable 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, American Petroleum 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.

Northern Star 13-21

13.7

MAJOR PROCESS COMPONENTS

During the initial Engineering Design the major considerations taken with regard the type of equipment selection for the Project are: • • • • • • • •

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

Major process compone nts are shown on the Process Flow Diagram (PFD) W00031-000PR-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 temporary mooring 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 an approximate unloading time of 18 hours at Bradwood Landing and full turnaround time 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 navigation channel 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 closely monitored 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 a depth 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 Northern Star 13-22

(the US Army Corps of Engineers’ Columbia River Federal Navigation Channel Improvement Project) is currently underway to deepen the existing 40-foot deep shipping channel by 3 feet to allow continued navigation access. Work to deepen the navigation 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 navigation channel. 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 650,000 cubic 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 of 100,000 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. The breasting 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 at each 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 points comprising 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) and on 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 the structures 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 the safe navigation of vessels on the Columbia River. The mooring hooks will be provided with strain gauges enabling measurement of the forces 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 monitored at 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 monitored until the Carrier is safely berthed. The two extreme up and downriver mooring dolphins will each be provided with a navigation light marking the extent of the structure in the river.

Northern Star 13-23

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 and pipework 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. Drainage from 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 trough such that any liquid escape dropping into the trough will be directed to 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 four marine 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 a problem 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 joints to 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 the shipside 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 a combined 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. The berth layout was first reviewed by experienced pilots, and changes made based on their recommendations. The final berth layout was then successfully confirmed in computer 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 in Resource Report 11.

Northern Star 13-24

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 onshore 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), International Navigation Association (PIANC), American Petroleum Institute (API), and American Society of Civil Engineers (ASCE). 13.7.1.1

Carrier Unloading Arms

Refer to P&ID’s 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. The transfer 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 the carrier 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 by means 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 hybrid arm) 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: Service: Unloading Arm Size: Design Temperature: Range of Carrier Capacities:

FMC Energy Systems or similar Natural Gas / LNG 16 in –274 oF / +99 oF 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. Northern Star 13-25

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 carrier’s on-board pumps. Cool-down of the unloading arms and the auxiliary equipment will be started from the carrier, after which the LNG pumping rate will gradually be ramped-up until the maximum 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 psig during 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 of the storage tanks via 32” pipes. The tanks can either be top or bottom filled depending on the compositions of the tank contents and the fresh cargo from the carrier. 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 lines will 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 vapor return 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 flow will adjust itself naturally to match the carrier’s 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 -220°F by injecting LNG into the vapor. LNG for desuperheating will be supplied from the jetty transfer line. A vapor return KO 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 act as a drain pot for the unloading arms. The carrier’s tank level gauges will be used for the fiscal measurement of the total cargo transferred from the carrier to the storage tanks. The LNG unloaded at Bradwood Landing from a carrier will be sampled on-line and analyzed for composition. 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 be installed on the unloading line to accomplish this.

Northern Star 13-26

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 greater than a 4°F 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 isolation valves for isolating the carrier supply in case of an emergency situation. During normal operation (when no carrier is berthed), the unloading lines will be kept cold by circulating LNG liquid from the send-out system to the jetty head via the recirculation 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 from the 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 with nitrogen. 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-DS013). 13.7.2.2

BOG and Vapor Handling System

The BOG and vapor handling system is detailed in P&ID’s W00031-000-PR-PI008/009/010/011. The vapor handling system will be essentially comprised of:-

Northern Star 13-27

• • •

Vapor handling pipework BOG compressors BOG condenser

The function of the vapor handling pipework is to provide a safe conduit for the vapors 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 is equipped 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 to control 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 is necessary 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 the unloading 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 the upper 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 carrier’s boil-off) will flow to the vapor recovery system. When there is no carrier unloading, the volume of LNG sent out from the storage tanks 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 the tanks to the vapor recovery system. Northern Star 13-28

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 the BOG compressors. In the BOG condenser, the boil-off gas will be contacted with LNG from the in-tank pumps 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 gas to 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 safety valves. 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 periods of 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 BOG Compressors 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 -250°F to avoid unacceptably high discharge temperature when the compressor is operating at its maximum 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 suction pipework, 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: Serv ice: Suction Pressure:

Burckhardt Corporation/IHI or similar Natural Gas 18.2 psia at –251 oF

Northern Star 13-29

•

Rated Discharge Pressure:

116 psia

See 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 and buffer 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 contact with 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 coming from 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 to heat 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 the condenser 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 to maintain 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 restore the 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 liquid buffer 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 with adequate NPSHA assuming the handling of boiling liquid.

Northern Star 13-30

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&ID’s 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 LNG tanks to be installed initially) to the BOG condenser (or bypass) and on to the sendout 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 pumps will 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 for tank 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

Northern Star 13-31

•

Motor Size

265 HP

See Appendix B13 for LNG In-Tank Pumps datasheet (W00031-161-PR-DS-002). 13.7.3.2

Sendout Pumps

Refer to P&ID’s W00031-000-PR-PI-013/014/015/016/017. The five send-out pumps will take their feed from the BOG condenser LNG outlet or bypass 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 Bradwood Landing 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 safe flow. The main technical characteristics of the send-out pumps are as follows: • • • • •

Manufacturer: Service: Suction Pressure (min/max): Rated Discharge Pressure: Motor Size:

Ebara or similar LNG 116 / 225 psia 1320 psia 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 terminal send-out capacity. Northern Star 13-32

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 above the 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 40°F. At minimum sendout rates where send-out pressure is throttled (reduced pipe friction losses) the LNG outlet temperature of the SCV’s can be increased to compensate for Joule-Thompson cooling by increasing the water bath temperature. No trim heating system is required. The SCV’s are fuelled by send-out gas. A fuel gas system controls the pressure and supply of the fuel gas to ensure continuous SCV operation. Approximately 1½% (w/w) of the LNG send-out is used in the vaporization of the LNG. Fuel gas is burnt under temperature 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 68°F). A typical design of the control system and piping layout along with a general arrangement of the actual heat exchange 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 being trapped. 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 water in 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 the dissolved acids. This creates sodium carbonate and sodium nitrate in solution. The water bath continuously overflows into the effluent pit, where the pH levels are monitored, 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: Service: Design Pressure (min/max): Design Temperature: Flowrate: Heat Duty:

Selas or Similar LNG FV / 274 psig -274 / 99 oF 186 MMSCFD 108.9 MMBTU/hr

Northern Star 13-33

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 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 terminal send-out capacity. It is intended that the sequencing of the vaporizer duty cycles will be performed automatically 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 this system 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 cold release, 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 for ignition. The vent will be designed for a maximum rate of 68,670 lb/h (based on minimum sendout case with carrier unloading and BOG Compressors off-line). See Appendix B13 for Vent Stack datasheet (W00031-768-PR-DS-021).

