Basis of Design LNG

Oregon LNG Warrenton, Oregon Appendix C

Job No. 07902 Page 1 of 8

Resource Report 13 18 CFR 380.12(o) Appendix C Basis of Design


Section


Page C.1 C.2 C.3 C.4 C.5 C.6

Engineering Design Standard ..................................................................... 3 Design Basis................................................................................................ 4 Hazard Detection and Mitigation Philosophy ............................................. 5 Rainfall Design Basis .................................................................................. 6 Seismic Design Basis .................................................................................. 7 Marine Facilities Design Basis ................................................................... 8


C.1 Engineering Design Standard


Oregon LNG Terminal Warrenton, OR Engineering Design Standard

Job No. 07902 Doc No. 07902-TS-000-001 Rev 4 Page 1 of 33

ENGINEERING DESIGN STANDARD by H H C H H

CH·IV International

REV NUMBER: ISSUE PURPOSE:

0 Draft for Client Review

DATE: BY: CHECKED: APPROVED:

05/17/07 TOA RCT JPB

1 Revised Client Review 9/17/07 TOA OOA AAR

2 Revised Client Review 10/8/07 OOA JAK AAR

3 Revised Client Review 10/25/11 VMC JPB AAR

4 Include Pretreatment facility 4/23/12 VMC DM AAR

This document contains information that is proprietary to CH·IV International, which is to be held in confidence. No disclosure or other use of this information is permitted without the express authorization from the LNG Development Company or CH·IV International.



INTRODUCTION ........................................................................................ 7 1 PURPOSE OF STANDARD ................................................................................. 7 2 REFERENCED DOCUMENTS ............................................................................. 7 2.1

Design Basis...........................................................................................................7

2.2

Design Codes and Standards .................................................................................7

2.3

Piping Specification ................................................................................................7

2.4

Cold Service Insulation Specification ......................................................................7

2.5

Instrumentation Symbols and Identification .............................................................7

3 BASIC DESIGN CONSIDERATIONS .................................................................. 7 3.1

General...................................................................................................................8

3.2

Continuous Operation .............................................................................................8

3.3

Designed for Maintenance ......................................................................................8

3.4

Facility Lighting .......................................................................................................9

3.5

Terminal Life Cycle .................................................................................................9

3.6

Electromagnetic Interference ..................................................................................9

3.7

Electronic Obsolescence ......................................................................................10

3.8

Future Expandability .............................................................................................10

PROCESS AND SYSTEMS DESIGN ....................................................... 10 4 PROCESS FLOW DIAGRAM AND HEAT & MATERIAL BALANCES ............. 10 4.1

Process Flow Streams – LNG Liquefaction ...........................................................10

4.2

Process Flow Streams – LNG Transfer to LNG Carrier ......................................... 11

4.3

Process Flow Streams – LNG Vaporization ..........................................................11

4.4

Boiloff Gas (BOG) Calculation Assumptions .........................................................12




4.5

Process Simulation Cases ....................................................................................12

4.6

Process Flow Streams – Pretreatment..................................................................12

5 TERMINAL LABELING / NUMBERING STANDARD ........................................ 12 5.1

Terminal Areas .....................................................................................................12

5.2

Pipeline Numbering Convention............................................................................13

5.3

Equipment Classification.......................................................................................14 5.3.1

5.4

5.5

Equipment Sub-classification .................................................................................. 14

Equipment, Instrument and Valve Numbering Convention .................................... 15 5.4.1

3 and 4 Digit Rule .................................................................................................... 15

5.4.2

Identical Equipment in Parallel Service ................................................................... 15

5.4.3

Valve Numbering ..................................................................................................... 15

Line Specification .................................................................................................16

6 PIPING & INSTRUMENTATION DIAGRAM (P&ID) STANDARD ..................... 16 6.1

Basic Considerations ............................................................................................16

6.2

P&ID Numbering ...................................................................................................16

6.3

P&ID Organization ................................................................................................17

6.4

PSV/TSV Standardization .....................................................................................17

6.5

Vent/Drain Valves .................................................................................................17

6.6

Field Instrumentation ............................................................................................18 6.6.1

Local Indication ....................................................................................................... 18

6.6.2

Combined Pipe Penetrations .................................................................................. 18

7 PIPING - GENERAL ........................................................................................... 18 7.1

Design Fluid Velocities .........................................................................................18

7.2

Design Pressure ...................................................................................................19

7.3

Use of Flanges .....................................................................................................19

7.4

De-Inventory of LNG Transfer System ..................................................................19




7.5

LNG Pipe Penetrations .........................................................................................19

7.6

Thermal Relief Valves ...........................................................................................19 7.6.1

Set Pressure ............................................................................................................ 19

7.6.2

TSV Take-Off Elevation........................................................................................... 20

7.6.3

TSV Discharge ........................................................................................................ 20

7.7

LNG Sample Points ..............................................................................................20

7.8

LNG Piping Headers .............................................................................................20

8 CRYOGENIC INSULATION ............................................................................... 20 9 CRYOGENIC INSTRUMENT PIPING DETAILS ................................................ 21 9.1

Vessel Level Instruments - General ......................................................................21

9.2

Liquid Level Taps on a Vessel ..............................................................................21

9.3

Liquid Differential Pressure Taps on a Vessel.......................................................22

9.4

Liquid Pressure Tap on a Vessel ..........................................................................22

9.5

Horizontal Liquid DP Flow Meters .........................................................................23

9.6

Vertical Liquid DP Flow Meters .............................................................................23

10 LNG TRANSFER AND COOLDOWN ................................................................ 24 10.1 Transfer Piping .....................................................................................................24 10.2 LNG Loading Arm Draining ...................................................................................24

11 LNG TANK DESIGN REQUIREMENTS ............................................................ 24 11.1 LNG Tank Discretionary Vent ...............................................................................24 11.2 LNG Tank Vapor Makeup .....................................................................................24 11.3 LNG Tank Recirculation ........................................................................................25 11.4 LNG Tank Isolation ...............................................................................................25 11.5 LNG Tank Boiloff Gas Flow Measurement ............................................................25 11.6 LNG Tank Top and Bottom Fill Flow Measurement...............................................25 This document contains information that is proprietary to CH·IV International, which is to be held in confidence. No disclosure or other use of this information is permitted without the express authorization from the LNG Development Company or CH·IV International.



12 MAINTENANCE COOLING OF THE TERMINAL .............................................. 25 12.1 Vertical Risers ......................................................................................................25 12.2 Standby LNG Pumps ............................................................................................25 12.3 Small Bore LNG Piping .........................................................................................26 12.4 Idle Operation .......................................................................................................26

13 VENT / DRAIN SYSTEM .................................................................................... 26 13.1 Vent System .........................................................................................................26 13.2 Double Block & Bleed Vents .................................................................................26 13.3 Vent and Drain Systems .......................................................................................26

14 DRYOUT AND COOLDOWN ............................................................................. 27 14.1 Initial Dryout and Cooldown ..................................................................................27 14.2 LNG Tank Cooldown ............................................................................................27

SAFETY DESIGN ..................................................................................... 27 15 EMERGENCY SHUTDOWN SYSTEM STANDARD .......................................... 27 15.1 Position Indicators on ESD Valves ........................................................................27 15.2 Use of Control Valves to Serve as ESD Valves ....................................................28 15.3 Positioners on ESD Valves ...................................................................................28 15.4 Emergency Shutdown System (ESD) Logic ..........................................................28

16 CAR SEALING STANDARD .............................................................................. 28 16.1 Introduction ...........................................................................................................28 16.2 Use of Car Seals ..................................................................................................29

17 DOUBLE BLOCK AND BLEED STANDARD .................................................... 30

ELECTRICAL DESIGN ............................................................................ 30 This document contains information that is proprietary to CH·IV International, which is to be held in confidence. No disclosure or other use of this information is permitted without the express authorization from the LNG Development Company or CH·IV International.



18 STANDBY AND BACK-UP ELECTRIC POWER............................................... 30 18.1 Standby Electric Power Generator ........................................................................30 18.2 Uninterruptible Power Supply (UPS) Systems ......................................................31

CONTROL SYSTEM DESIGN .................................................................. 31 19 CONTROL SYSTEM DESIGN STANDARD ...................................................... 31 19.1 Description ...........................................................................................................31 19.2 Design Philosophy ................................................................................................31 19.2.1 Control Rooms ........................................................................................................ 32 19.2.2 Field Instruments ..................................................................................................... 32 19.2.3 Instrumentation Power Supply ................................................................................ 32




INTRODUCTION 1

PURPOSE OF STANDARD This Standard establishes essential requirements and minimum standards for the design, installation and safe operation of the Oregon LNG Terminal (the “Terminal”) that is to be constructed on t he Skipanon peninsula in Oregon by LNG Development Company. This standard is to be used in conjunction with the Design Basis document 07902-TS-000-002. This standard delineates areas of particular interest that the Engineer (CH·IV International) shall focus on i n the preparation of the Front End Engineering Design and which EPC companies shall integrate into their own engineering, procurement and construction (EPC) standards. In addition to this Standard, the Terminal design shall comply explicitly with the Federal LNG Safety Code (49CFR Part 193) and NFPA 59A (2001 edition).

2

REFERENCED DOCUMENTS 2.1

Design Basis Document 07902-TS-000-002

2.2

Design Codes and Standards Document 07902-TS-000-022

2.3

Piping Specification Document 07902-TS-000-104

2.4

Cold Service Insulation Specification Document 07902-TS-000-105

2.5

Instrumentation Symbols and Identification ISA-5.1

3

BASIC DESIGN CONSIDERATIONS



3.1


General The Terminal shall be of proven design, built to current design codes and standards listed in the Design Codes and Standards document (07902-TS-000-022). The design is further aimed at giving “state-of-the-art” levels of operability, reliability, availability and maintainability. Only cryogenic equipment from vendors who have a proven record of operation in LNG service shall be used in this Terminal. This equipment shall include but not be limited to LNG (un)loading arms, storage tanks, compressors, liquid expanders, pressure vessels, pumps, heat exchangers, valves, piping and instrumentation. T he use of different manufacturers or types of vendor-supplied equipment for similar applications shall be minimized in order to improve the operability and maintainability of the Terminal and to consolidate and therefore minimize the holding of spare parts required. The Terminal shall be designed to permit unconstrained operation over the absolute range of ambient conditions referred to in the Design Basis. It shall be provided with suitable weather protection to enable all operation and maintenance procedures to be undertaken under all design weather conditions.

3.2

Continuous Operation The Terminal shall be designed for continuous LNG liquefaction, LNG sendout or LNG vaporization operations except in the case of a total power outage. Sufficient sparing and equipment isolation shall be included such that normal maintenance and inspection can be accomplished while sustaining the design liquefaction, LNG sendout or LNG vaporization rates. Although the Terminal shall be designed for continuous service, it is understood that the LNG liquefaction system will require annual scheduled outages of approximately 1 week duration.

3.3

Designed for Maintenance The Terminal design shall facilitate ease of on-site maintenance of all equipment, including adequate clearance for maintenance access. In-place overhead lifting equipment shall be included for all compressors, pumps and any other critical areas as determined by the Engineer. Adequate clearance shall be provided in all such areas for the vertical removal of equipment. Double doors or roll-up overhead doors shall be provided on compressor and pump buildings to allow for the removal of equipment. R emovable roof panels shall not be employed. P latforms, ladders, stairways, walkways and landings shall be provided as required for access to buildings, equipment, valves and instrumentation. G enerally, all valves,




instrumentation and inspection ports that are mounted at an elevation of 6 f eet or higher shall be provided with platforms for operational access. The overall Terminal layout shall allow for ease of access to equipment and buildings by a variety of vehicles including trucks and lifting equipment as well as any other vehicles required for the operation and maintenance of the Terminal. Site access roads shall comply with requirements specified by local fire department(s). Walkways shall be provided throughout the Terminal for pedestrian access. 3.4

Facility Lighting Adequate lighting shall be installed in all operational areas such that work may be performed safely at any time. These areas include, but are not limited to process and utility areas, all roads and accesses, office and maintenance areas, the marine pier area and tanks. Facility lighting design shall take “light pollution and energy efficiency” into account. The lighting system in the marine transfer area shall comply with the requirements of 33CFR127.109.

