BRADWOOD LANDING TERMINAL
Resource Report 13
Engineering and Design Material
SUBMITTED BY NORTHERN STAR NATURAL GAS LLC
Rev 2
16
thMay 2006
RESOURCE REPORT 13
ADDITIONAL INFORMATION RELATED TO LNG PLANTS CONTENTS
13 INTRODUCTION 13-1
13.1 SITE PLAN 13-1
13.1.1 Siting 13-2
13.1.2 Thermal Radiation Protection 13-2 13.1.3 Flammable Vapour Dispersion Protection 13-2 13.1.4 Seismic Design Investigation and Design Forces 13-3
13.1.5 Flooding 13-5
13.1.6 Soil Characteristics 13-5
13.1.7 Wind Forces 13-6
13.1.8 Other Severe and Natural Conditions 13-7
13.1.9 Adjacent Activities 13-7
13.1.10 Separation of Facilities 13-8
13.1.11 Site Development 13-8
13.1.11.1 Grading and Excavation 13-8 13.1.11.2 LNG Tank Impoundment 13-9 13.1.11.3 Drainage and Storm Water Run-off 13-9 13.1.11.4 Spill Containment 13-10
13.1.11.5 Foundations 13-10
13.1.11.6 Roads 13-11
13.1.11.7 Site Surface Treatment 13-11
13.2 FIRE PROTECTION SYSTEM 13-12
13.2.1 Firewater System 13-12
13.2.1.1 Firewater System Components 13-12
13.2.1.2 Firewater Piping 13-14
13.2.2 Dry Chemical Extinguishers 13-14 13.2.3 High Expansion Foam System 13-14 13.2.4 Portable Fire Extinguishers 13-15 13.2.5 Fireproofing and Siren 13-15
13.3 HAZARD DETECTION SYSTEM 13-15
13.3.1 General 13-15
13.3.2 Monitoring Equipment 13-17
13.3.2.1 Gas Detectors 13-17
13.3.2.2 Low Temperature Detectors 13-17
13.3.3 Fire Detectors 13-17
13.3.3.1 General 13-17
13.3.3.2 Smoke Detectors 13-18
13.3.3.3 High Temperature Detectors 13-18
13.3.3.4 Visual Monitoring 13-18
13.3.4 Fire and Hazardous Gas Detection System 13-18
13.4 SPILL CONTAINMENT SYSTEM 13-19
13.4.1 Spill Containment Tanks 13-19 13.4.2 Spill Containment Tank and Vaporizer Area 13-19 13.4.3 Spill Containment Jetty Area 13-20 13.4.4 Spill Containment General 13-20
13.5 SHUT-OFF VALVES 13-20
13.6 DESIGN PLANNING 13-21
13.7 MAJOR PROCESS COMPONENTS 13-22
13.7.1 Marine Facilities 13-22
13.7.1.1 Carrier Unloading Arms 13-25 13.7.2 LNG Un-loading Operation 13-26 13.7.2.1 Vapour Return Blowers Knockout Drum 13-27 13.7.2.2 BOG and Vapour Handling System 13-27 13.7.2.3 Boil-off Gas Compressor 13-29
13.7.2.4 BOG Condenser 13-30
13.7.3 LNG Sendout System 13-31
13.7.3.1 In-tank LNG Pumps 13-31
13.7.3.2 Sendout Pumps 13-32
13.7.3.3 Submerged Combustion Vaporizers 13-32 13.7.3.4 Operation and Control 13-33
13.7.4 Vent 13-34
13.7.5 Buildings and Piping Structures 13-34 13.7.5.1 New Buildings – Scope of Work 13-34 13.7.5.2 Structural Piperacks 13-37 13.8 LNG STORAGE TANKS 13-37 13.8.1 General 13-37 13.8.2 Tank Foundation 13-39 13.8.3 Outer Tank 13-39 13.8.4 Inner Tank 13-40
13.8.5 Seismic Loads on Inner and Outer Tanks 13-40 13.8.6 Wind Loads on Outer Tank 13-41
13.8.8 Tank Instrumentation 13-42
13.8.8.1 Cooldown Sensors 13-42
13.8.8.2 Temperature Sensors 13-43 13.8.8.3 Liquid Level Instruments 13-43 13.8.8.4 Tank Gauging, Density and Overfill Protection Requirements 13-43 13.8.8.5 Density Monitoring 13-43 13.8.8.6 Liquid Temperature Measurements 13-44 13.8.8.7 Pressure & Vacuum Relief Systems 13-44 13.8.8.8 Settlement Monitoring 13-44 13.8.8.9 Inner and Outer Tank Relative Movement Indicators 13-44 13.8.9 Fittings, Accessories, Tank Piping 13-44
13.8.9.1 Roof Platforms 13-44
13.8.9.2 Cranes / Hoists 13-45
13.8.9.3 Intank Pump Columns 13-45 13.8.9.4 Tank Internal Piping 13-45 13.8.9.5 Tank External Piping 13-45 13.8.10 Stairways and Platforms 13-46 13.8.10.1 Access to Platform and Roof 13-46 13.8.10.2 Internal Tank Ladder 13-46 13.8.10.3 Walkways and Handrails 13-46 13.8.11 Cryogenic Spill Protection 13-47
13.8.12 Painting 13-47
13.8.13 Tank Lighting and Convenience Receptacles 13-47 13.8.14 Electrical Grounding 13-47
13.8.15 Welding 13-47
13.8.16 Testing and Inspection 13-48 13.8.16.1 Alloy Verification 13-48
13.8.16.2 Radiography 13-48
13.8.16.3 Liquid Penetrant Examination 13-48 13.8.16.4 Vacuum Box Testing 13-48 13.8.16.5 Hydrotesting of Inner Tank 13-49 13.8.16.6 Pressure and Vacuum Testing 13-49 13.8.17 Procedures for Monitoring and Remediation of Stratification 13-49