Northern Star 13-34

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 integrity in a 150 mph wind speed, exposure “C” per ASCE 7. All buildings will be designed using 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 Seismic Evaluation and Design of Petrochemical Facilities’) and the “Code for Seismic Design of Buildings” and the “Code for Anti-Seismic Design of Special Structures”. Structural integrity 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 Administration building section will include offices, restrooms, conference room, data storage and kitchen. A 5-ton SWL electrically operated overhead traveling crane shall be provided in the Workshop/Warehouse area. The laboratory is located in the Workshop/warehouse. A switchroom is to be provided in one corner of the Warehouse with 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 feet above 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 insulation layer, 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 interior finishes, HVAC, lighting, building electrical, fire/smoke detection & protection and plumbing. Northern Star 13-35

Instrument Air Package Shelter (Drawing No W00031-800-CI-GA-003) in Appendix B13: This Building is a pre-fabricated structural steel framed structure with Metal sheeting to roof only. The sides of the building are to be left unclad and a ridge vent is included for maximum ventilation. Building plan 33 feet by 23 feet by 15 feet to eaves. Switchroom A (Drawing No W00031-800-CI-GA-005) in Appendix B13: Blast resisting design, this Building is to consist of a reinforced concrete structural support frame with reinforced concrete roof and foundation system. All walls internal and external are to be concrete blockwork and rendered. Building Plan 64 feet by 24 feet by 15 feet floor to eaves. The floor of the switch room is to be elevated 3 feet above general grade. Work will include a fresh air-intake duct to bring fresh air to building envelope. Building work will include all interior finishes, HVAC, fire/smoke detection, lighting, and building electrical. Switchroom B (Drawing No W00031-800-CI-GA-006) in Appendix B13: Blast resisting design, this building is to consist of a reinforced concrete structural support frame with reinforced concrete roof and foundation system. All walls internal and external are to be concrete blockwork and rendered. Building Plan 80 feet by 24 feet by 15 feet floor to eaves. The floor of the switch room is to be elevated 3 feet above general grade. Work will include a fresh air-intake duct to bring fresh air to building envelope. Building work will include all interior finishes, HVAC, fire/smoke detection, lighting, and building electrical. PFC Room (Power Factor Correction) 2 No Required (Drawing No W00031-800-CI-GA-007) in Appendix B13: Blast resisting design, this Building is to consist of a reinforced concrete structural support frame with reinforced concrete roof and foundation system. All walls internal and external are to be concrete blockwork and rendered. Building Plan 25 feet by 13.5 feet by 12 feet floor to eaves. The floor of the PFC room is to be elevated 3 feet above general grade. Work will include a fresh air-intake duct to bring fresh air to building envelope. Building work will include all interior finishes, HVAC, fire/smoke detection, lighting, and building electrical. Compressor Building (Drawing No W00031-800-GA-008) in Appendix B13: Compressor Building is a prefabricated steel frame building with metal sheeting to roof and walls together with acoustic panels, if required for noise attenuation. Building size is 56' x 125' x 50’ to eaves. Crane hook height is required to be 42' min. above the floor level. The building will include a 10-ton electric operated bridge crane. The base of the building will be at grade, however the bases of the compressors and access platforms will be elevated to 3 feet above grade.

Northern Star 13-36

Jetty Control/Switch Room (Drawing No W00031-800-CI-GA-009) in Appendix B13. The building shall 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 w aterproof using an inverted roof system where the waterproof roofing membrane is positioned below an insulation layer, protected from solar radiation and subject to minimum temperature variation. Building plan size is 24' x 28' with a 12' eaves height and should include control room, battery/UPS room, I/O room. Work will include a fresh air-intake duct to bring fresh air to building envelope and all interior finishes, HVAC, fire/smoke detection, lighting, and building electrical. Firewater Pumphouse (Drawing No W00031-800-CI-GA-010) in Appendix B13: Prefabricated steel frame building with metal sheeting together with acoustic panels, if required for noise attenuation. A 5-ton monorail manual hoist and trolley is included. Building plan size is 40' x 30' with a 15' eave height. Gate House / Security Building (Drawing No W00031-800-CI-GA-011) in Appendix B13: This Building is to consist of a reinforced concrete structural support frame with reinforced concrete roof and foundation system. All walls internal and external are to be concrete blockwork and rendered. Building Plan 19.66 feet by 16.42 feet by 13.66 feet high. The building is to include an office/kitchen area, reception and a uni-sex washroom. Building work will include all interior finishes, HVAC, security monitoring, card readers, drive up window in/out to talk to driver and retrieve badges and to have counter for walk in traffic to sign in and obtain badges. Gatehouse to have 2 porte-cocheres for wet weather inspection. 13.7.5.2

Structural Pipe Racks

Piperacks supporting LNG piping will be of reinforced concrete construction, conforming to project specification W00031-000-CI-SP-005) in Appendix B13. Other piperacks will be constructed of structural steel and will conform to Project specification W00031-000-CI-SP-006 included in Appendix B13. See project drawing W00031-030-PI-LO-004 included in Appendix A13, for typical piperack cross-sections.

Northern Star 13-37

13.8

LNG STORAGE TANKS

13.8.1

General

The LNG will be stored in two LNG storage tanks. Each LNG storage tank is a full containment type tank, which will have a primary inner container and a secondary outer container. These tanks will be designed and constructed so that the selfsupporting primary container and the secondary container will be capable of independently containing the LNG. The primary container will contain the LNG under normal operating conditions. The secondary container will be capable of containing the LNG and of controlling the vapor resulting from product leakage from the inner container. The insulated tanks will be designed to store a nominal volume of 160,000 m3 (1,006,000 barrels) of LNG at a temperature of -270°F and a maximum internal pressure of 4.2 pounds per square inch gauge (psig). The double-walled tank will consist of: • • • • •

A 9% nickel steel open top inner container; A prestressed concrete outer container wall; A reinforced concrete dome roof; A reinforced concrete outer container bottom; An insulated aluminum deck over the inner container suspended from the roof.

The aluminum support deck will be insulated on its top surface with fiberglass blanket insulation material. The diameter of the outer container will be approximately 259 feet. The vapor pressure from the LNG will be equalized through ports in the suspended deck and will be contained by the outer container. The internal design pressure of the outer container roof will be 4.2 psig. The space between the inner container and the outer container will be insulated to allow the LNG to be stored at a minimum temperature of -270°F while maintaining the outer container at near ambient temperature. The insulation beneath the inner container will be cellular glass, load-bearing insulation that will support the weight of the inner container and the LNG. The space between the sidewalls of the inner and outer containers will be filled with expanded perlite insulation that will be compacted to reduce long term settling of the insulation. Base heating will be provided in the foundation to prevent frost heave or will be on elevated piles, the exact design to be defined during the design phase. The outer container will be lined on the inside with carbon steel plates. This carbon steel liner will serve as a barrier to moisture migration from the atmosphere reaching the insulation inside the outer concrete. This liner also forms the barrier to prevent vapor escaping from inside the tank in normal operation.

Northern Star 13-38

To increase the safety of the tank there will be no penetrations through the inner container or outer container sidewall or bottom. All piping into and out of the inner or outer containers will enter from the top of the tank. The inner container will be designed and constructed in accordance with the requirements of API Standard 620 Appendix Q. The tank system will meet the requirements of NFPA 59A and 49 CFR Part 193. Refer to Drawing W00031-120-ME-GA001 included in Appendix C13 for general arrangement details. Number of tanks

2

Net capacity of each inner container

160,000 m3 (1,006,000 bbl)

Internal design pressure

4.2 psig

Operating pressure

2.9 psig

Design wind load

150 mph

Seismic zone

ASCE 7 Zone 3

Inner tank minimum design metal temperature

-270°F

Corrosion Allowance of inner container

None

Allowable Boil-off Rate

0.05% per day

13.8.2

Tank Foundation

The storage tank will be built on a reinforced concrete slab supported on a piled foundation as indicated on Drawing W00031-0011-CI-LO-017 included in Appendix C13. 13.8.3

Outer Tank

The outer tank contains the product pressure at ambient temperature and contains the insulation system. The outer tank roof is composed of a butt-welded compression ring and welded steel plates. A deck is suspended from the outer roof with hangers. The deck holds the roof insulation above the inner tank. The outer tank roof and vapor space above the suspended deck are essentially at ambient temperature. A typical cryogenic roof penetration is shown on Drawing W00031-125-ME-DW-005 in Appendix C13. The outer tanks are designed for the following conditions:

Northern Star 13-39

a) The specified internal and external pressures of 4.2 psig and 1.0 ounce per square inch, respectively. b) The specified wind design speed of 150 mph with Exposure C and an Importance Factor, I, equal 1.0 per ASCE-7 and as specified in 49 CFR Part 193, Section 2067. c) Seismic loads in accordance with NFPA 59A and the sitespecific seismic reports. d) Internal pressure imposed by insulation loads. e) Roof and platform dead loads. f) Roof live load of 25 psf applied to the entire projected area of the roof and combined with the specified external pressure of 1.0 ounce per square inch and the platform global live load of 25 psf. g) Platform live load of 75 psf combined with crane handling live load and external pressure load of 0.5 ounce per square inch. Roof live load of 25 psf is not combined with platform live load of 75 psf. The suspended deck will be composed of B209-5083-O aluminum. The suspended deck hangers will be Type 304 stainless steel. 13.8.4

Inner Tank

The inner tank will be designed in accordance with API 620 Appendix Q. The inner tank will be “open top”, consisting of a shell and bottom. The design for the inner tank will not utilize a roof. Gas and gas pressure produced by the stored product will be contained by the outer tank. The inner tank, therefore, will not be subjected to differential gas pressure and will be stressed only by liquid head, insulation loads, earthquake loads, and the effects of thermal gradients. Circumferential stiffeners will be located on the inside of the inner tank shell to resist external insulation pressure. The tank liquid levels will provide a net capacity in the cold condition of at least 160,000 m3 (1,006,000 barrels) tank liquid levels will be as follows: Minimum Normal Operating Level Maximum Normal Operating Level Seismic Design Liquid Level Maximum Design Liquid Level

6.5 ft 125 ft 10½ in 125 ft 10½ in 126 ft 10½ in

The inner tanks will be designed for the following conditions:

Northern Star 13-40

a) Product temperatures and resulting thermal gradients due to cooldown and subsequent filling and emptying operations. b) Internal pressure due to liquid head to the Maximum Design Liquid Level. c) Seismic loads in accordance with NFPA 59A and the site specific seismic reports included in Appendix D13. d) External pressure imposed by insulation loads. The inner tank will be composed of 9% nickel steel A553 Type 1. The inner bottom will be composed of a lap-welded bottom in the tank interior. Details of the inner container are shown on Drawing W00031-120-ME-GA-001included in Appendix C13. 13.8.5

Seismic Loads on Inner and Outer Tanks

For earthquake loading, the inner container will be designed using the methods in API 620. In addition, the operating base earthquake (OBE) and safe shutdown earthquake (SSE) criteria specified in NFPA 59A will be used. The design assumes that the inner container is filled with LNG to its maximum operating level during both OBE and SSE. Horizontal and vertical accelerations will be considered for both OBE and SSE seismic events. Appropriate damping factors will consider soil structure interaction effects. The seismic loading on the base insulation will be also considered. The complete seismic information is available in the Seismic Hazard Report produced by URS Corporation included in Appendix D13. Foundation details are shown on drawing W00031-0011-CI-LO-017 included in Appendix C13. 13.8.6

Wind Loads on Outer Tank

The outer container will be designed to withstand a wind velocity of 150 mph in accordance with CFR Part 193.2067. 13.8.7

Insulation System

The tank insulation system will be designed to limit the tank boil off rate to no greater than 0.05% per day of the tank contents at an ambient temperature of 95°F, with the tank full and in a steady-state condition. Northern Star 13-41

Shell Insulation The annular space between the inner and outer tanks will be approximately 48 in wide. The annular space will be filled with loose fill expanded perlite and resilient glass wool blanket insulation. Expanded perlite insulation is hard, granular material that readily settles, consolidates and builds up lateral pressure in a space that changes dimensions. Perlite density is between 48 lb/ft3 and 65 lb/ft3. The glass wool blanket acts as a spring cushion to accommodate the dimensional changes without compacting the perlite and causing excessive external pressure of the inner shell. An important consideration for the installation of the perlite in the annular space is the perlite vibration after filling. Vibration will be used to settle the perlite to eliminate potential voids or pockets in the perlite volume and maximize the insulating value of the system. A reservoir of perlite will be placed at the top of the annular space to compensate for future, long-term settlement of the perlite. The shell insulation configuration is shown on drawing W00031-101-ME-DW-015 included in Appendix C13. Deck Insulation The outer tank roof will support a suspended deck above the top of the inner tank. The suspended deck will be insulated with glass wool blankets with a density of 0.75 lb/ft3. At each penetration through the suspended deck there will be a flexible shroud fitted to prevent fiberglass material from falling into the inner container. The details are shown on Drawings W00031-101-ME-DW-013 and 014 included in Appendix C13. The suspended deck will be composed of aluminum plate with a series of stiffeners. Hanger bars will attach to the deck stiffeners and roof framing to suspend the deck above the inner tank. The suspended deck and hangers will be designed for product temperatures. The deck hangers will be composed of stainless steel. Bottom Insulation The tank bottoms will be insulated with cellular glass block insulation which is a load bearing insulation designed to support the tank and product weight. The bottom insulation in the tank interior will be composed of two 6” and one 4” layer with a total bottom insulation thickness of 16”. A concrete bearing ring will be located under the inner tank shell to distribute the shell loads into the underlying bottom insulation. The bottom insulation under the inner tank shell will be composed of one 4” layer. The cellular glass blocks will be located between the outer bottom and inner bottom and laid on a concrete leveling course on top of the outer tank bottom. Inter-leaving material will be placed over the concrete leveling course and between bottom insulation layers to fully develop the strength of the load bearing bottom insulation. A layer of dry sand will be placed over the cellular glass block bottom insulation prior to installation of the inner tank bottom. Northern Star 13-42

Details of the proposed bottom insulation system are shown on Drawing W00031-101ME-DW-017 included in Appendix C13. 13.8.8

Tank Instrumentation

Tank instrumentation requirements are shown on the Tank P&ID Drawings W00031-000-PR-PI-067, 068,069 & 070.included in Appendix A13. 13.8.8.1

Cool-Down Sensors

To assist in cool down and subsequent temperature measurement during commissioning and decommissioning of the tank, an adequate number of resistance temperature detector (RTD) elements will be installed. All cabling from these RTD’s will be terminated at a junction box external to the tank roof. 13.8.8.2

Temperature Sensors

Thirteen RTD elements will be placed on the inner shell. Eleven will be placed on the inner container bottom and five will be placed on the suspended deck. These temperature elements will be used to monitor the tank temperature during the cooldown operation. Four RTD’s will be located in the tank bottom annular space for leak detection. They will be spaced equally around the circumference of the tank. Three temperature monitoring RTD’s will be located in the vertical portion of the annular space at two different heights ( six RTD’s in total ). 13.8.8.3

Liquid Level Instruments

The tank will include two liquid level gauges installed in stilling wells. The gauges will be servo-motor operated type, include field indicators and a data transmitter to allow information to interface with the plant DCS system. These particular type gauges have the capability of being retrofitted with a density board to compute product density. 13.8.8.4

Tank Gauging and Overfill Protection Requirements

The above two servo type level gauges are equipped to provide remote reading and high-level alarm signals in the control room. Each gauge will be equipped with a transmitter and threshold contact allowing the reading of low level, normal maximum operating level and high-high level with emergency alarm/trip. Northern Star 13-43

An independent third instrument for level high alarm and level high-high alarm with trips will be provided. The trip switches from this third instrument, along with the other two automatic gauges, will be wired to a safety shutdown system in a two out of three configuration. 13.8.8.5