3.5

Terminal Life Cycle The Terminal shall be designed for a l ife cycle of at least 25 years. A fter 25 years operation the Terminal may be subject to a program of refurbishment to extend the life. Equipment and components normally subject to wear and deterioration need not have a life of 25 years. T his equipment shall, however, be designed to have maximum practical life and shall be designed with adequate sparing so as to allow for continuous operation of the Terminal at base load.

3.6

Electromagnetic Interference The Terminal and equipment (including computers, control and telecommunication systems) shall be designed to avoid generation of unacceptable electromagnetic interference and to avoid susceptibility to such interference from such items during testing, commissioning and normal operation. If necessary, electromagnetic screening features shall be incorporated to ensure reliable immunity to such interference at all times.



3.7


Electronic Obsolescence Computers, controls, instrumentation, control systems and telecommunications shall be designed based on latest proven technology so as to avoid obsolescence and loss of technical support from the supplier.

3.8

Future Expandability Where future expansion plans have been identified, accommodation shall be made in the design to allow for this expansion with minimum future interruption of Terminal operation. This may include reservation of plot plan space for future equipment and provision of extra capacity when sizing control systems, safety systems, pipelines/manifolds, pipe racks, utility systems, auxiliaries, cable trays and electrical switchgear space (bus configuration). W here appropriate, tie-in points with valves and/or blind flanges shall be provided.

PROCESS AND SYSTEMS DESIGN 4

PROCESS FLOW DIAGRAM AND HEAT & MATERIAL BALANCES Where applicable, the following specific streams (conditions) shall be included in Heat & Material Balance (H&MB) tables with identifying labels for each on the Process Flow Diagram (PFD). 4.1

Process Flow Streams – LNG Liquefaction •

Feed Gas entering the Liquefaction Systems

•

All natural gas streams entering and exiting heat exchangers, compressors and phase separators, including intercoolers/aftercoolers of compressors

•

Propane refrigerant and Mixed Refrigerant streams entering and exiting heat exchangers, Main Cryogenic Heat Exchanger (MCHE), compressors, liquid expanders and phase separators, including intercoolers/aftercoolers of compressors

•

All gas streams entering and exiting heat exchangers and phase separators, including intercoolers/aftercoolers of compressors

•

LNG downstream of final pressure let down device after MCHE, JT valves and LNG liquid expanders, LNG flash drum, LNG flash exchanger, nitrogen rejection column (NRC), and LNG liquid expanders.

•

Vapors from the LNG flash drum and NRC, if used.


Oregon LNG Terminal Warrenton, OR Engineering Design Standard •

4.2

4.3


LNG entering LNG tank(s) after liquefaction

Process Flow Streams – LNG Transfer to LNG Carrier •

LNG in storage in the LNG tank(s)

•

LNG at discharge of the LNG Transfer Pump

•

LNG at loading arm flange

•

LNG storage conditions in cargo tanks of the LNG carrier

•

Vapor returning from the LNG carrier, i.e., vapor at inlet to Dock Blowers, if used

•

Vapor at discharge of Dock Blowers, if used

•

Vapor entering/exiting LNG tank vapor space

•

Vapor at BOG Desuperheater prior to BOG Drum, if used

•

Vapor at inlet to BOG Compressors, if used

•

Vapor exiting BOG Compressors, if used

•

Fuel gas consumed by the gas-fired equipment, if used.

Process Flow Streams – LNG Vaporization •

LNG in LNG Storage Tank

•

LNG at discharge of In-Tank Pump

•

LNG entering Vapor Condenser, if used

•

LNG exiting Vapor Condenser, if used

•

Condensed BOG exiting Vapor Condenser, if used

•

LNG to HP Pumps

•

LNG at inlet to LNG Vaporizer

•

Natural Gas at outlet of Vaporizer

•

Vapor displaced into LNG Storage Tank

•

Vapor at inlet to BOG Compressors, if used

•

Vapor exiting BOG Compressors, if used

•

Heat Transfer Fluid, if used, entering LNG vaporizers

•

Heat Transfer Fluid, if used, exiting LNG vaporizers

•

Fuel gas consumed by the Heat Transfer Fluid heaters, if used.



4.4


Boiloff Gas (BOG) Calculation Assumptions Refer to Design Basis 07902-TS-000-002.

4.5

Process Simulation Cases Refer to Design Basis 07902-TS-000-002.

4.6

5

Process Flow Streams – Pretreatment •

Feed Gas entering the Pretreatment Facility

•

All natural gas streams (excluding fuel gas) entering and exiting heat exchangers, compressors, phase separators, and amine contactors

•

All acid gas streams entering and exiting heat exchangers, compressors, phase separators, and stripper towers

•

All amine adsorbent streams entering and exiting heat exchangers, pumps, phase separators and contactor and regeneration towers

TERMINAL LABELING / NUMBERING STANDARD 5.1

Terminal Areas The Terminal shall be divided into a finite number of process and other system areas with equipment in any given area being numbered to identify that area. The following Terminal area codes shall be used for both document and equipment identification. Code

Description

000

General, Miscellaneous, Informational

100

Dock/Pier Process Systems

200

On-shore, Low Pressure (150#) Process Systems

300

High Pressure Process Systems

400

Auxiliaries Supporting Process (Heat Transfer Fluid Systems, Compressor Lube Oil Systems, steam, etc.)

500

Electrical

600

Fire Detection/Mitigation Systems, including LNG Spill Containment Sumps

700

Control System



5.2


800

Civil Works (Buildings, Roads, etc.)

900

Utilities

1000

Pretreatment Facility Process and Utilities

2000

Liquefaction Process including Refrigerant Systems

4000

Auxiliaries supporting the Liquefaction Process, including refrigerant storage and cooling water systems.

Pipeline Numbering Convention Pipeline numbers shall follow the line numbering convention shown in Figure 5.2: Figure 5.2 – Line Numbering Convention

where,

1

•

Line Service is the fluid in that given line (See 07902-PI-000-007 for total listing of services).

•

Line Number is a unique number associated with the specific Line Service – see Section 5.1.

•

Line Number Modifier is typically A – B – C, etc. for identical, parallel equipment 1.

•

Line Size is the Nominal Pipe Size (NPS) in inches.

•

Line Specification defines the metallurgy, pressure and temperature rating of the line in question (See 07902-PI-000-007 for listing of Line Specifications).

•

Insulation Specification defines the thickness and type of the insulation (if used) of the line in question (See 07902-PI-000-007 for listing of insulation Specifications).

Sometimes A or B may be used to define manifold branches rather than parallel service.



5.3


Equipment Classification Major equipment shall be assigned abbreviation designations as follows: Type of Equipment Designation Buildings / Shelters A Boilers / Heaters B Compressors / Blowers C Drums / Pressure Vessels D Heat Exchangers / Vaporizers E Fire Fighting F Fire Water Monitor FM Fire Water Hydrant FH Fire Water Hose Reel FR Generators G HVAC / Building Heaters H Special Equipment / Packaged Equipment Skids L Motors M Pumps/Expanders P Tanks T Manual Valves (no remote control or powered operator) V 5.3.1

Equipment Sub-classification Equipment that is dedicated to a given piece of equipment, part of vendor packages and/or related to certain hazard mitigation equipment may include multiple letter designations. For example: 

The motor of a pump may be designated with PM, where the “P” indicates it is a pump and the “M” indicates it is the motor on that pump.



The compressor that is part of an instrument air package may have the designation LC, where “L” indicates it is Packaged and “C” indicates the Compress in that package.



The pump that is part of a fire protection package, such as a high expansion foam system, may have the design nation FLP, where “F” indicated Fire Fighting, “L” indicates it is part of a vendor package and “P” indicates it is a pump.



5.4


Equipment, Instrument and Valve Numbering Convention To aid in electronic sorting and electronic filing of equipment information, equipment shall be labeled first by the classification (Section 5.3) designation followed by a unique number for the piece of equipment. For example a pressure vessel could be D-203. 5.4.1

3 and 4 Digit Rule Due to the relatively small number of systems and “units” of an LNG terminal, equipment, instrument and valve numbers shall be limited to 3 or 4 digits. For example: a pressure control valve in Area 100 – PV-102; an LNG pump in Area 2600 – P-2602, etc. a flow controller in Area 300 – FIC-302. If the Engineer’s design software requires more than 4 digits, then the first digit shall always be 0 (zero). The equipment number shall be unique. 2 For example if the C-204 is the BOG Compressors, there should be no ot her piece of equipment sharing the “204” designation, unless there is an “A/B/C” modifier (see below) or that piece of equipment is directly associated with the C-204, such as its electric motor which would be the CM-204.

5.4.2

Identical Equipment in Parallel Service Identical equipment (process equipment, valves, instrumentation, relief valves, etc.) and piping in parallel operation shall be given A/B/C modifiers of the same basic equipment number and not a wholly unrelated numbering. This rule shall also apply to line numbers, as well. F or example: FV-110A and FV-110B; T-201A and T-201B; PIC-320A and PIC-320B; TSV-310A and TSV-310B; LNG-205A-12" and LNG-205B-12"; E-2010A and E-2010B.

5.4.3

Valve Numbering Control valves shall follow the ISA-5.1 standard for valve numbering. All manual valves, regardless of size, shall be uniquely identified in the final design. A ll valve numbers shall be shown on the P&IDs. Manual (hand) valves shall use the designation “V.” P lease note the numbering system for valves associated with PSVs and TSVs discussed under the “PSV/TSV Standardization” in Section 6.4 below. A permanent, weatherproof tag indicating the unique identifier shall be affixed to each valve, manual or control, and each piece of instrumentation. T hese shall be supplied and installed by the vendor supplying each item.

2

Instruments, valve numbers and line numbers, however can share the same three digit number.



5.5


Line Specification Due to the relatively small number of piping classes typically used in an LNG terminal, line specifications shall be limited to 4 digits, with a fifth digit permitted to indicate above or below grade, if necessary. T he Engineer’s standard line specifications might have more digits, in which case the Engineer shall use the 4 digit convention with a cross reference. T he primary criteria of interest are the pressure rating of the piping and the metallurgy. A table of the Line Specifications used is included in 07902-PI-000-007. See LNG Plant Piping Specification 07902-TS-000104 for more information on Line Specifications.

6

PIPING & INSTRUMENTATION DIAGRAM (P&ID) STANDARD 6.1

6.2

Basic Considerations 1.

Provide alphanumeric grid [A-1] on all P&IDs.

2.

Identical or similar pages of P&IDs shall have same drawing number with a trailing two-digit sequential identifier (-01, -02 etc.)

3.

Provide a Table of Contents of the P&IDs (Drawing List) and Equipment List indexed by P&ID number on the first page of the P&ID set.

4.

Provide equipment specifications for equipment above or below each piece of equipment.

5.

Process line connectors should leave and enter P&ID pages in approximate similar locations with a unique reference number.

6.

Pipe specification class breaks shall be properly designated and shown.

P&ID Numbering The P&ID Number is composed of the following codes as depicted in the example below: XXXXX-PI-YYY-ZZZ-WW where •

XXXXX = five digit CH·IV Project Number. For this project, the project number is 07902.