13.9 PIPING AND INSTRUMENTATION 13-49
13.9.1 Piping and Instrumentation Drawings 13-49
13.9.2 Process Control 13-49
13.9.2.1 Distributed Control System 13-50 13.9.2.2 Control – Communication Network 13-52 13.9.3 Emergency Shutdown System 13-53 13.9.4 Analysis Instrumentation 13-54 13.9.4.1 Gas Chromatograph 13-54 13.10 ELECTRICAL SYSTEMS 13-54 13.10.1 General 13-54 13.10.2 Area Classification 13-55 13.10.3 Voltage Levels 13-55
13.10.5 Switchgear and Motor Control Centres 13-56 13.10.6 Load Shedding 13-56 13.10.7 Wiring 13-57 13.10.8 Electric Motors 13-57 13.10.9 Exterior Lighting 13-57 13.10.10 Grounding 13-57 13.10.11 Lightning Protection 13-58 13.10.12 Uninterruptible Power Supply 13-58
13.11 DESIGN CODES AND STANDARDS 13-59
13.12 PERMITS AND APPROVALS 13-59
13.13 REGULATORY COMPLIANCE 13-59
13.13.1 49 CFR Part 193 13-59
13.13.2 NFPA 59A 13-59
13.13.3 Additional Responses to 49 CFR Part 193 13-59
13.13.3.1 193.2051 – Scope 13-59
13.13.3.2 193.2199 – Records 13-59 13.13.3.3 193.2155 – Structural Requirements 13-60 13.13.3.4 193.2187 – Non-metallic Membrane Liner 13-60
13.13.3.5 193.2301 – Scope 13-60
13.13.3.6 193.2303 – Construction Acceptance 13-60 13.13.3.7 193.2304 – Corrosion Control Overview 13-60 13.13.3.8 193.2321 – Non-destructive Tests 13-60 13.13.3.9 193.2401 – Scope 13-60 13.13.3.10 Sub-part F – Operations 13-61 13.13.3.11 193.2511 – Personnel Safety 13-61 13.13.3.12 193.2521 – Operating Records 13-61 13.13.3.13 Sub-part G – Maintenance 13-61 13.13.3.14 193.2619 – Control Systems 13-62 13.13.3.15 193.2639 – Maintenance Records 13-62 13.13.3.16 Sub-part H – Personnel Qualifications and Training 13-62 13.13.3.17 Sub-part I – Fire Protection 13-62 13.13.3.18 Sub-part J – Security 13-62 13.13.4 Additional Responses to NFPA 59A 13-63 13.13.4.1 2-4 Designer and Fabricator Competence 13-63 13.13.4.2 2-5 Soil Protection for Cyrogenic Equipment 13-63 13.13.4.3 2-6 Falling Ice and Snow 13-63 13.13.4.4 2-7 Concrete Materials 13-63 13.13.4.5 3-1 Process Systems – General 13-63 13.13.4.6 3-2 Pumps and Compressors 13-64 13.13.4.7 3-3 Flammable Refrigerant and Flammable Liquid Storage 13-64 13.13.4.8 3-4 Process Equipment 13-64 13.13.4.9 4-1 Stationary LNG Storage Containers – General 13-64 13.13.4.10 4-2 Metal Containers 13-64 13.13.4.11 4-3 Concrete Containers 13-64 13.13.4.12 4-4 Marking of LNG Containers 13-64
13.13.4.13 4-6 Container Purging Procedures 13-65 13.13.4.14 4-8 Relief Devices 13-65 13.13.4.15 5-6 Products of Combustion 13-65 13.13.4.16 6-1 Piping Systems and Components – General 13-65 13.13.4.17 6-2 Materials of Construction 13-65 13.13.4.18 6-3 Installation 13-66 13.13.4.19 6-4 Pipe Supports 13-66 13.13.4.20 6-5 Piping Identification 13-66 13.13.4.21 6-6 Inspection and Testing of Piping 13-66 13.13.4.22 6-7 Purging of Piping Systems 13-66 13.13.4.23 6-8 Safety and Relief Valves 13-67 13.13.4.24 6-9 Corrosion Control 13-67 13.13.4.25 7-7 Electrical Grounding and Bonding 13-67 13.13.4.26 8-2 Piping System 13-67 13.13.4.27 8-3 Pump and Compressor Control 13-68 13.13.4.28 8-4 Marine Shipping and Receiving 13-68 13.13.4.29 8-5 Tank Vehicle and Tank Car Loading and Unloading Facilities 13-68 13.13.4.30 8-9 Communications and Lighting 13-68 13.13.4.31 9-7 Maintenance of Fire Protection Equipment 13-68 13.13.4.32 9-9 Personnel Safety 13-68 13.13.4.33 9-10 Other Operations 13-68 13.13.4.34 4-7 Cooldown Procedures 13-69 13.13.4.35 9-7 Ignition Source Control 13-69
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
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
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:
• Thermal radiation protection;
• Flammable vapor gas dispersion protection;
• Seismic design investigation and design forces;
• Flooding;
• Soils characteristics;
• Wind forces;
• Other severe and natural conditions;
• Adjacent activities;
• Separation of facilities;
• Site development.