Density Monitoring

An independent level, temperature, density (LTD) system monitor, with density difference alarm, will be installed. The system will monitor the level verses temperature verses density profile. This device will be utilized to monitor for liquid stratification and potential rollover situations. 13.8.8.6

Liquid Temperature Measurements

Two temperature assemblies will be installed to measure the tank internal contents at predetermined intervals. These temperature signals will be transmitted to the control room via the level system serial link. 13.8.8.7

Pressure and Vacuum Relief Systems

The relief valves will be positioned as shown on drawing W00031-128-ST-GA-001 included in Appendix C13. A monorail crane will be positioned for relief valve service. 13.8.8.8

Settlement Monitoring

A settlement monitoring system will be provided to measure and record inner and outer container movements during construction and hydro test. A minimum of 16 survey/reference points will be equally spaced around the outer edge of the base slab. In addition, settlement of the inner container will be monitored at the same reference points used for the base slab/outer container. Measurement will be made from the inner container annular plate. Also a reference point will be established on the outer container wall to measure differential settlement between inner and outer containers. Differential settlement and tilting of the base slab will be monitored and recorded. During the hydro test, settlements, rotation and base slab tilting will be monitored at approximately each 16 foot increment of water fill height. Measurements will also be recorded when the tank is emptied. During construction, the settlement of the base slab and inner container will be monitored on a weekly basis.

Northern Star 13-44

See specification W00031-040-IN-SP-007 included in Appendix B13 13.8.8.9

Inner and Outer Tank Relative Movement Indicators

The LNG Storage Tanks will include transitional and rotational movement indicators. See drawing W00031-125-ME-DW-026 included in Appendix C13. 13.8.9

Fittings, Accessories, Tank Piping

13.8.9.1

Roof Platforms

The proposed pump platform will be sized to provide sufficient working space around the pump wells and piping. 13.8.9.2

Cranes/Hoists

The pump handling system will consist of a monorail type hoist. Explosion proof electric motors and components will be provided to meet hazardous rating requirements. See drawing W00031-128-ST-GA-001 included in Appendix C13. 13.8.9.3

Intank Pump Columns

Three intank pump columns will be installed in the tank. The pump columns will be fully installed with foot valve, electrical, supports, instrumentation, piping, etc. for a complete system. The columns will be designed to ASME pressure vessel codes, as they operate at higher pressures than the LNG storage tanks. Each pump will be provided with a vibration probe. An arrangement of the pump column is shown on Drawing W00031-127-ME-DW-025 included in Appendix C13. There will be one spare intank pump stored in the warehouse. 13.8.9.4

Tank Internal Piping

The tank internal piping will enter the tank through the concrete outer tank roof. The tank internal piping will be as indicated on W00031-000-PR-PI-067 through W00031-000-PR-PI-070 included in Appendix A13. Roof connection details are shown on Drawings W00031-125-ME-DW-006 and 006, internal pipe work details are shown on Drawings W00031-125-ME-DW-007 to 011 and 024. These drawings are included in Appendix C13. Northern Star 13-45

13.8.9.5

Tank External Piping

The tank external piping will be as indicated on P&IDs included in Appendix A13. All piping systems will be in accordance with ASME B31.3 and NFPA 59A. The proposed arrangement for the design of the Pipes running down the face of the tank wall is to support the pipelines from the top of the tank structure and guide them in the vertical leg normally in two locations on the wall. However, the final number of supports in the vertical leg is dependant on the height of the tank and the elevation of the interconnecting piperack\ sleepers. These supports in the vertical section would be taken directly from the wall of the tank therefore no structure from grade for these supports is required. The interconnecting rack shall be a separate structure with the first pipe support strategically located (based on pipe flexibility analysis at detail design stage) to ensure that this support will rest at this location taking into consideration the contraction of the pipework in the vertical leg and any estimated settlement in the supporting structure. The interconnecting rack structure itself will generally have the first columns supported from the tank pile cap. A typical CAD view of the external tank external piping is included in Appendix A13. 13.8.10

Stairways and Platforms

13.8.10.1

Access to Platform and Roof

A stairway with intermediate landings attached to the outer tank will be provided to access the roof platforms. This staircase will provide access from the platform to the tank roof. An emergency escape ladder will also be provided opposite the main roof platform and accessed via a roof walkway. This will be of the caged ladder type with side stepping platforms. It will be attached to and supported by the outer tank. Platforms are provided on the tank roof for access to the pump columns, nozzles, and instrumentation. Stairways and handrails will provide access to the top of the roof. These stairways and ladder are shown on drawings W00031-129-ST-GA-003 and W00031-129-ST-GA-005, included in Appendix C13.

Northern Star 13-46

13.8.10.2

Internal Tank Ladder

Internal tank access will be provided through roof manways. provided to the inner tank bottom.

A stairway will be

Access details are shown on drawing W00031-129-ST-GA-004 included in Appendix C13. 13.8.10.3

Walkways and Handrails

Handrails for exterior stairways and platforms will be galvanized.

13.8.11

Cryogenic Spill Protection

Spill protection of the tank roof will be designed to comply with the requirements of NFPA 59A. The protection will extend over the edge of the roof dome. Any structural carbon steel on the roof will be protected from potential spills. Extent of spill protection on the concrete roof is shown on drawing W00031-121-CI-GA-003 included in Appendix C13. 13.8.12

Painting

Carbon steel stairs, platforms and pipe supports will be galvanized. Stainless steel, aluminum and galvanized surfaces will not be painted. 13.8.13

Tank Lighting and Convenience Receptacles

General tank lighting systems will be provided. Lighting levels will be as defined in IESNA recommendation. Emergency escape lighting will be provided using self contained battery fittings. A dual aircraft warning light will be provided at the highest point of each tank in accordance with FAA Directive. Outdoor convenience receptacles will be provided at each tank with a minimum of two at the top platform. The electrical system will be designed in accordance with the National Electrical Code (NEC).

Northern Star 13-47

13.8.14

Electrical Grounding

Each tank will be provided with a tank grounding system. Each tank’s grounding grid will consist of stranded copper wire. Grounding electrodes will be spaced such that the overall grounding resistance shall not exceed 10 Ohms. 13.8.15

Welding

Tank welding procedure qualifications and welder qualifications will be in accordance with ASME Sec. IX C13. The guidelines of API 620 Appendix Q will be followed for the quantity of tests. Test plates will be welded on a test stand. Visual Inspection Visual Inspection will be performed in accordance with API 620. Shell plate to annular plate joint will be smoothly finished to avoid undercuts and overlaps, provided that any undercut will be within the tolerances allowed by API 620. Ultrasonic Inspection Partial ultrasonic inspection will be performed based on Section 17.0 of the same specification. 13.8.16

Testing and Inspection

Testing and inspection of the welding, completed work, and the completed structure will be performed under the direct supervision of a qualified welding supervisor inspector. Both visual inspection and ultrasonic inspection will be utilized. A tank inspection and quality assurance procedure will be utilized for this project. C13 13.8.16.1

Alloy Verification

Alloy verification will be performed in accordance with specification W00031-000-TSPR-001, included in Appendix B13. All alloy material used in the construction of the primary and secondary tank systems will be subject to alloy verification. All alloy material external to the tank and in cryogenic or hydrocarbon service will be subject to alloy verification.