•

PI = Document Type (here PI = Piping & Instrumentation Diagram)

•

YYY = Terminal Area, as described in Section 5.1, YYYY for systems associated with liquefaction and liquefaction auxiliaries.



6.3


•

ZZZ = Page Number, starting with the Sequence Number as described in Section 6.3

•

WW = two-digit sequential identifier, to be used only for multiple identical or similar P&IDs

P&ID Organization The P&IDs shall be in numerical sequence organized 3 by the Codes defined in Section 5.1. For example, the first drawing number in the Introductory P&IDs would be XXXXX-PI-000-001.

6.4

PSV/TSV Standardization All TSV and PSV systems shall be shown on the P&IDs, however to simplify the amount of information shown on any given P&ID, a reference “block” may be shown in place of showing all TSV/PSV detail. Valve numbering and arrangement for each TSV/PSV shall follow the convention shown in reference diagram. Where sitespecific reason to deviate, the details will be shown on t he specific P&ID. T he pressure set point for all TSV/PSV shall be shown adjacent to the TSV/PSV number.

6.5

Vent/Drain Valves All vent points in LNG service, exclusive of lines served by TSV or PSV, require two valves, one venting into the BOG Header or Low Point Drain system and a second valve vented to atmosphere. For high pressure systems (>900#), additional block and bleed valves are required on drain valve configurations. These configurations are shown in Figure 6.5.

3

Gaps in the numerical sequence are permitted to allow for future expansion.



Job No. 07902 Doc No. 07902-TS-000-001 Rev 4 Page 18 of 33 Figure 6.5 – Vent / Drain Valve Standardization

6.6

Field Instrumentation 6.6.1

Local Indication Use local indicating instrument transmitters in lieu of a local gauge and separate transmitter wherever possible. Exceptions would include where the transmitter is not readily visible, in which case a l ocal indicator may be required. This determination is on a case-by-case basis after piping layout has been resolved.

6.6.2

Combined Pipe Penetrations The Engineer shall combine pipe penetrations wherever possible. For example, if PT and PDT are found together, use the upstream tap of PDT for PT.

7

PIPING - GENERAL 7.1

Design Fluid Velocities Maximum design steady-state velocities: Low Pressure Hydrocarbon ............ 10 ft/sec High Pressure Hydrocarbon ........... 15 ft/sec Transient Hydrocarbon Flow ......... 20 ft/sec Hydrocarbon Vapor ......................... 75 ft/sec Water / Heat Transfer Fluid ............ 10 ft/sec




Other Non-Low Viscosity Fluids ... 10 ft/sec 7.2

Design Pressure For FERC jurisdictional facilities such as Oregon LNG, unless protected by HIPPS (high integrity process protection systems) the specified design pressure of all pressure retaining components in each cryogenic or natural gas piping system shall be no less than the pressure rating of the piping in that system.

7.3

Use of Flanges All efforts shall be made to minimize the use of flanges in cryogenic piping. A ll cryogenic valves are to be welded unless specifically identified otherwise. V essels and equipment shall use welded connections, except where entry for inspections or maintenance after start-up is anticipated or required, such as exchangers. In these cases there shall be a case-by-case evaluation to confirm flanges are required. Belleville® washers shall be utilized for all flanged connections in LNG or cryogenic service.

7.4

De-Inventory of LNG Transfer System Provisions shall be made to allow for the de-inventorying of large volume liquid hydrocarbon systems, such as LNG Transfer Systems, subsequent to the initial startup of the Terminal. Every isolation/control/ESD valve in these systems shall have de-inventory bypasses to be sized by the Engineer. The design shall include a manual valve and check valve to the tank side of the valve. A ll piping shall be sloped accordingly to allow de-inventorying. There shall be similar de-inventory systems at the fill line into each tank.

7.5

LNG Pipe Penetrations Small diameter weld penetrations increase pipe thermal stresses during cooldown. Consequently, all piping penetrations for vents, drains and sensing lines for instruments shall be evaluated. If the thermal stresses for a given penetration cannot be diminished by pipe hangers or pipe supports, the penetration shall be a minimum of 2". A ll efforts shall be made to minimize the number and size of penetrations. Wherever possible, combine penetrations for sensing lines for levels, pressures and differential pressures for both local and remote instrumentation.

7.6

Thermal Relief Valves 7.6.1

Set Pressure




Thermal Safety Valves (TSV) shall be set for no less than the design pressure of the line based on f lange rating, even if no flanges are present on that system. 7.6.2

TSV Take-Off Elevation All TSV installations shall take into consideration the elevation of the take-off relative to the piping being protected such that its discharge shall not result in releasing LNG from piping of higher elevation.

7.6.3

TSV Discharge Note: For FERC jurisdictional facilities such as Oregon LNG, TSVs should discharge into an independent collection system or directly into an LNG line.

7.7

LNG Sample Points LNG sample points shall be located in such a way that potential for contamination from flows from other sources is eliminated. For example, the LNG transfer sample point shall be located before the tie-in of the recirculation cooling line. S imilarly, LNG samples from individual tanks must be located on the dedicated pump out line from that LNG Storage Tank upstream of the LNG Storage Tank recirculation crossover.

7.8

LNG Piping Headers LNG headers and dead headed piping shall be provided with a means for maintenance cooling. P iping that serves in intermittent operation shall also be provided with a means for maintenance cooling.

8

CRYOGENIC INSULATION See the Cold Service Insulation Specification 07902-TS-000-105 for details on insulation of cold and cryogenic services.



9


CRYOGENIC INSTRUMENT PIPING DETAILS 9.1

Vessel Level Instruments - General All pressure vessels with at least two level systems should have one for the expected operating range and the second covering tangent to tangent (minimum).

9.2

Liquid Level Taps on a Vessel



9.3

Liquid Differential Pressure Taps on a Vessel

9.4

Liquid Pressure Tap on a Vessel




9.5

Horizontal Liquid DP Flow Meters

9.6

Vertical Liquid DP Flow Meters





10 LNG TRANSFER AND COOLDOWN 10.1

Transfer Piping It is the preference of the Owner that the transfer piping should be configured with one large bore (>32") and one small bore line. Line sizing shall remain the responsibility of the Engineer. However, LNG recirculation rates to maintain piping temperatures shall be based on a maximum LNG temperature rise of 10°F but no less than 500 gpm, whichever controls. The temperature difference shall be measured on the LNG Recirculation Line and the LNG Transfer Line as close to the fill header as practical.

10.2

LNG Loading Arm Draining The piping for each arm shall be sloped toward the LNG header with a r emotely controllable bypass valve around each LNG arm valve. Nitrogen pressure shall be used to de-inventory the LNG arms into the LNG header and back onto the ship.

11 LNG TANK DESIGN REQUIREMENTS 11.1

LNG Tank Discretionary Vent There shall be a single Vent Header pressure control valve connected at or near the high point of the BOG Header. The valve shall operate on the highest gauge pressure sensed on any of the LNG Storage Tanks. There shall be no additional vents/drains entering the piping between this valve and the Flare Stack. T he Vent System downstream of the Vent Header pressure control valve shall be swept with a minimal flow of nitrogen gas. Note: For FERC jurisdictional facilities such as Oregon LNG, a discretionary vent atop each LNG storage tank shall be provided with a remotely-operated discretionary vent.

11.2

LNG Tank Vapor Makeup The Engineer shall determine requirements to send gas to the vapor spaces of the LNG Storage Tank due to the draw-down of the LNG from the tank(s).



11.3


LNG Tank Recirculation Provision shall be made to circulate the LNG in any given tank from bottom to top at the maximum pumping rate of all of the installed pumps for a given tank. T his recirculation shall be accomplished without interfering with normal LNG liquefaction, LNG transfer pipeline recirculation and send-out flows.

11.4

LNG Tank Isolation LNG Storage Tanks shall be provided with isolation flanges and/or valves to allow a tank to be taken out of service while normal terminal operations continue using other tank(s).

11.5

LNG Tank Boiloff Gas Flow Measurement Note: For FERC jurisdictional facilities such as Oregon LNG, flow measurement shall be provided for boiloff gas exiting each LNG storage tank.

11.6

LNG Tank Top and Bottom Fill Flow Measurement Note: For FERC jurisdictional facilities such as Oregon LNG, flow measurement shall be provided for LNG entering the top and bottom fill lines of each storage tank. Flow measurement is indicative only and is to be used to ensure the tank fill rates are not exceeded. This flow measurement needs to be accurate only in the range of the maximum permitted fill rate.

12 MAINTENANCE COOLING OF THE TERMINAL 12.1

Vertical Risers Provision shall be made to circulate all vertical risers (fill and pump discharge) on each LNG Storage Tank with LNG for the purposes of maintenance cooling. Provision shall also be provided to prevent geysering of these lines.

12.2

Standby LNG Pumps Provision shall be made to assure that all LNG pumps in stand-by service are maintained in a fully cooled down state ready for operation.



12.3


Small Bore LNG Piping Piping of 8" or less may be designed for rapid cooling. Long runs of piping greater than 8" shall be provided means to maintenance cool the section of pipe. T he technique most often can be accomplished with a 2" line with a restriction orifice (RO) installed as a bypass on a closed control valve.

12.4

Idle Operation During periods when there is no LNG production or sendout, provision shall be made to maintain all LNG piping in a fully cooled down state ready for operation.

13 VENT / DRAIN SYSTEM 13.1

Vent System The Terminal shall be designed to minimize fugitive emissions with no venting during all normal operations, except for the acid gas vent from the Amine process in the Pretreatment facility which will be vented to atmosphere through a thermal oxidizer All LNG and NG relief valves (excluding LNG Storage Tank, fuel gas, vaporizer outlet relief valves and feed gas to liquefaction) shall relieve to a closed relief system that is in common with the LNG Storage Tank vapor spaces. In case of excess relief system pressure, the BOG Header pressure control valve shall direct gas to the Flare Stack. A continuous nitrogen gas sweep shall be incorporated downstream of the control valve to ensure proper purging of the Flare Stack. For the LNG Liquefaction unit all process LNG, MR and NG relief valves shall relieve to the Dry Gas Flare.

13.2

Double Block & Bleed Vents All de-pressuring vents associated with Double Block and Bleed isolation systems shall have both a valve to the Vent/Drain System and an ambient bleed valve.

13.3

Vent and Drain Systems For LNG systems, there shall be separate vent and drain header system for gas and for liquids. These header systems shall drain into an un-insulated Low Point Drain Drum, which vents into the BOG Header. T he Low Point Drain Drum shall be designed to allow isolation and pressurization for heavy hydrocarbon liquid removal.




Additionally, provision shall be made to allow personnel to perform draining operations without being in the proximity of the drum. Note: For FERC jurisdictional facilities such as Oregon LNG, an alternate drain shall be provided from the drain of the uninsulated low-point knock-out vessel to the top of the LNG tank or an LNG line through a dedicated line. Additionally, provision shall be made to allow personnel to perform draining operations without being in the proximity of the drum. For the Liquefaction Unit propane, natural gas and mixed refrigerant shall be a directed to a separate vent/drain header for gas and for liquids. The liquid drain header shall drain into a Cold Liquid Disposal before going into the Cold Gas Flare. The gas shall flow into the Cold Gas Flare system. Where acid gases is handled, such as in feed gas pretreatment, there will be a second flare system, the Warm Gas Flare, for handling such gas streams.

14 DRYOUT AND COOLDOWN 14.1

Initial Dryout and Cooldown Design provisions shall be made for the initial dryout and cool down of the LNG Transfer System. Similar design provisions shall be made for the initial dryout and cool down of the balance of Terminal LNG piping.