13.1.2 Thermal Radiation Protection
Calculations have been made, by Whessoe Oil and Gas Limited, in relation to 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.
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 345-021-0010 (Site Characterisation – Exhibits H and I), OAR 345-022-0020 (Structural
Standard), and OAR 345-022-0022 (Soil Protection). These reports also comply 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.
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 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
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.
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.
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.
Vaporizers Will be located at least 100 feet from the property line and at least 50 feet from any source of ignition.
13.1.11 Site Development
13.1.11.1 Grading and 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.
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.
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.
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.
13.2 FIRE PROTECTION SYSTEM
The proposed terminal has a number of independent fire protection systems. These include
i) A fire water main capable of servicing hydrants, monitors, the jetty spray curtain, and individual equipment spray protection.
ii) High expansion foam system for protection of the spill impoundment basins.
iii) Dry chemical extinguishers to enable a fire within the relief valve discharge piping to be extinguished automatically.
iv) 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-PR-DB-008. The following codes were referred to in the design of the fire water system:
• NFPA 13 – Installation of Sprinkler Systems
• NFPA 14 – Installation of Standpipe, Private Hydrants and Hose Systems
• NFPA 15 - Water Spray Fixed Systems for Fire Protection
• NFPA 20 – Standard for the Installation of Stationary Pumps for Fire Protection
• NFPA 24 – Installation of Private Fire Service Mains and their Appurtenances
• API 2030 – Application of Fixed Water Spray Systems for Fire Protection in the Petroleum Industry
13.2.1.1 Firewater System Components
Refer to the Firewater and Monitor layout drawings W00031-030-PI-LO-007 and W00031-030-PI-LO-008 included in Appendix A13
• 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
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.
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.
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) Smoke Detection Layout W00031-840-IN-LO-001 b) CCTV Layout W00031-840-IN-LO-002
c) Macs (Call Points) Layout W00031-840-IN-LO-003 d) Point Gas Detection Layout W00031-840-IN-LO-004 e) Open Path Gas Detection Layout W00031-840-IN-LO-005 f) Flame Detection Layout W00031-840-IN-LO-006
g) Low Temp./ Cold Detection Layout W00031-840-IN-LO-007 h) Water / Foam Delivery Layout W00031-840-IN-LO-008 i) Fire Extinguishers Layout W00031-840-IN-LO-009 j) 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;
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..
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.
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.
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 anti-crack reinforcement.
Following annual inspections it is expected that the sacrificial screed layer will require minor repairs to areas of weathering five years following the end of 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
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.
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) W00031-000-PR-PF-001 and P&IDs referenced in each section, the drawings are included in Appendix A13.
13.7.1 Marine Facilities
The Project will include the construction of an LNG Carrier unloading facility consisting of a dredged basin with an LNG Carrier berth and a berth for the 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
(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.
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.
The facilities have been designed to provide safe berths for the receipt and support of LNG Carriers and to ensure the safe transfer of LNG cargoes from the ships to on-shore storage facilities. Design is in accordance with applicable codes and standards, including but not limited to Oil Companies International Marine Forum (OCIMF), Society of International Gas Tanker and Terminal Operators (SIGTTO), 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: FMC Energy Systems or similar
• Service: Natural Gas / LNG
• Unloading Arm Size: 16 in
• Design Temperature: –274 oF / +99 oF
• Range of Carrier Capacities: 26.4 – 52.8MM gallons (100,000 m3 – 200,000 m3)
The unloading arms manufacturer will be selected based on compliance to specifications and will have prior experience with LNG operations.
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.
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 re-circulation and unloading lines.
3.7.2.1 Vapor Return Blowers Knockout Drum Refer to P&ID W00031-000-PR-PI-007.
A vapor return KO drum will be located on the jetty. Once the unloading activities have been completed and before re-circulation is started, LNG will be drained 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-DS-013).
13.7.2.2 BOG and Vapor Handling System
The BOG and vapor handling system is detailed in P&ID’s W00031-000-PR-PI-008/009/010/011.
• 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.