Northern Star 13-48

13.8.16.2

Radiography

The radiographic techniques and acceptance criteria will be in accordance with API 620. The extent of radiography will be in accordance with API 620, NFPA 59A Section 4.2.1. 13.8.16.3

Liquid Penetrant Examination

Liquid penetrant examination will be performed in accordance with API 620 and with the exception that the water-washable method may be used. 13.8.16.4

Vacuum Box Testing

Vacuum box testing will be carried out in accordance with API 620. 13.8.16.5

Hydrotesting of Inner Tank

Hydrostatic testing of the inner container shall be in accordance with API 620 Appendix Q.8 (partial hydrotest). The hydrotest water will only be supplied from an acceptable fresh water source. The test water will be sampled and tested for suitability prior to use. Water will be pumped into the tank at rates not exceeding the limitation set by API 620 and piped into the inner container through the manhole in the outer container tank roof. Residence time in the tank will be limited to prevent corrosion. Approximately 28 million gallons of water will be required to test each tank. Hydrotest water will be discharged in a manner acceptable to the regulators upon completion of the tests. Water treatment is not expected; however, if necessary, procedures will be developed for treating the water prior to discharge. 13.8.16.6

Pressure and Vacuum Testing

A pneumatic test of the outer container will be performed in accordance with API 620 Appendix Q.8.

13.8.17

Procedures for Monitoring and Remediation of Stratification

The LNG tanks will be equipped with density monitoring instrumentation to indicate stratification and potential rollover problems, and allow early operator action. The LNG storage tanks will be capable of top or bottom filling from an LNG carrier to Northern Star 13-49

avoid stratification. In addition, facilities will be provided to circulate the stored product so that if stratification begins to develop, the tank contents can be thoroughly mixed. This will involve pumping LNG from the bottom of the tank and returning it to either the top or the bottom as needed. 13.9

PIPING AND INSTRUMENTATION

13.9.1

Piping and Instrumentation Drawings

The P&IDs are included in Appendix A13 and Index of Piping Material Classes W00031030-PI-SP-002 is included in Appendix B13. 13.9.2

Process Control

Control and monitoring of the facility will be performed by an integrated DCS control system consisting of packaged units with local control panels, numerous field mounted instruments connected to remote I/O cabinets and various operator interface stations located in the control rooms. 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. 13.9.2.1

Distributed Control System

Specification for DCS system W00031-040-IN-SP-002 is included in Appendix B13. The control system will be based on conventional distributed control with I/O modules. Communication between the various processors and local control panels will be achieved via a “self healing” fiber optic industrial ethernet ring. This application provides the following advantages: • • • •

•

Continual operation even while the network is being reconfigured; The network is easily maintained and expanded during operation; Fiber optics are immune to electrical and electromagnetic interference; The fiber optic ring provides communication redundancy, in that any one break in the network does not result in loss of control functionality throughout the system; Communication and data transfer up to 100 Mbps;

Northern Star 13-50

• •

The distance between node points on the network can be large with minimal signal errors or degradation; Identical data are available at any point on the network system.

In general, instrumentation signal levels will be 24VDC with both analog 4-20mA and discrete signal types as well as RTD temperature signals. The control system and interface points will consist of the following: • • • • • •

Boil-off gas compressors (2) with local control panels, PLC controller, panel mounted human machine interface (HMI) and network communication port; Marine mooring systems (1) with local control panel, PLC controller, PC / monitor and network communication port; Jetty unloading arm control systems (1) with local control panels, PLC controller and network communications port; Tank gauging data acquisition systems (2) with data input modules and network or serial communication port; LNG vaporizers (7) with local control panels and simple PLC controls; Metering skid and associated control room panel (1) with gas chromatograph controller flow computer. Flow rate values will be relayed to the operator HMI via a hard wired signal from the metering system control panel to the main Communications panel as analogue inputs.

All Vendor packaged unit instrumentation will be skid mounted and come pre-wired to skid mounted control panels. All the above systems will be supplied pre-configured with control logic algorithms and HMI graphics. The tank gauging systems will connect to the main control room tank gauging and data acquisition control system via RS-485 or ethernet link and will be independent of the plant wide communications fiber optic link. Non-Vendor packaged equipment will consist of the following: • •

Remote I/O cabinets (14 Typical) with PLC controllers, remote I/O modules, power supplies, field terminals and network communication port; Temperature mux (multiplex) boxes (5 Typical) with power supplies, field terminals, remote PLC input cards and serial communications port;

Northern Star 13-51

•

• • • • •

Main DCS equipment panel with Processor, I/O modules, power supplies, field terminals, multiport media converter and network communications port; Main communications panel with monitor, keyboard, mouse, data switch, ethernet hub and dual redundant data servers; SIS / F&G equipment panel with redundant system controller, I/O modules, power supplies, field terminals and dual redundant communications link; Operator/Engineer workstations (10 Typical) with network communications port; An additional operator workstation will be provided for a historian package; and Graphics and reports printers (8 Typical)

The remote I/O cabinets will be strategically located throughout the plant process area as follows; • • • • • • • •

Two (2 Typical) adjacent to the vaporizers, area #1, Remote I/O cabinet; Two (2 Typical) adjacent to the vaporizers, area #2, Remote I/O cabinet; One (1 Typical) adjacent to the B.O.G. Compressor, area #3, Remote I/O cabinet; One (1 Typical) adjacent to the B.O.G. Compressor, area #4, Remote I/O cabinet; One (1 Typical) adjacent to LNG storage tank TK-120, Remote I/O cabinet; One (1 Typical) adjacent to LNG storage tank TK-220, Remote I/O cabinet; Five (5 Typical) Pipe track to the jetty, Remote I/O cabinet; One (1 Typical) inside Jetty Berth Control Room, Remote I/O cabinet.

The temperature multiplex boxes will connect to remote I/O cabinets as detailed on Network Architecture Diagram W00031-040-IN-DW-701 included in Appendix A13. The main DCS equipment panel will be located in the control room. These equipment cabinets will serve as the termination point for all instrumentation other than package / skid mounted devices. Cabinets will be certified for Class 1 Division 2 installation. Field instrumentation will generally be SMART 24VDC 4-20mA analogue transmitters with Hart protocol compatibility. The devices will be configurable via a Universal Hand Held Communicator.

Northern Star 13-52

13.9.2.2

Control - Communication Network

Communications between the various local control panels, remote I/O cabinets and the control rooms will be achieved via a redundant fiber optic industrial ethernet ring. This will provide two-way, high-speed communication for control and display. Operator workstations will be provided at two locations, the control room and the jetty control room. Printers will be provided for screen / graphic printouts and also for reports. Control of AC powered equipment will be controlled via interposing relays located in the electrical switch room. 13.9.3

Emergency Shutdown System

(Reference specification for SIS System W00031-040-IN-SP-003) All SIS designated I/O instrumentation will be hard wired from the field device to the control room SIS panel. Three levels of shutdown will be configured for the proposed LNG Terminal as follows: Level 1 To be used for a major incident and will carry out a total plant shutdown. This will be a manually activated operation and will be initiated from the control room via a hardwired emergency shutdown (ESD) button located at the operators console or by three other ESD push button stations located throughout Bradwood Landing, as follows: • • •

One on the main security gate entrance; One in the process area; One in the jetty control room

Level 2 Will only shutdown the appropriate jetty unloading area and can be initiated manually, automatically by local instrumentation, by a Level 1 shutdown, or by ship to shore operation. Output activation will be dictated by the SIS logic as detailed in the Cause and Effects Diagram to be developed during detailed engineering. Northern Star 13-53

All SIS associated alarms will be reported to the dedicated SIS / F&G workstation and also the Engineering workstation. Audible alarms will be provided throughout the plant area to alert field operations. All SIS equipment will be selected and configured for safe, power loss, air loss, and fail action. The SIS equipment cabinet will be located in the plant control room, will be independent of the ethernet-network, and will connect via a redundant link to the dedicated SIS / F&G workstation and also the Engineering workstation. Both workstations will be configured as data servers to the remaining workstations on the ethernet-network. This will allow alarm and status monitoring of the SIS / F&G systems on the entire network. Level 3 Level 3 shutdowns for shutting down individual pieces of equipment will be initiated automatically by trip input signals to the SIS system. Trip output activation will be dictated by the SIS logic as detailed in the Cause and Effects Diagram, to be developed in detail engineering.