14.2

LNG Tank Cooldown Each LNG Storage Tank shall have the capability of using LNG or liquid nitrogen (LIN) for its initial cooldown. A ppropriate design temperatures for this equipment shall be used.

SAFETY DESIGN 15 EMERGENCY SHUTDOWN SYSTEM STANDARD 15.1

Position Indicators on ESD Valves All ESD valves shall have position indicators. Open/close valve position switches and/or valve position indication feedback are acceptable.



15.2


Use of Control Valves to Serve as ESD Valves On a cas e-by-case basis, control valves can also be used as ESD valves where such use does not diminish the intent of the ESD activation. This may also require higher degrees of shut off, fire-safe installation and provision of hand wheels to some valves.

15.3

Positioners on ESD Valves On a cas e-by-case basis, positioners are permitted to be added to ESD valves to provide remotely controllable, throttle-able operation. All valves require independent valve position switches indicating when the valve is not fully closed.

15.4

Emergency Shutdown System (ESD) Logic The Emergency Shutdown System (ESD) is provided to initiate closure of valves and shutdown of process drivers under emergency situations. A ll other shutdowns that are process related trips are not emergency shutdowns. T he ESD system has three elements: ESD-1:

Shutdown of (un)loading operations and isolation of the marine facility

ESD-1-1: Activates the Emergency Release Couplings (ERC) on all of the arms. ESD-2:

Shutdown of LNG/NG operations including ESD-1.

16 CAR SEALING STANDARD 16.1

Introduction The Owner recognizes that a management plan for control/monitoring of all valves is warranted and a program will be developed to meet the operational and safety requirements for personnel protection and equipment/piping integrity and environmental protection. Foremost to the Owner is the implementation of a program that prevents an improper valve alignment, which creates an unsafe condition for personnel, and secondly, implementation of a program to provide contingency protection when removing an over-pressure safety device from service. A rigorously enforced car seal program permits a sizable reduction in the number of thermal relief valves installed in an LNG terminal without reducing the level of safety and protection to the piping system. For these purposes, the Car Seal Program will be developed. A car seal is a physical tie that once installed must be cut or broken for the valve to be operated. Each valve when sealed has two identically numbered weather-proof discs. One is permanently




attached to the valve body while the other is attached with a car seal to the valve in a manner that prevents the valve from being operated without breaking the seal. A Car Sealed Open (CSO) valve is equivalent to an open section of pipe from a process design standpoint whereas a Car Sealed Closed (CSC) valve is equivalent to a weld cap. 16.2

Use of Car Seals Car seals are devices used on valves with equipment or piping when: 1)

They provide personnel protection from inadvertent ambient release. Example: A vent valve to atmosphere should be CSC if inadvertent operation while in normal operation results in a pressurized stream of LNG being released.

2)

Improper position results in effectively removing relief valve protection. Example: Inlet and outlet block valves must be CSO on a ny relief valve. Similarly, the sensing lines for pilot operated relief valves shall be CSO.

3)

Relatively minor operating error with potential to trap a cryogenic fluid in a section of pipe. Example: Any isolation valve on a piece of equipment shall be CSO if its closure could result in trapping of LNG in a section of pipe not protected by a thermal relief.

4)

They assure the proper alignment of the fire suppression and protection systems. Example: The main firewater system block valve to fire water distribution shall be CSO.

5)

The loss of equipment being protected has the potential to create an upset in the process and/or produce significant economic cost. Example: Any isolation valve on LNG pump recycle lines shall be CSO.

6)

Documentation of valve use as required by the Terminal SPCC Plan. Example: The bypass valve on a wastewater treatment/collection system shall be CSC if it leads directly to the outfall.

7)

They potentially minimize the frequency of maintenance of LNG process equipment. Example: Any isolation valve on the pump pot vent shall be CSO in order to provide the thermal path to insure no vapor lock in the pot.




17 DOUBLE BLOCK AND BLEED STANDARD To assure 100% reliable operation and employee safety, the Terminal shall be designed with the following philosophy regarding non-instrumentation equipment isolation: ♦

LNG and Flammable Refrigerant Service - Equipment shall be isolated from all sources of LNG/flammable refrigerant using a “Double Block and Bleed” (two block valves depressured by an intermediary valve to vent) philosophy. Check valves shall not be considered as block valves for this purpose.

♦

Cold (-40°) and cryogenic gas service at 150 # class and below - Equipment shall be isolated from a source of cryogenic gas by a single block valve.

♦

Cold (-40°) and cryogenic gas service at 300 # class and above - Equipment shall be isolated from a source of cryogenic gas by a “Double Block and Bleed” philosophy. Check valves shall not be considered as block valves for this purpose.

♦

Warm (above -40°) gas service for 150 # class - A single block valve shall be sufficient.

♦

Warm (above -40°) gas service for 300 # class and above - A “Double Block and Bleed” philosophy shall apply. Check valves shall not be considered as block valves for this purpose.

♦

Toxic Service (above OSHA IDLH limit) 4 - Equipment shall be isolated from the components indicated using a “Double Block and Bleed” (two block valves depressured by an intermediary valve to vent) philosophy. Check valves shall not be considered as block valves for this purpose.

♦

Situations not covered above shall be handled individually and shall be based on a Hazards Analysis and/or a RAM analysis.

ELECTRICAL DESIGN 18 STANDBY AND BACK-UP ELECTRIC POWER 18.1

Standby Electric Power Generator One 100% standby power generator set shall be provided, capable of providing enough power to maintain LNG circulation via operation of one LP Pump, Terminal lighting, all control systems and provide for the operation of all other necessary auxiliary systems.

4

Hydrogen Sulfide, Mercaptans and CO2.



18.2


Uninterruptible Power Supply (UPS) Systems The 2 x 100% UPS system shall have a minimum combined battery life of 4 hours. The UPS unit(s) shall be rated for 120% of its related load and include an output automatic static transfer switch to an alternative 3Ø VAC supply, an emergency manual bypass switch for supply from a different 3Ø [440/230] VAC supply, and all necessary indications with local alarm lamps and remote alarms in the Main Control Room. The UPS units shall be located in air-conditioned rooms, and may be included in the AC switchgear or DC switchboard rooms as required and shall assure the operation and functioning of the process controls, ESD, and Fire Safety systems. The UPS shall be powered by either NiCad or Valve Regulated Lead Acid (VRLA) batteries.

CONTROL SYSTEM DESIGN 19 CONTROL SYSTEM DESIGN STANDARD 19.1

Description The control systems shall be comprised of a single vendor distributed control system (DCS) and operator interface, instrumentation, cabling, terminations, enclosures, marshalling, etc. T he Distributed Control System shall allow communication with each instrument sub-system via Modbus RTU protocol, utilizing Ethernet or serial connections, or hardwired connections. T he DCS shall provide the sole means of process remote control and supervision of the Terminal from the Main Control Room (MCR) and at the Platform Control Room (PCR). Stand alone, single vendor Safety Instrumented System (SIS) and Hazard Detection & Mitigation System (HDMS), which may be programmable logic controller (PLC)based, shall be provided to continuously monitor and alert the operator of hazardous conditions throughout the Terminal. The SIS and HDMS shall be fault-tolerant and be designed in such a manner as to eliminate sources of single point failure. Monitoring capability for these systems shall be provided via graphic display screens and/or mimic panel displays located in the MCR and the PCR. SIS and HDMS shall be interfaced with the DCS.

19.2

Design Philosophy The control system shall be designed and configured such that no single component failure will result in a Terminal trip, failure to inhibit a hazard condition or loss of control. T o achieve this, all provided components shall be readily maintainable during operations. O nline replacement should be possible. Protection and trip




parameters shall be sampled through multiple inputs and use a majority logic voting system. The DCS shall have the capability to monitor, control, display, alarm, record and trend all assigned inputs and outputs. T he operator interfaces shall be simple and clear and based on good Human Factor Engineering principles. The system architecture consists of the following sub-systems: •

Distributed Control Systems (DCS)

•

Operating and Monitoring System

•

Engineering Workstations

•

Maintenance Workstations

•

Bus system for the communication between I&C components and stand-alone sub-systems (e.g., compressor control system).

•

Safety systems (SIS and HDMS)

19.2.1 Control Rooms The MCR, PCR and Administration Building shall contain the operator interface or Human-Machine Interface (HMI). The HMI shall be through computer-based workstations, running specialized software designed for that purpose. The DCS link to the HMI shall be provided for the collection and management of process data. T he DCS should have the startup, operation, alarm management and normal shutdown logic. The MCR shall have a raised computer floor for ease of access and upgrades with room for the fire suppression system. The Administration Building shall be limited to monitoring capability. 19.2.2 Field Instruments Field instruments may be connected via remote distributed I/O panels located in weatherproof enclosures or via marshalling racks in the Local Control Shelters (LCS). The location of LCS shall be based on Terminal process area. 19.2.3 Instrumentation Power Supply All control and instrumentation systems throughout the Terminal shall be provided with Uninterruptible Power Supplies (UPS) power to support operation after loss of power. Power for the DCS, SIS and HDMS equipment shall be provided by redundant 120 VAC, 60Hz ±5% power supplies (UPS). The power feed from each separate UPS shall be capable of supplying the full load of the system. These power systems for each system shall provide power for a minimum of 4 hours. This document contains information that is proprietary to CH·IV International, which is to be held in confidence. No disclosure or other use of this information is permitted without the express authorization from the LNG Development Company or CH·IV International.



The power system to controllers and I/O for associated process, SIS and HDMS shall be supplied with 24 V DC and have integral automatic and bumpless backup. P ower system alarming shall be provided in the DCS. Control system equipment shall be supplied with appropriate fuse and circuit breaker protection for all AC and DC power distribution, field devices, etc. All field loop power shall be 24 VDC. The SIS and HDMS cabinets shall be powered from two 24 V DC battery backed up sources. The SIS and HDMS shall be designed such that all chassis power supplies are rated for 150% of the maximum calculated load. Each 24 VDC power supply must be rated to supply full loads with power distributed so that one supply can be removed for maintenance without de-energizing any critical equipment.