13.9.4

Analysis Instrumentation

13.9.4.1

Gas Chromatograph

The specification for Instrumentation and Control System Design W00031-040-IN-SP001 included in Appendix B13 provides the requirements for the provision of a gas Chromatograph. 13.10

ELECTRICAL SYSTEMS

The following drawings are included in Appendix A13, W00031-040-EL-DW-001, 002, 003, 004. 13.10.1

General

Power will be supplied to the project from the utility company, an overhead power line operating at 115 kV will be provided from the existing 115kV network in the area. Northern Star 13-54

A new115kV switch yard and associated 4160/480V substation will be built at the plant site. The philosophy adopted is to operate each switchboard with both of the incoming sections closed with the bus tie open. Upon failure of one of the incoming supplies, the effected incoming circuit breaker shall open and the bus tie shall automatically close. This operation shall be locked out however, should the fault be detected as being on the switchboard Busbar Transfer back to a two leg operation shall be carried out manually and the two incomers and bus tie shall be momentarily closed whilst this change over is accomplished. For safety reasons, this operation shall be carried out remotely, either via the plant control system or by a switching panel located in a separate room to the switchboard itself. All switchgear and MCC equipment shall be designed and installed in accordance with the relevant IEEE, ANSI and NEMA specifications. Switchgear and MCC voltage ratings shall be 4160 and 480V. Such switchgear shall be indoor pattern and be metal clad. 4160V motors shall be controlled using E2 fused contactors, 480V motors shall be started and controlled using DOL starter circuits, circuit breaker protected. All MCC and switchgear shall be dead front design and be designed such that each individual motor starter or feeder unit is contained within a unique enclosure as part of the switchboard or MCC structure. The operating load of the facility will be approximately 20 MVA. Most of this load will consist of motors, with the largest motors rated at approximately 2335 HP each. 13.10.2

Area Classification

W00031-000-EL-DW-004 included in Appendix A13 shows the electrical area classification for the facility. Much of the area is Class I, Group D, Division 2 per NEC. The electrical materials and methods will be in accordance with the requirements of the 2002 edition of the NEC. 13.10.3

Voltage Levels

Northern Star 13-55

The utility will supply electricity to the plant at 115 kV. Transformers will be installed to step down to 4.16 kV, 480 V, 480/227V, 240/120V and 120 V. 13.10.4

Utility and Generator Power Supply

Power for the facility will be supplied by a local electricity company. A standby generator will provide back-up power for critical loads. The standby generator will be diesel engine driven, and will have an output rating of 4160 V, 3 phase, 60 Hertz, 1,000 kVA, 0.8 PF. Critical loads served by the generator will include the instrument air compressors, plant lighting and the UPS systems. 13.10.5

Switchgear and Motor Control Centers

All switchgear and MCC equipment shall be designed and installed in accordance with the relevant IEEE, ANSI and NEMA specifications. Switchgear and MCC voltage ratings shall be 4160 and 480V. Such switchgear shall be indoor pattern and be metal clad. 4160V motors shall be controlled using E2 fused contactors, 480V motors shall be started and controlled using DOL (Direct On Line) starter circuits, circuit breaker protected. All MCC and switchgear shall be dead front design and be designed such that each individual motor starter or feeder unit is contained within a unique enclosure as part of the switchboard or MCC structure. 13.10.6

Load Shedding

Under such circumstances as a momentary voltage dip or sag, the power distribution system will effectively collapse and motors will begin to decelerate. Some drives may trip, some may ride through the dip in a somewhat unpredictable manner. Any motors that ride through a transient voltage dip, will begin to decelerate, but, when the voltage dip is past, all of these drives will attempt to accelerate away again and consequently the starting current of all of these loads will be imposed on the distribution system all at the same time and the power system may be unable to sustain this transient current.

Northern Star 13-56

To legislate against such circumstances, A load shedding scheme shall be designed into the electrical switchgear and MCC equipment such that should there be a sudden loss of capacity or otherwise an unexpected overload situation, then loads shall be automatically tripped out in sequence until a stabilized situation exists within the power distribution system. The sequence of loads to be tripped and subsequently automatically restarted shall be defined in consultation with the process engineering section to ensure that the impact upon the operating plant is minimized. 13.10.7

Wiring

Power and control wiring will be run primarily above grade in cable trays and conduits. Remote areas for which supports do not exist will be served by below grade conduits encased in concrete. 13.10.8

Electric Motors

All electric motors considered are asynchronous induction cage types. Enclosures shall be suitable for the ambient outdoor conditions prevailing and any hazardous area considerations. 13.10.9

Exterior Lighting

High-pressure sodium type lighting will be provided for all exterior plant locations. These locations include the process area equipment, access roadway, tank stairways, roof platforms, building exterior, and jetties. The lighting fixtures provided will be approved for the area classification in which they are installed and will be weatherproof. 13.10.10

Grounding

Power Grounding and equipotential bonding are considered in accordance with ANSI / NEMA / IEEE specifications, particularly IEEE 142 & IEEE 80 shall apply as and where appropriate. For the switchyard, the applicable specification shall be IEEE80, which defines steps to be taken to avoid unacceptable touch and step potentials occurring during fault conditions. This usually requires a grid of buried bare conductors to be laid in the ground around power equipment with ground electrodes being established as required to reduce the impedance to ground to a low enough level to avoid danger and mal operation of equipment. Northern Star 13-57

Neutral earth resistors shall be installed at main power transformers and generating plant and be connected into the main grounding system as shown on the Contractor prepared drawings. Elsewhere, a plant grounding system shall be installed as part of the works, the applicable standard being IEEE 142. This shall address all equipotential bonding and lightning protection considerations. 13.10.11

Lightning Protection

Lightning protection schemes shall be installed where deemed necessary by the listed codes and standards. This shall typically include the LNG tanks substations and control building. Ground electrodes for the lightning protection system shall be electrically bonded to the main ground network ground electrodes. The lightning protection scheme shall also be bonded to the main electrical ground. This requirement is seen as being specifically applicable to the storage tanks, which externally shall be substantially made up of non-conducting material. This shall require the use of specially designed air terminals and down conductors, which shall be connected to ground locally around the tank base. The lightning protection and plant grounding system shall be single point bonded using proprietary ground bars local to the tank base. 13.10.12

Uninterruptible Power Supply

Under a supply outage, all facilities would be without power for a short period until the generator achieves full speed. Also, the generator itself may be unavailable or may fail for some reason. In order to maintain plant monitoring and control facilities at such a time, a short time rated UPS system will be installed that will only power essential instrumentation & controls or any vital lighting circuits. Separate UPS systems are proposed for the plant control room and the jetty areas. The UPS systems shall be dual redundant types arranged to avoid any instance of common mode failure within the UPS systems themselves. Back up batteries shall be provided in separate dedicated battery rooms for each UPS. UPS standby power would be by static battery banks located in separate specially designed battery rooms. Several different technologies are available for battery specification, though general practice presently tends to favor maintenance free,

Northern Star 13-58

valve regulated lead acid types and these are proposed for the UPS systems described above. Proposed ratings are 30 kVA for the main plant and control system UPS and 15kVA for the jetty area. Autonomy is proposed as a minimum of 1 hour for all loads except those critical for plant monitoring and safety systems whish shall have installed battery capacity to facilitate power supply for up to 8 hours.

13.11

DESIGN CODES AND STANDARDS

A list of the Design Codes and Standards is included in Appendix A13 13.12

PERMITS AND APPROVALS

All the permits, consultations and regulatory requirements for the Project and the anticipated filing date of each are listed in Resource Report 1. 13.13

REGULATORY COMPLIANCE

A Code Compliance Tables completed by Whessoe are provided. Additional details of where the Project design complies with 49 CFR Part 193 and NFPA 59A are included in this Section 13.13. 13.13.1

49 CFR Part 193

Table 13.13-1 lists the sections of 49 CFR Part 193 and the reference in this Resource Report 13 where each requirement is discussed. Some references are continued at the end of this section. 13.13.2

NFPA 59A

Table 13.13-2 lists the sections of NFPA 59A and the reference in this Resource Report 13 where each requirement is discussed. 13.13.3

Additional Responses to 49 CFR Part 193

13.13.3.1

193.2051 – Scope

Northern Star 13-59

Bradwood Landing is sited in accordance with the criteria set forth in Subpart B – Siting requirements. The scope is as outlined in the paragraph. 13.13.3.2

193.2119 – Records

During the design and construction of the proposed terminal facility records of all material for components, buildings, foundations and support systems will be maintained. The operator will keep these records for the life of the item concerned. 13.13.3.3

193.2155 – Structural requirements

The new LNG storage tanks are not located within a horizontal distance of one mile from the ends, or 0.25 mile from the nearest point of a runway. 13.13.3.4

193.2187 – Nonmetallic Membrane Liner

A flammable nonmetallic membrane liner will not be used for the new LNG storage tanks. 13.14.3.5

193.2301 – Scope

The Project will comply with requirements of this part and NFPA 59A. In the event of a conflict between this part and NFPA 59A, this part shall prevail. 13.13.3.6

193.2303 – Construction acceptance

New construction on the facility will not be placed in service until it passes all applicable inspections and tests prescribed in 49 CFR 193 and NFPA 59A. 13.13.3.7

193.2304 – Corrosion control overview

Materials for new components of the proposed facility will be reviewed from a corrosion control viewpoint such that the structural integrity of the component will not be affected. 13.13.3.8

193.2321 – Non-destructive tests

The required radiographic testing methods will be used as defined by this paragraph, and by using written procedures that describe technique, reporting, and record keeping requirements. Northern Star 13-60

13.13.3.9

193.2401 – Scope

Vaporization equipment and control systems will be designed, fabricated and installed in accordance with the requirements of this part and of NFPA 59A. In the event of a conflict between this part and NFPA 59A, this part prevails. 13.13.3.10

Sub-part F – Operations

The control center for this facility will be designed to insure all applicable requirements of this part are met with regard to facility operations. Operating procedures will be prepared and extensive training will be provided to insure that facility personnel are familiar with and understand the importance of adherence to safe procedures. These procedures will address safe startup, shutdown, cool down, purging, etc., as well as routine operation and monitoring. Particular attention will be taken to coordination and involvement of appropriate local officials in the vicinity of the LNG terminal. 13.13.3.11

193.2511 – Personnel Safety

Protective clothing and equipment necessary for the safety of personnel while performing emergency response duties will be provided. All personnel who are normally on duty where they could be harmed by thermal radiation from a burning pool of impounded liquid will be provided a means of protection at that location from the harmful effects of thermal radiation or a means of escape. First-aid materials will be provided in clearly marked locations available to all personnel. 13.13.3.12

193.2521 – Operating Records

Inspection, testing and investigation records shall be maintained for a period of not less than five years. 13.13.3.13

Sub-part G – Maintenance

Detailed maintenance procedures will be written for the LNG facility meeting all applicable requirements of this part. Particular care will be taken to address replacement of equipment parts or systems with like components that are suitable for the intended service. These procedures will be coordinated with the operating procedures discussed in 13.13.3.11 to ensure that operation of equipment is in compliance with proper procedures.

Northern Star 13-61

Periodic testing of fire protection and auxiliary power systems will be performed to insure that these systems are in a fully operable state should they be required. There are no LNG transfer hoses in the proposed design. Inspection of the LNG tanks to verify the structural integrity and safety of the tank will be performed periodically and immediately after any major meteorological or geophysical disturbance. There will be periodic testing of the installed cathodic protection systems by a person specifically trained for this type of work. 13.13.3.14

193.2619 – Control Systems

Safety and shutdown systems will be tested once each calendar year. The fire protection control system will be inspected every six months. 13.13.3.15

193.2639 – Maintenance records

Periodic inspection and testing records will be maintained for a period of not less than five years. 13.13.3.16

Sub-part H – Personne l Qualifications and Training

An engineering, procurement, and construction contractor qualified in the design and construction of the project facilities will be employed to design and construct the facility. All personnel assigned to Bradwood Landing will be properly trained and determined to be qualified to perform their duties. Training records providing evidence that all personnel have undergone and satisfactorily completed required training will be maintained for one year after personnel are no lo nger assigned duties at Bradwood Landing. 13.13.3.17

Sub-part I – Fire Protection

Bradwood Landing will be designed to comply with all applicable requirements of this part. Procedures and systems will be developed to complement these design features. 13.13.3.18

Sub-part J – Security

Northern Star 13-62

Bradwood Landing will be designed to comply with all applicable requirements of this part. Procedures and systems will be developed to complement these design features. 13.13.4

Additional Responses to NFPA 59A

13.13.4.1

2-4 Designer and Fabricator Competence

Designers, fabricators and constructors will be experienced, competent and properly trained. Soils investigations have been made for the entire site. Supervision will be provided for the fabrication, construction and acceptance tests for facility components. 13.13.4.2

2-5 Soil Protection for Cryogenic Equipment

The LNG storage tank foundations will be on-ground and electrically heated to prevent frost heave from occurring. All cryogenic equipment and piping will be elevated to prevent soil damage. 13.13.4.3

2-6 Falling Ice and Snow

No operating equipment will be located adjacent to the LNG storage tank. Personnel access to the tank will be controlled during the extremely infrequent snow or ice storms that may occur at Bradwood Landing. 13.13.4.4

2-7 Concrete Materials

There are no concrete structures that will be normally in contact with LNG. Concrete used for the construction of LNG tanks will be in accordance with Sections 4-3.2 and 4-3.3 of NFPA 59A 2001 edition and ACI 318. Pipe supports will be in accordance with Section 6-4 of NFPA 59A. Concrete for slope protection and impounding area paving will comply with ACI 304R. Reinforcement will comply with Paragraph 2-2.1 of ACI 344R-W.

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13.13.4.5

3-1 Process Systems – General

Most of the process system equipment containing, LNG flammable refrigerants or flammable gases are located outside. Equipment that is located inside a building will comply with Sections 2-3 and 2-3.2 of NFPA 59A. 13.13.4.6

3-2 Pumps and Compressors

All pumps and compressors will be designed to meet the requirements of this paragraph. 13.13.4.7

3-3 Flammable Refrigerant and Flammable Liquid Storage

Installation of storage tanks for flammable liquids will comply with all of the standards noted in the Section 3-3 of NFPA 59A. 13.13.4.8

3-4 Process Equipment

Process equipment will meet the requirements of this section. All equipment, piping and process vessels shall be designed to withstand full vacuum conditions, or provisions shall be made to prevent the development of a vacuum in equipment that might create a hazardous condition. 13.13.4.9

4-1 Stationary LNG Storage Containers - General

The proposed LNG storage tanks will be inspected to insure compliance with the engineering design and material, fabrication, assembly and test provisions of NFPA 59A prior to initial operation of Bradwood Landing. 13.13.4.10

4-2 Metal Containers

The internal design pressure for the new LNG storage tank is 4.2 psig (less than 15 psig). The radiographic inspection will be performed in accordance with Section 4-2.1 of NFPA 59A. 13.13.4.11

4-3 Concrete Containers

The concrete outer container of the LNG storage tanks will be designed in accordance with ACI 318 and the provisions of 4.3.2.2. through 4.3.2.5 of NFPA 59A.