C.2 Design Basis


Oregon LNG Warrenton, OR Design Basis


DESIGN BASIS by H H C H H

REV NUMBER: ISSUE PURPOSE: DATE: BY: CHECKED: APPROVED:


4

5

6

7

8

9

Revised Client Review

Revised Client Review

Include Dewatering System

Include Liquefaction

Includes APCI Design

Includes Client Comments

12/31/07 AAR RCT AAR

02/16/09 OOA RCT AAR

10/29/09 AAR TOA AAR

10/06/11 VMC MS AAR

12/21/11 VMC MS AAR

04/13/12 VMC MS AAR


Section 1


Page

GENERAL .............................................................................................................. 6 1.1 Reference Documents ..................................................................................................6 1.2 Definitions of Units and Conversion Factors .............................................................7 1.3 Glossary of Terms and Abbreviations .......................................................................7

2

CODES AND STANDARDS ................................................................................. 7

3

PROCESS DESCRIPTION AND DESIGN CASES .......................................... 7 3.1 Process Description ......................................................................................................7 3.2 Normal Terminal Operating Modes ...........................................................................8 3.3 Design Cases: ................................................................................................................9

4

SITE CONDITIONS .............................................................................................. 9 4.1 Barometric Pressure ....................................................................................................9 4.2 Air Temperature ........................................................................................................10 4.3 Wind Speeds ...............................................................................................................10 4.4 Coordinate and Elevation References ......................................................................10 4.5 Seawater Temperature ..............................................................................................11 4.6 Noise Limitations........................................................................................................11

5

NATURAL GAS TRANSMISSION PIPELINE ............................................... 11 5.1 Gas Transmission Line ..............................................................................................11

6

LIQUEFACTION FACILITIES ........................................................................ 12 6.1 Feed Gas Pretreatment ..............................................................................................12 6.2 Feed Gas Specification ...............................................................................................14 6.3 FEED Gas Scrubbing.................................................................................................15



6.4 Liquefaction Facility Rotating Equipment ..............................................................15 6.5 Main Cryogenic Heat Exchanger .............................................................................16 6.6 Cooling Media ............................................................................................................16 6.7 LNG Composition ......................................................................................................17

7

LNG STORAGE TANKS .................................................................................... 18 7.1 Description ..................................................................................................................18 7.2 Operating Limitations ...............................................................................................18 7.3 Other Design Considerations ....................................................................................18

8

LNG VAPORIZATION AND NATURAL GAS SENDOUT FACILITIES .. 19 8.1 Natural Gas Vaporization and Sendout Facilities ..................................................19 8.2 Sendout Requirements: .............................................................................................19

9

BOILOFF GAS HANDLING AND FLARE SYSTEMS ................................. 20 9.1 BOG Handling System...............................................................................................20 9.2 Flare System ...............................................................................................................21

10

LNG PUMPS ........................................................................................................ 21 10.1 Description ..................................................................................................................21 10.2 Design Considerations ...............................................................................................21

11

LNG CARRIERS ................................................................................................. 22 11.1 General Design Requirements ..................................................................................22 11.2 Design Requirements - LNG Export ........................................................................22 11.3 Design Requirements – Ship Loading Vapor Return .............................................22

12

MECHANICAL.................................................................................................... 23 12.1 Cryogenic Insulation ..................................................................................................23



12.2 Cryogenic Piping ........................................................................................................23 12.3 Cryogenic Piping Heat Leak .....................................................................................23 12.4 Vapor Handling Equipment ......................................................................................24 12.5 Pressure Vessels and Containment Equipment.......................................................24 12.6 Seismic Considerations ..............................................................................................24

13

UTILITY / AUXILIARY SYSTEMS ................................................................. 24

14

CIVIL DESIGN .................................................................................................... 25

15

INSTRUMENTATION AND CONTROL SYSTEMS ..................................... 25 15.1 Design Considerations ...............................................................................................25

16

COMMUNICATIONS AND SECURITY SYSTEMS ..................................... 28

17

FIRE, HAZARD AND SAFETY SYSTEMS ..................................................... 28 17.1 Design Considerations ...............................................................................................28

18

DESIGN LIFE ...................................................................................................... 29

19

TERMINAL RELIABILITY AND EQUIPMENT SPARING PHILOSOPHY ................................................................................................................................ 29


Job No. 07902 Doc No. 07902-TS-000-002 Rev 9 Page v of 36

List of Tables Table

Page

Table 4.6 Noise Limitations ........................................................................................................11 Table 6.2-1: Feed Gas Composition and Conditions for liquefaction .......................................15 Table 6.7-1: LNG Composition .................................................................................................17 Table 8.2-1: Natural Gas Sendout Specification Limits ............................................................19 Table 9.1-1: BOG Composition and Properties .........................................................................20 Table 11.2-1: LNG Carrier Information (Export) ......................................................................22


1


GENERAL This document outlines the basic design criteria to be used for the proposed Oregon LNG Terminal (“Terminal”). The Terminal will be located on the East Skipanon Peninsula near the confluence of the Skipanon and the Columbia Rivers in Warrenton, Clatsop County, Oregon. The Oregon LNG Development Company holds a long term sub-lease for the 96 acre parcel of land upon which the Terminal will be sited. The Terminal will include: 

Two identical liquefaction trains, each with a nominal capacity of 4.5 million metric tonnes per annum (MTPA). The feed gas requirement to support the abovementioned production is approximately 1,300 million standard cubic feet per day (MMSCFD) of pretreated natural gas. The liquefaction will be achieved using the APCI C3–MR Liquefaction Process. Sub-cooled LNG produced in these trains will flow into two 160,000 cubic meter (“m3”) aboveground, full containment LNG storage tanks.



Base-load natural gas sendout capacity of approximately 500 MMSCFD.

LNG will be loaded at slightly sub-cooled condition onto oceangoing LNG carriers that will arrive at the Oregon LNG Project via marine transit through the Columbia River. The scope of this document includes the on-shore Terminal up to its battery limit as well as the piping systems and associated equipment on the marine facility. Excluded from the scope of this document is: 

The marine facility structure,



The off-site natural gas piping system, and

1.1

Reference Documents The document is supported by the following project specific documents: 

Plot Plan (Drawing No. 07902-DG-000-001)



Process Flow Diagrams: 

Balance of Plant (Document No. 07902-PF-000-001)



Liquefaction - Feed Gas and Mixed Refrigerant Cooling (Document No. 07902-PF-000-002)



Liquefaction - Scrub Column and MCHE (Document No. 07902-PF-000003)



Liquefaction - Mixed Refrigerant Compressor (Document No. 07902-PF000-004)


Job No. 07902 Doc No. 07902-TS-000-002 Rev 9 Page 7 of 36  

1.2

Liquefaction - Propane Compressor (Document No. 07902-PF-000-005)

Heat & Material Balance Diagrams 

Liquefaction Lean Case (Document No. 07902-PF-000-022)



Liquefaction Rich Case (Document No. 07902-PF-000-011)



Balance of Plant (Document No. 07902-PF-000-012)



Engineering Development Standard (Document No. 07902-TS-000-001)



Design Codes and Standards (Document No. 07902-TS-000-022)

Definitions of Units and Conversion Factors The units used for this project are English units. See Appendix A for a table of units and conversion factors.

1.3

Glossary of Terms and Abbreviations See Appendix B for a Glossary of Terms and Abbreviations used throughout this document.

2

CODES AND STANDARDS The Terminal shall be designed in accordance with 49 CFR Part 193: Liquefied Natural Gas Facilities Federal Safety Standards and NFPA 59A, “Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG),” editions incorporated therein. Document 07902-TS-000-022 includes a listing of other codes and standards to be used in the design, construction and operation of the Terminal. Additional codes and standards may be applicable and substitutions for the listed codes and standards may be used, if approved by LNG Development Company. All applicable local codes and standards that have not been included in the list shall be satisfied in the design.

3

PROCESS DESCRIPTION AND DESIGN CASES 3.1

Process Description The Terminal will receive natural gas from the Williams Northwest Gas Pipeline (NWP) via the proposed Oregon LNG Compressor Station and Pipeline at a pressure of approximately 875 psig. The Pretreatment Facility will remove CO2, sulfur compounds, water and mercury to meet liquefaction feed gas specifications. This will be accomplished with an amine sweetening system, a molecular sieve dehydration system and a mercury removal unit. The Pretreatment Facility will provide natural gas to the Liquefaction Facility at design feed gas conditions of 815 psia and 100 ºF.



Pretreated natural gas will be liquefied in two identical liquefaction trains of 4.5 MTPA, each, for an overall nominal export capacity of 9.0 MTPA. Each liquefaction train will include a heavy hydrocarbons removal unit. The liquefaction technology will be Air Products & Chemicals, Inc. (APCI) Propane-Pre-cooled, Mixed Refrigerant (C3MR), which entails two refrigeration cycles to pre-cool and liquefy the natural gas feed. The natural gas feed is first pre-cooled using propane refrigerant at descending pressure levels and corresponding lower vaporization temperatures. After being cooled by the propane refrigeration, the feed gas will enter the Main Cryogenic Heat Exchanger (MCHE) where sub-cooled LNG is produced by cooling and liquefying of natural gas against the Mixed Refrigerant. Sub-cooled LNG leaving the MCHE is then depressurized and further cooled through LNG Liquid Turbines. LNG at 50 psig flows to the LNG storage tanks. Process cooling will be provided by cooling water, cooled in an evaporative cooling tower. Electric motors will drive the Propane and Mixed Refrigerant compressors. 3.2

Normal Terminal Operating Modes 3.2.1

Liquefaction During these modes of operation, natural gas is being continuously liquefied through the abovementioned process, with or without ship loading operations. During LNG carrier loading operations, a single LNG Carrier will moor at the loading berth and following cooldown of the loading arms, sub-cooled LNG will be transferred to the Carrier via the in-tank LNG sendout pumps at 10,000 m3/hr. Vapor generated during LNG carrier loading will be returned to the Terminal’s vapor handling system via the vapor arm connected to the LNG Carrier and a vapor return pipeline. When there are no LNG carrier loading operations occurring, a portion of the LNG from liquefiers will circulate LNG through a small diameter circulation line to the marine facility and back through the LNG transfer pipeline to the LNG storage tank(s) in order to keep these piping systems cold. All boiloff gas (BOG), including the BOG generated due to the heat leak into the LNG storage tanks, pumping systems and piping systems and vapor displaced by the incoming LNG to tanks and LNG ship, will be recycled to the liquefaction feed gas system upstream of the MCHE.


3.2.2


Regasification In this operating mode no natural gas liquefaction is taking place. the intank, column mounted LNG pumps will send LNG to the vaporization system that will consist of shell and tube heat exchangers using an intermittent ethylene glycol water solution heated in natural gas fired heaters. During no LNG carrier unloading operations, the in-tank column mounted LNG pumps will also circulate LNG through a small diameter circulation line to the marine facility and back through the LNG transfer pipeline to the LNG storage tank(s) in order to keep these piping systems cold. Boiloff gas (BOG) that is continuously generated in the tanks due to heat leak into the system piping, heat leak through the insulated tank walls, and heat added due to LNG circulation in the dock will be compressed by the Pipeline BOG Compressors and routed to pipeline for sendout. Liquefaction trains will not be kept cold during extended periods of sendout operations.

3.3

4

Design Cases: Case 1 -

Baseload liquefaction, no LNG Carrier loading

Case 2 -

Baseload liquefaction, LNG Carrier loading

Case 3 -

No liquefaction, LNG Carrier Loading

Case 4 -

Baseload natural gas sendout (no liquefaction), no carrier loading

Case 5 -

No liquefaction, no LNG sendout (idle Terminal)

SITE CONDITIONS 4.1

Barometric Pressure Average Barometric Pressure ........................................................................ 1017 mbar Maximum Barometric Pressure .................................................................... 1040 mbar Minimum Barometric Pressure ....................................................................... 980 mbar Maximum Rate of Change per Hour of Barometric Pressure .............................. 1 mbar


4.2


Air Temperature Maximum Design Temperature ............................................................................. 96 °F Minimum Design Temperature ................................................................................ 6 °F Design Ambient Temperature for Evaporative Cooling Tower Design ................ 68 °F Basis for heat leak calculations ................................................................................ 95°F

4.3

Wind Speeds Basis for heat leak calculations ........................................................................... 10 mph LNG Storage Tank Wind Velocity Design Basis1 ............................................ 150 mph Process Equipment Wind Velocity Design Basis2 ................... 100 mph (3 second gust) Buildings Wind Velocity Design Basis2 ................................. 100 mph (3 second gust) Notes:

4.4

1.

Per 49 CFR 193.2067

2.