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13.13.4.12

4-4 Marking of LNG Containers

The proposed LNG storage tanks will have a nameplate with all the information required by this section. Each penetration will be marked with the function of the penetration and be visible if frosting occurs. 13.13.4.13

4-6 Container Purging Procedures

The proposed LNG storage tanks will be purged and cooled down in accordance with sections 11-3.5 and 11-3.6 of NFPA 59A prior to placing the LNG storage tanks into service. 13.13.4.14

4-8 Relief Devices

Pressure and vacuum relief devices for the LNG storage tanks will be designed in accordance with Section 4-8 of NFPA 59A. 13.13.4.15

5-6 Products of Combustion

The proposed trim heaters will not be installed in buildings. 13.13.4.16

6-1 Piping Systems and Components – General

All piping systems will be in accordance with ASME B31.3, Process Piping, and due consideration will also be given to the additional provisions of NFPA 59A with respect to piping systems and components for flammable liquids and gases with service temperatures below –20 degrees F. The piping will be designed for the applicable seismic criteria, and the resultant stresses will be within those allowed in ASME B31.3, Process Piping. The piping systems and their design will take into account fatigue effects. Expansion and contraction of the piping systems will be taken into account when designing the supports and laying out the piping systems. Further reference in this respect should be made to specification W00031-030-PI-SP-001, Plant Layout and Piping Design, included in Appendix B13. 13.13.4.17

6-2 Materials of Construction

All materials of construction will be suitable for the design temperatures and pressures to be encountered in service. The piping systems will be designed to meet the requirements of NFPA 59A Section 6-2.1.2. The insulating system to be installed Northern Star 13-65

will not propagate fire and will maintain its properties during an emergency. ASTM A312 and ASTM A358 type 304/304L (dual certified) stainless steel pipe will be used for cryogenic or hazardous fluid services. The materials used within the piping systems will comply with the requirements of ASME B31.3. Valves will comply with the requirements of NFPA 59A Section 6-2.4. 13.13.4.18

6-3 Installation

The connection requirements of NFPA 59A Sections 6-3.1 and 6-3.2 for pipework will be incorporated into the piping design and into the specifications that govern welding, fabrication and erection of the piping system. Extended bonnets will be provided for valves exposed to cryogenic temperatures. All penetrations conveying fluids to or from the LNG tank will be provided with shutoff valves at the tank. Pipe welding procedures and welders will be qualified in accordance with ASME B31.3, Section IX of the ASME Boiler and Pressure Vessel Code and meet the requirements of Section 6-3.4 of NFPA 59A. The pipe marking requirements of Section 6-3.5 will be included in the fabrication and construction process. 13.13.4.19

6-4 Pipe Supports

The design of the pipe supports will ensure that excessive heat transfer causing icing or embrittlement of the supporting steel will not occur. Low temperature piping will not rest directly on structural supports. Pipe supports constructed of thermally isolating structural materials will be used to transmit loads from the process pipe to the pipe supports. 13.13.4.20

6-5 Piping Identification

The piping systems will be suitably labeled with line identification and flow arrows. 13.13.4.21

6-6 Inspection and Testing of Piping

Pipework will be inspected and tested in accordance with the requirements of ASME B31.3, Process Piping, and will also incorporate the requirements of Section 6-6 of NFPA 59A. Further reference should also be made to specification W00031-030-PI-SP003, Pipework Testing, included in Appendix B13. Radiographic and other nondestructive testing methods will be used as required under Section 6-6.3 of NFPA 59A. Written procedures will be prepared for testing and inspection of piping, and test records and certifications will be maintained for the life of the piping systems.

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13.13.4.22

6-7 Purging of Piping Systems

LNG and natural gas lines will be installed with purge points so that the lines can be safely purged with nitrogen. 13.13.4.23

6-8 Safety and Relief Valves

All piping will be protected by safety relief valves set to keep the internal pressure on the piping within its design limits. The discharge from these relief valves will be directed to the venting system which goes to the vent stack, except for the storage tank relief valves. 13.13.4.24

6-9 Corrosion Control

Piping which may be run underground, such as drainage piping, firewater piping and process gas piping, will be either constructed of materials which can resist corrosion or be suitably coated. Piping components will be periodically inspected and repaired or replaced under the scheduled maintenance program established in the maintenance procedures and NACE RP 0169. 13.13.4.25

7-7 Electrical Grounding and Bonding

Power Grounding and equipotential bonding are considered in accordance with ANSI / NEMA / IEEE specifications, particularly IEEE 142 & IEEE 80 shall apply as and where appropriate. For the switchyard, the applicable specification shall be IEEE80 which defines steps to be taken to avoid unacceptable touch and step potentials occurring during fault conditions. This usually requires a grid of buried bare conductors to be laid in the ground around power equipment with ground electrodes being established as required to reduce the impedance to ground to a low enough level to avoid danger and mal operation of equipment. Neutral earth resistors shall be installed at main power transformers and generating plant and be connected into the main grounding system. Elsewhere, a plant grounding system shall be installed as part of the works, the applicable standard being IEEE 142. This shall address all equipotential bonding and lightning protection considerations

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13.13.4.26

8-2 Piping System

Valves will be installed at the extremities of each transfer system. Hydraulic shock analysis will be performed on all lines which contain an automatic shutoff valve, to ensure that line or equipment failure cannot be caused by hydraulic shock. Check valves will be provided at points in which backflow may occur. 13.13.4.27

8-3 Pump and Compressor Control

The terminal’s pumps and compressors will be capable of being controlled both locally and remotely from the control room, and will have signal lights to indicate when pumps and compressors are operating or shutdown. 13.13.4.28

8-4 Marine Shipping and Receiving

The terminal’s carrier unloading and mechanical systems shall be designed in accordance with Section 8-4 of NFPA 59A. 13.13.4.29

8-5 Tank Vehicle and Tank Car Loading and Unloading Facilities

There will not be tank vehicle or tank car loading or unloading at the proposed terminal. 13.13.4.30

8-9 Communications and Lighting

Adequate communication will be provided to allow the operator at the unloading operation to be in contact with other personnel associated with the unloading operation. 13.13.4.31

9-7 Maintenance of Fire Protection Equipment

Terminal maintenance procedures will incorporate routine maintenance for fire protection equipment per NFPA 10 and other applicable codes and standards. 13.13.4.32

9-9 Personnel Safety

Emergency procedures will be developed, which will include the protective clothing to be worn and procedures for confined space entry. At least three portable flammable gas detectors will be provided.

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13.13.4.33

9-10 Other Operations

Manual depressurizing will be accomplished by hard piped connections to the facility vent system. 13.13.4.34

4-7 Cool-down Procedures

The operator of the proposed facility has employed personnel with extensive experience in operation and maintenance of LNG facilities. Based on this experience and with the consultation of other LNG experts, detailed written cool-down procedures will be prepared for the facility, including training procedures. These written procedures will incorporate the requirements of NFPA 59A and other applicable codes and regulations and will be used to train and qualify all operations personnel before commissioning and operation. 13.13.4.35

9-7 Ignition Source Control

The proposed facility will not allow smoking within the perimeter. Access by vehicles and other devices will be limited by a system of procedures and written permits with monitored access.

13.14

SEISMIC REVIEW

The report “Draft Report, Seismic Hazard Analysis for LNG Import Terminal, Bradwood Oregon” prepared by URS Consulting, Inc. is included in Appendix D13.

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