The site is located in a “Special Wind Region” as defined in ASCE 7-05. The design wind speed value of 100 mph is based upon information presented in “SEAW Commentary on Wind Code Provisions,” Volume 1, Section 4.3

Coordinate and Elevation References The Oregon State Plane, North zone, NAD83, International Feet, grid coordinates will be used in the design. More specifically, Horizontal Coordinates: State Plane - Oregon North, NAD83 (CORS96)(EPOCH:2002.0000), International Feet based on OPUS solutions to certain points, and Static ties to the others. Elevations are North American Vertical Datum of 1988 (NAVD88) computed with Geoid 03 and OPUS positions and heights. Tidal datum for the site relates to NAVD88 datum (in feet) as follows 

El. 0 (NAVD88) = El. 0



El. 0 (MLLW) = El. -0.44



El. 0 (MLW) = El. 0.81



El. 0 (MTL) = El. 4.24



El. 0 (MSL) = El. 4.24



El. 0 (MHW) = El. 7.66


Job No. 07902 Doc No. 07902-TS-000-002 Rev 9 Page 11 of 36 

El. 0 (MHHW) = El. 8.36

Please note that this tidal information is not specific to the site but is taken from National Oceanic Atmospheric Administration (NOAA) tidal station No. 9439026 located at Astoria, Young’s Bay. . 4.5

Seawater Temperature Annual Maximum ................................................................................................... 68 °F Annual Minimum .................................................................................................... 42 °F Annual Average ...................................................................................................... 55 °F

4.6

Noise Limitations The following table provides a summary of Anticipated Regulatory Noise Limits for the Terminal. Table 4.6 Noise Limitations NSA

Applicable Noise Limit

Controlling Regulation

M1

Ldn of 53 dBA

L50 of 47 dBA

Oregon

M2

Ldn of 55 dBA

[49 dBA continuous]

FERC

M3

Ldn of 55 dBA

[49 dBA continuous]

FERC

Note: For a steady noise source, the continuous level is the same as the Leq or L50. The Ldn is approximately 6 dBA greater than the continuous level.

5

NATURAL GAS TRANSMISSION PIPELINE 5.1

Gas Transmission Line Pipeline Length: ............................................................................................. 85.5 Miles Diameter of Pipeline: ........................................................................................... 36 inch Maximum Allowable Working Pressure (in accordance with pipeline design):1,440 psig Maximum Operating Pressure at Pipeline Interconnect ................................... 960 psig


6


LIQUEFACTION FACILITIES 6.1

Feed Gas Pretreatment A Pretreatment Facility will be installed at the Terminal to provide feed gas conditioning required by the gas liquefaction process. The Terminal will receive gas from the Williams Northwest Gas Pipeline (NWP) via the proposed Oregon LNG Compressor Station and Pipeline. The Pretreatment Facility will remove CO2, sulfur compounds, water and mercury to meet liquefaction feed gas specifications. This will be accomplished with an amine sweetening system, a molecular sieve dehydration system and a mercury removal unit sized to match the Terminal liquefaction design capacity of 1,300 million standard cubic feet per day (MMSCFD). 6.1.1 Primary Gas Path Gas from the proposed 86.5 mile Oregon LNG pipeline will arrive at a pig receiver and meter station located at the Terminal site. Pretreatment design inlet conditions are 875 psig and 50° F at 1,300 MMSCFD. Condensation is not expected in the pipeline at design conditions, but liquids may be received due to upstream upset conditions or pipeline pigging operations. Therefore the inlet gas will first flow through a horizontal Inlet Separator vessel for removal of any free liquids. Inlet Separator liquids will be sent through level control to a closed drain system. Inlet Separator gas will join mole sieve bed regeneration gas (“regen gas”) before splitting on flow control into two, parallel, 50% capacity, amine gas sweetening trains (“Amine Trains”). The nominal gas capacity of each Amine Train will be 750 MMSCFD based on 50% of the 1,300 MMSCFD Pretreatment design capacity plus 10% for estimated regen gas recycle. The Amine Trains will be conventional amine adsorbent gas sweetening systems with dedicated amine regeneration systems. Gas entering each Amine Train will be warmed in the Feed/Overhead Gas Exchanger and will enter the bottom of the Amine Contactor, a trayed tower where CO2 and sulfur components in the gas will be removed in a cascading liquid adsorbent (“amine” – a conventional or proprietary aqueous solution: diethanolamine DEA selected for preliminary design). Lean Amine liquid from the Amine Regeneration System will enter the top of the Amine Contactor and Rich Amine liquid will be returned to the Amine Regeneration System from the bottom of the Amine Contactor on level control. The ‘sweetened’ gas will flow from the top of the Amine Contactor through the Feed/Overhead Gas Exchanger and then through the Contactor Overhead Cooler, an exchanger that cools the gas with Cooling Water supplied by the Terminal cooling water system. The cooled, sweetened gas



will then enter the Contactor Overhead Scrubber, where condensed water and entrained Amine will be recovered and returned on level control to the Amine Flash Drum. The Contactor Overhead Cooler outlet temperature will set the water load for the Dehydrators. The gas from the Contactor Overhead Scrubber will exit each Amine Train, recombine, flow through a particulate/entrained-liquid filter and then split to downflow through the multiple, parallel Dehydrators. The Dehydrators will be vessels containing beds of regenerable desiccant media, which will remove almost all water from the process gas stream. The Dehydrator media will be routinely regenerated by reverse flow of hot dry gas through the beds and will be accomplished automatically with sequencing valves. The sweetened, dry gas from the Dehydrators will recombine in a header, flow through another particulate filter and then split to flow through multiple, parallel Mercury Removal Beds. Gas from the Mercury Removal Beds will recombine and flow through a final particulate filter and pressure control valve to the Liquefaction Facility. 6.1.2

Amine Regeneration Rich amine liquid from the Amine Contactor will flow on level control to the Amine Flash Drum where evolved gas will be separated from the liquid and recovered in the fuel gas system. Rich amine liquid will then flow though particulate and contaminant filters, heated in a cross exchanger by the lean amine from the Stripper bottoms and then flow through the Amine Flash Drum level control valve to the upper section of the trayed, reboiled, refluxed Stripper tower. The Stripper will remove adsorbed carbon dioxide and sulfur compounds from the amine solution, which will exit in the overhead vapor (Stripper Reflux Drum vapor). The heat required for the Stripper Reboiler in each amine train will be supplied by a dedicated, circulating heat medium system consisting of a fired heater, expansion tank, filter and circulation pumps. The Stripper Reboiler will be a thermosiphon type reboiler. The heat medium will be hot oil. Cooling for the Stripper Reflux Condenser will be supplied by the Terminal cooling water system. The wet CO2 vapor from the Stripper Reflux Drums from both trains will be further cooled, sent through a scrubber to remove condensed water and then vented to atmosphere through a thermal oxidizer. Lean, hot amine solution from the Stripper bottoms will flow through the Lean/Rich amine cross exchanger on level control to an expansion drum.



Amine Booster pumps will move the lean amine from the Stripper bottoms/Expansion Drum and Lean/Rich Exchanger through a particulate filter and Lean Amine Cooler (cooling medium: Terminal cooling water). The Lean Amine Pumps will return the lean amine to the top of the Amine Contactor through a flow control valve. The Pretreatment Facility will include bulk storage of amine and a system for generating and storing demineralized water and transfer pumps to make-up for amine solution losses in the amine regeneration system. The circulating amine fluid will also require corrosion inhibitor, anti-foam or other chemical injection. 6.1.3

Mole Sieve Regeneration The molecular sieve beds will be sized for a theoretical five year media life. The total gas throughput will require an estimated eight, 12 foot ID Dehydrator vessels to be operating in parallel continuously while two additional Dehydrator vessels are regenerating. Regeneration will be accomplished automatically by sequentially isolating the bed and flowing first hot, then cool regen gas through the molecular sieve material. The regen gas will be supplied by a slipstream of the dry gas from the Dehydrator outlets. The regen gas will be heated in an exchanger with hot oil in a dedicated system (expansion drum, circulation pumps and fired heater). Regen gas flow will be controlled at approximately 10% of the total process design rate and its temperature (during hot cycle) will be controlled at approximately 600° F. Regen gas from the Dehydrators will be boosted approximately 75 psi in the Regen Gas Compressors to flow to the Regen Gas Cooler (cooling medium: cooling water), the Regen Gas Scrubber and return to the amine train inlets. Water condensed from the regen gas in the Regen Gas Cooler and separated in the Regen Gas Scrubber will be removed on level control to a closed drain system.

6.1.4

Mercury Removal Beds The Mercury Removal Beds contain a carbon or other proprietary nonregenerable media with a theoretical design life of 5 years. The design will provide capability for the beds to be manually isolated and dried with regen gas.

6.2

Feed Gas Specification The liquefaction units feed gas composition is shown in Table 6.2-1below.


Job No. 07902 Doc No. 07902-TS-000-002 Rev 9 Page 15 of 36 Table 6.2-1: Feed Gas Composition and Conditions for liquefaction

Composition (mol%)

Lean Gas

Heavy Gas

Estimated Recycle BOG, Lean Gas

Estimated Recycle BOG, Rich Gas

Carbon Dioxide

0.0050

0.0050

0.00

0.00

Nitrogen

0.6596

0.4017

13.00

8.00

Methane

96.8519

94.6765

87.00

92.00

Ethane

1.7893

3.5645

0.00

0.00

Propane

0.4519

0.9863

0.00

0.00

i-Butane

0.0681

0.1401

0.00

0.00

n-Butane

0.0927

0.0345

0.00

0.00

i-Pentane

0.0249

0.0419

0.00

0.00

n-Pentane

0.0191

0.0345

0.00

0.00

Hexane

0.0016

0.0480

0.00

0.00

Heptane

0.0008

0.0240

0.00

0.00

Octane

0.0003

0.0080

0.00

0.00

Methyl Mercaptan

0.0005

0.0005

0.00

0.00

Ethyl Mercaptan

0.0010

0.0010

0.00

0.00

Propyl Mercaptan

0.0002

0.0002

0.00

0.00

0.00

0.00

100.00

100.00

A

0.0331

BTX

100.00

Total Inlet Pressure (psia)

815

Inlet Temperature (°F)

100

B

A

0.0333

100.00 815 B

100

815 B

100

815 100

B

A: BTX composition is for all Benzene, Toluene and Xylene components B: Estimated inlet temperatures

The pretreated feed gas will be delivered to the pre-cooling and liquefaction facilities via the natural gas pipeline at 815 psia and 100°F. 6.3

FEED Gas Scrubbing A Scrubber Column upstream of the MCHE will be used to remove heavy components, Mercaptans and BTX from the Feed Gas before liquefaction.

6.4

Liquefaction Facility Rotating Equipment 6.4.1

Mixed Refrigerant and Propane Compressors / Drivers The propane and mixed refrigerant compressors will be driven by variable speed electric motors. The load between the MR refrigerant compressors strings shall be approximately equally split.



The maximum available rated power from each electric motor will be 75 MW. The refrigeration compressors shall be centrifugal type. The following compressor configuration is preferred:

6.4.2



The Propane Compressor will be driven by a single variable speed electric motor.



The LP MR compressor will be driven by a single variable speed electric motor.



The MP and HP compressors will be driven by a single variable speed electric common motor.

Liquid Turbines Liquid turbines will be used on the LNG letdown downstream of the MCHE outlet and heavy MR liquid letdown in the middle of the MCHE’s shell. Backpressure of the liquid turbines’ outlet for the LNG downstream of the MCHE will be 50 psig to allow sufficient head for the LNG to enter the LNG storage tanks. Subcooled LNG shall be below the bubble point temperature at the tanks’ pressure at the inlet of the LNG storage tanks. Backpressure of the liquid turbines’ outlet for the heavy MR liquid letdown will be at the minimum two bars above the bubble point to ensure no vapor is formed in the liquid turbines. The remaining pressure drop will be taken across a control valve.

6.4.3

Pipeline Boil Off Compressors Pipeline Boil Off Compressors will be designed to re-compress the BOG up to the feed gas pressure upstream of the MCHE. The compressors will be driven by variable speed electric motors and will be “oil free”.

6.5

Main Cryogenic Heat Exchanger Each liquefaction unit will utilize a single MCHE.

6.6

Cooling Media A maximum approximately 10 million gallons a days of water make-up will be required to provide the total cooling for the pretreatment and liquefaction facilities.



Cooling Water Specifications: Cooling Process: ..................................................... Evaporative Cooling Water Tower Design Temperature .............................................................................................. 68°F Return Temperature ................................................................................................ 83°F Design Wet-Bulb/Dry-Bulb Ambient Temperature .................................... 62°F/68 °F Assumed CWT Concentration Ratio ..................................................Up to 20.0 cycles Approximate Recirculation Rate ............................................................. 304,000 gpm 6.7 LNG Composition The LNG composition from the liquefaction units is shown in Table 6.7-1 Table 6.7-1: LNG Composition LNG Composition Component

Lean

Rich

0.97

0.632

CO2

0.0050

0.0050

Methane

96.68

94.81

Ethane

1.75

3.47

Propane

0.44

0.92

I-Butane

0.063

0.12

N-Butane

0.082

0.026

Pentane+

0.003

0.0048

100.000

100.00

Molecular Weight

16.59

16.94

Gross Heating Value, Btu/scf

1023

1047

Wobbe Index, Btu/scf

1352

1389

Nitrogen

TOTAL GAS PROPERTIES


7


LNG STORAGE TANKS 7.1

Description LNG will be stored in two identical 160,000 m³ (net) LNG storage tanks. The Terminal shall have a total LNG storage capacity of 320,000m3 (net). The LNG storage tanks shall be flat-bottomed, vertical, cylindrical, full containment type design. The inner tank will be constructed of a suitable cryogenic alloy such as 9% nickel steel, as the primary liquid containment. The outer tank walls and roof shall consist of reinforced concrete and will be designed to contain the vapor as well as provide secondary containment of the LNG in the unlikely event of an inner tank failure. Outer tank walls will also include post-tensioned cables as required by the design. The LNG storage tank and foundation design shall be based on the results of the site specific geotechnical investigation and site specific seismic hazard evaluation.

7.2

Operating Limitations The maximum allowable working pressure of the tank will be 4.3 psig with the following operating set points: LNG Tank Relief Valve Set Point .................................................................... 4.3 psig Discretionary Vent PIC Set Point .................................................................... 4.0 psig Normal Operating Pressure Range ........................................................ 0.5 to 3.7 psig Operating Pressure to Size BOG Compressor ................................................... 3.5 psig The tank minimum design LNG density .................................................... 29.3 lb/ft3. The minimum design LNG temperature ......................................................... -270°F. The LNG tank floor and exposed wall shall be designed to accommodate temperatures of -320°F in case liquid nitrogen is to be used during the initial cool down procedure.

7.3

Other Design Considerations The maximum allowable design vacuum on the tank will be determined by the tank designer but shall not be less than 2.0" w.c. A tank pressure maintenance system will be provided to prevent vacuum conditions from occurring during normal operation. A vacuum relief system will be installed on the tank and will be sized for the worst case conditions.



The heat leak into the LNG storage tank will give a maximum boil-off of 0.05% per day at 68°F ambient temperature, based on pure methane and a full tank. Instrumentation will be provided for continuous level, temperature and density measurements throughout the level of the tank inventory to monitor for stratification of the tank contents. Features shall be provided in the design to rapidly circulate the stored LNG to thoroughly mix the contents, should stratification start to develop.

8

LNG VAPORIZATION AND NATURAL GAS SENDOUT FACILITIES 8.1

Natural Gas Vaporization and Sendout Facilities Baseload Natural Gas Sendout Rate ............................................................. 500 mmsfd Vaporization Type ....... Intermediate Glycol / Water Shell and Tube Heat Exchangers Vaporization Heat Source .......................................................................... Fired Heaters Battery Limit Natural Gas Maximum Discharge Pressure .............................. 1440 psig Battery Limit Natural Gas Sendout Temperature ................................................... 40 °F

8.2

Sendout Requirements: All sendout rates indicated are net, i.e., exclusive of internal shrinkage and consumption within the Terminal. The Terminal design sendout rate is 500 MMSCFD. Natural gas from the Terminal will connect to the Williams Northwest Pipeline System and will comply with the requirements of the Williams Northwest Pipeline System tariff (Third Revised Volume No. 1 is in effect at present). The key provisions of the tariff are summarized in Table 8.2-1. Table 8.2-1: Natural Gas Sendout Specification Limits Characteristic and Compounds Gross Heating Value

Units

Limit

Btu/scf

985 Minimum

Total Inert Gas Composition Temperature

3 mol% Maximum °F

120°F Maximum


9


BOILOFF GAS HANDLING AND FLARE SYSTEMS 9.1

BOG Handling System The Vapor Handling System includes the BOG Header, LNG Tank Vapor Space, LNG Carrier Vapor Return Line, onshore BOG Compressors, and overpressure relief line to flare. BOG is generated and shall be considered from the following sources: 

Heat leak into the LNG storage tank through the insulation systems.



Displaced and LNG Carrier generated vapor returned during the LNG loading process.



Displaced vapor due to the LNG volumes entering into the storage tanks from the liquefiers.



Heat generated by LNG in-tank (loading) pumps



Heat leak into LNG piping, including transfer pipeline recirculation.

The liquefaction facility will produce sub-cooled LNG; therefore, there will be no LNG flash gas from LNG entering the storage tank from the liquefaction system. The composition of the boiloff gas (BOG) is predominantly a function of the mole percent of nitrogen in the LNG stream as it enters the LNG Storage Tank or as it is loaded onto an LNG carrier. The BOG composition is based on the vapor source and is provided in Table 9.1-1. Table 9.1-1: BOG Composition and Properties BOG Composition Component

Lean

Rich

Nitrogen

20.2

14.2

Methane

79.8

85.8

Ethane

0.0

0.0

Propane+

0.0

0.0

100.000%

100.000%

Molecular Weight

18.5

16.94

Gross Heating Value, Btu/scf

806

866

Wobbe Index, Btu/scf

1010

1107

TOTAL GAS PROPERTIES


9.2


Flare System The Terminal will be designed to minimize fugitive emissions with no flaring during all normal operations using a Closed Vent/Drain System. All LNG and natural gas relief valves (excluding LNG storage tank, fuel gas drum and the LNG Vaporizer process relief valves) will be vented into a closed vent flare system that is common with the LNG storage tank vapor spaces. All release in the Liquefaction trains during an operation upset or train start-up will be sent to a closed dry gas flare system. The following will be the basis of the Liquefaction flare design: 

Initial dry out and cool down of a single trains



Maximum emergency release during operation of the LNG trains.

10 LNG PUMPS 10.1

Description There are two LNG pumping systems: In-Tank LP (Low Pressure) Pumps and HP (High Pressure) Pumps. The LP Pumps used for LNG sendout to regasification or LNG carrier loading will be column mounted submerged motor type located inside and near the bottom of the LNG storage tanks. The HP Pumps used for regasification will be multi-stage centrifugal submerged motor type and will be mounted in individual sealed and insulated suction vessels.

10.2

Design Considerations All pumps will be provided with individual minimum flow recycle line and flow control to protect the pump from insufficient cooling and to maintain bearing lubrication at low flow rates. All pumps will have remotely monitored pressure, flow, vibration and motor amperage signals. All pumps will be designed to be isolated and safely maintained without requiring other pumps to be removed from service. The LP Pumps will be removable for maintenance while maintaining an operating level in the LNG storage tank. Each HP Pump will be supplied from a common suction manifold and discharge into a common manifold supplying the LNG vaporizers. Valves will be provided to safely isolate each pump from the system.



11 LNG CARRIERS 11.1

General Design Requirements The Terminal is expected to receive LNG Carriers that range in size from 70,000 m3 to 266,000 m3. The Terminal will have a single berth. The Terminal will be capable of loading LNG carriers at a design rate of 10,000 m3/hr via 3 ×16" LNG loading arms. A single 16" vapor arm will be used to return the BOG, including the displaced vapor, from the LNG carrier storage tanks to the Terminal BOG handling system.

11.2

Design Requirements - LNG Export

Table 11.2-1 provides design criteria to be used for the LNG loading system. Table 11.2-1: LNG Carrier Information (Export)

Largest ship size Smallest ship size BOG vapor return conditions at ship flange during loading Loading time (based on 10,000 m3 per hr average loading rate) LNG loading pressures at ship flange Pressure (minimum): Design loading rate, m3/hr LNG Carrier’s Tank Vapor Pressure

266,000 m3 70,000 m3 6.5 psig [0.45 barg] using ship compressors Up to 22 hours excluding connect/disconnect time. 30 psig [2.1 barg] 10,000 (Nominal Rated) 1.25 psig

LNG will be loaded to LNG Carrier sub-cooled to prevent flashing assuming Carrier arrives at the Terminal at the conditions stated above. Minimum available BOG pressure at the carrier’s vapor manifold flange is below 20 psig. 11.3

Design Requirements – Ship Loading Vapor Return LNG Carrier loading return vapor will include displacement volume of loaded LNG, BOG generated due to the heat leak through the LNG carrier tanks and potentially the heat added through the piping heat leak and pumping horsepower. Ship vapor return calculations use the following assumptions: 

Design loading rate of 10,000 m3/hr



LNGC nominal size of 145,000 m3



LNGC tank vapor pressure of 1.25 psig [86 mbar]



LNGC design heat leak rate of 0.25%/day



Onshore LNG Storage Tank nominal pressure of 0.5 psig

Vapor return from the ship will be handled through a single 16" loading arm and a vapor return line. The vapor line connects to the BOG header that distributes BOG to the LNG tank vapor space, BOG compressors and the flare system through an automatic overpressure control. For a ship arriving with “warm” cargo tanks, vapor return may be limited during cooldown of the ship tanks and could extend the dock time for loading to accommodate vapor return (BOG) system limits to avoid flaring. Services to be provided by the LNG Carrier Liquid Nitrogen ........................................................................................................ .No Diesel / Fuel Oil ....................................................................................................... .No Potable Water ........................................................................................................... No Electric Power .......................................................................................................... No

12 MECHANICAL 12.1

Cryogenic Insulation Cryogenic insulation systems will consist of multiple layers of insulation polyurethane foam (PUF), polyisocyanurate foam (PIR) or cellular glass foam (Foamglas™) with vapor barrier membrane installed between each layer and a sealed weatherproof metallic (stainless steel or owner approved alternative) outer jacketing. Adequate insulation expansion joints will be included.

12.2

Cryogenic Piping Any equipment or piping to be used in cryogenic service will be internally clean, free of surface contaminants and completely free of any residual water, condensable water or oil prior to initial cooldown.

12.3

Cryogenic Piping Heat Leak Cryogenic Piping Heat Leak



LNG Piping, Insulated ……………………………….1.25 Btu/ft2/hr (based on surface of internal line) Other Cryogenic Externally Insulated Equipment………9 Btu/ft2/hr (Maximum based on external surface) 12.4

Vapor Handling Equipment Compressors for BOG service shall not use any oil that could contact the process gas through any possible flow path.

12.5

Pressure Vessels and Containment Equipment All pressure vessels, heat exchangers and fired heaters will be designed, built and code stamped to the appropriate ASME, API or TEMA Standard as listed in Document 07902-TS-000-022. Additionally, all pressure vessels will be registered with the U.S. National Board.

12.6

Seismic Considerations Based on the seismicity of the site, all-piping, utility and electrical lines that cross the seismic isolation interface of the LNG Storage Tanks will be designed to accommodate the maximum isolation displacements as indicated in the Seismic and Structural Design Criteria for Equipment and Structures, Oregon LNG Terminal.

13 UTILITY / AUXILIARY SYSTEMS The Terminal will be designed with the following utility and auxiliary systems, as required, to support the operation of the Terminal in each of the defined operating cases: 

Electrical Power Distribution including: Power Substations, Transformers, Switchgear, Multiple Voltage Distribution as well as Emergency Generation and UPS Systems.



Refrigerant component storage and transfer



Refrigerant cooling systems using cooling water and evaporative cooling towers



Heavy hydrocarbon disposal



Nitrogen



Fire Water



Potable Water



Service Water



Mechanical Handling Systems including Fixed Cranes and Lifting Devices



Sanitary Sewer and Waste Water Treatment




Storm Sewer and Disposal



Waste/Oily Water Collection and Treatment System



Utility Air and Instrument Air



Diesel Fuel Oil Storage and Distribution


14 CIVIL DESIGN The civil design of the Terminal will cover, at minimum, the following areas: 

Soil Improvement



Foundations



Paving



Curbing (both roadway and LNG spill diversion, where appropriate)



LNG Containment and Impoundment Design and Insulation Needs



Pipe Supports



Buildings



Culvert / Bridge / Piping / Road Requirements



Shoreline Stabilization



Equipment Grouting

15 INSTRUMENTATION AND CONTROL SYSTEMS 15.1

Design Considerations A Terminal Control and Monitoring System (PCMS) will be designed that will consist of field instrumentation and a number of microprocessor based sub-systems that will be located in strategically placed control centers throughout the Terminal. Primary operator interfaces will be provided at the Main Control Room (MCR) and at the Platform Control Room (PCR). Sub-systems that make up the PCMS will include the Distributed Control System (DCS), Safety Instrumented System (SIS), Hazard Detection and Mitigation System (HDMS), Analyzer System, Gas Metering System, LNG Tank Gauging System, Vibration Monitoring System, and the Marine Instrumentation System The DCS will include a Supervisory Station that will be located in the Main Control Room (MCR) and will access (Read Only) process monitoring and alarm data. The Supervisory Station will be used to generate various operational and management



reports. The DCS will communicate with each instrument sub-system via Modbus RTU protocol, utilizing Ethernet or serial connections, or hard-wired connections. The Terminal will be controlled primarily from the MCR, which will be the primary operator interface and monitoring center for the Terminal. The MCR will be equipped with pushbuttons that activate the Emergency Shutdown (ESD) system. Operations personnel in the MCR will monitor critical alarms and process variables and will be able to manually shutdown the unloading operation. The Platform Control Room will be the control center for loading operations and will be located on the loading platform and manned during LNG loading operations. The PCR will be equipped with pushbuttons that activate the ESD system. Local Control Station (LCS) shelters will be located near packaged equipment, will contain instrument cabinets, and packaged equipment cabinets. Field instruments will be connected via remote distributed I/O panels located in weatherproof enclosures or via marshalling racks in equipment rooms. A completely independent, stand-alone, high integrity Safety Instrumented System (SIS) will be designed to implement process safety related interlocks. A stand-alone independent Hazard Detection and Mitigation System (HDMS) will be designed to continuously monitor and alert the Technician of hazardous conditions throughout the Terminal due to fire or LNG/NG leaks. Monitoring capability will be provided via video display units and/or mimic panel displays located in the MCR and the PCR. In response to the Fire and Gas leak alerts, operating personnel will have the ability to manually initiating appropriate fire fighting and/or shutdown actions via hardwired switches provided on the MCR and the PCR control consoles. Fire alarms and overview graphic displays depicting the location of detectors will be repeated on the DCS. An LNG Storage Tank Gauging System will be designed that will consist of a microprocessor based networked inventory management system that will consolidate all level, temperature and density measurement associated with the LNG storage tanks. The system will be interfaced with the DCS via non-redundant Ethernet or serial link. A Vibration Monitoring System will be designed to monitor shaft vibration, axial displacement, and bearing temperatures of major rotating machines. A dedicated machine monitoring workstation will be provided in the MCR. Common alarms will be provided on the DCS. Trip signals will be hard-wired to the machine safeguarding system and alarmed on the DCS. A Marine Monitoring System will be designed to aid LNG carrier berthing and navigation including the following control systems monitored at the PCR:



Mooring Load Monitoring System,



LNG carrier Berthing Monitoring System; and



Weather Monitoring System



16 COMMUNICATIONS AND SECURITY SYSTEMS The Terminal shall have communications and security systems including: 

Telephone System – Internal and Outside Access



Radio Communications (walkie-talkie system for internal Terminal use)



Marine Ship-to-Shore Radio Communications as Required to Communicate with Approaching/Departing LNG Carriers



Cable Connections for Data Transfer and Communications with Carriers at the Dock



Intercom/Paging System



Local Alarm and Hazard Warning Signals



Security Fencing/Gates



Security and Safety CCTV Monitoring with Digital Video Feed and recording capabilities.

17 FIRE, HAZARD AND SAFETY SYSTEMS 17.1

Design Considerations 17.1.1 Hazard Detection A comprehensive hazard monitoring system shall be provided. Elements of these systems may include: 

Flammable gas detectors



High and low temperature detectors



Smoke detectors



UV/IR flame detectors



Manual local emergency shutdown (ESD) activation push buttons

All hazard signals will alarm both in the control room and locally. Local signals will be both audible and visual (strobe lights) and have distinctive alarms and colors for fire and flammable gas (leak) hazards. Where appropriate a hazard trip may initiate automatic shutdown of equipment and systems and may activate the ESD system. The Terminal will have a hazard monitoring philosophy that will define the proper equipment and how it will integrate with the DCS.



17.1.2 Hazard Mitigation Fire water and, where appropriate, deluge systems shall be provided to protect personnel, equipment and facilities. Hazards from potential LNG spills and ignition shall be mitigated by a combination of fire and vapor suppression systems, which may include: 

Dry chemical systems



Dedicated fire water system



Dedicated water deluge and sprinkler applications



High expansion foam systems

18 DESIGN LIFE The minimum design life for all facilities, excluding marine, shall be 25 years. After 25 years operation, the Terminal may be subject to a program of refurbishment to extend the life. Equipment and components normally subject to wear and deterioration need not have a life of 25 years. These pieces of equipment shall, however, be designed to have maximum practical life and shall be designed so as not to prevent Terminal operation at full load

19 TERMINAL RELIABILITY AND EQUIPMENT SPARING PHILOSOPHY The Terminal will be designed to operate with an availability of 95 percent and will assume a minimum (n+1) sparing philosophy for all major equipment.



Appendix A: Units Conversion (SI to English) Quantity (Base Units)

From SI

To English

Multiply By

Ampere (A)

Ampere (A)

1.0

meter (m)

feet (ft)

3.2808

kilograms (kg)

pound mass (lbm)

2.2046

degrees Celsius (°C)

degrees Fahrenheit (°F)

(°C x 1.8) +32

degrees Kelvin (°K) =°C plus 273.15

degrees Rankine (°R) = °F plus 459.67

°K x 1.8

Time

second (s)

second (s)

1.0

Amount of Substance

mole (mol)

mole (mol)

1.0

Area

square meter (m2)

square feet (ft2)

10.764

Density

kilograms per cubic meter (kg/m3)

pounds per cubic foot (lb/ft3)

0.062428

Dynamic Viscosity

centipoises (µ)

pounds mass per footsecond (lbm/ft-s)

0.00067222

Electric Resistance

Ohm (Ω)

Ohm (Ω)

1.0

Electromotive Force

Volt (V)

Volt (V)

1.0

Energy, Work, Quantity of Heat

Joule (J)

British thermal unit (Btu)

0.0009478

Enthalpy

Joule (J)

British thermal unit (Btu)

0.0009478

Entropy

Joule per degree Celsius (J/°C)

British thermal unit per degree Fahrenheit (Btu/°F)

0.000526

mole percent (Mole%)

mole percent (Mole%)

1.0

Force

Newton (N)

pound force (lb)

0.2248

Frequency

Hertz (Hz)

Hertz (Hz)

1.0

Fluid Flow Rate (Volumetric)

cubic meters per hour (m3/h) or kiloliters per hour (kl/h)

U. S. gallons per minute (gpm)

4.4028

Gas Flow Rate (Volumetric)

normal cubic meters per hour (Nm3/hr)

standard cubic feet per day (scfd)

895.92

meters per second squared (m/s2)

feet per second squared (ft/s2)

3.2808

meters per second (m/s)

feet per second (ft/s)

3.2808

Electric Current Length Mass Temperature

Feed Composition

Linear Acceleration Linear Velocity



Appendix A: Units Conversion (SI to English) Quantity (Base Units)

From SI

To English

Multiply By

metric tons

standard cubic feet (scf) (approx.)

46,865

Mass Flow Rate

kilograms per hour (kg/h)

pounds mass per hour (lbm/h)

2.2046

Moment of Force

Newton meter (N-m)

foot-pound (ft-lb)

0.73756

Watts (W)

British thermal unit per hour (Btu/h)

3.4134

Watts (W)

horsepower (hp)

0.0013405

Pascals (Pa) or Newtons per square meter (N/m2)

pounds per square inch – gage or absolute (psi)

0.0001450

bar

pounds per square inch

14.5038

Coulomb

Coulomb

1.0

revolutions per minute (rpm)

revolutions per minute (rpm)

1.0

Specific Enthalpy

Joule per kilogram (J/kg)

British thermal unit per pound mass (Btu/lbm)

0.00042992

Specific Entropy

Joule per kilogram degree Kelvin (J/kg-°K)

British thermal unit per pound mass degree Rankine (Btu/lbm-°R)

0.00023885

Newtons per square meter (N/m2)

pounds per square inch (psi)

0.00014504

Watt per meter degree Celsius (W/m2-°C)

British thermal unit inch per hour foot squared degree Fahrenheit (Btuin/hr-ft2-°F)

6.9335

Minute (min)

minute (min)

1.0

hour (h)

1.0

LNG Trade

Power

Pressure

Quantity of Electricity Rotational Velocity

Stress Thermal Conductivity

Time

hour (h) Volume Volume (Liquid) Weight

3

cubic meters (m )

3

cubic feet (ft )

35.314

liters

U. S. gallons

0.2642

Metric tons

pounds (lbs)

2204.62



Appendix B: Glossary of Terms and Conditions 100 Year Event ......................Something that based on historical data would not occur more than once in 100 years. ACI.........................................American Concrete Institute API .........................................American Petroleum Institute ASCE .....................................American Society of Civil Engineers ASME ....................................American Society of Mechanical Engineers ASTM ....................................American Society for Testing and Materials Bathymetric ............................Relating to the measurement of depths of water in oceans, seas, and lakes. Battery Limit ..........................The exterior limit of the terminal equipment or land, beyond which the terminal has no immediate responsibility. BBL (bbl) ...............................barrel, 42 U.S. gallons Berth .......................................The location where a carrier lies when it is at anchor. Boiloff ....................................The cold -160°C [-260°F] gas that has evaporated from LNG. It is, in all practicality, pure methane. Cathodic Protection ................A means of protecting metals against corrosion by supplying a small electric charge (negative) to the surface, preventing the accumulation of corrosive ions. Centrifugal Pump ...................A pump in which the fluid flows axially through an inlet into an impeller and is accelerated by a rotating element, increasing the velocity and as a result, the pressure. CGA .......................................Compressed Gas Association Cryogenic ...............................Temperatures colder than -75°C [-100°F]. DB ..........................................Design Basis DCS ........................................Distributed Control System Deluge ....................................A system used to cover or spray essential equipment with water in the event of a fire. Dolphin ..................................A buoy or cluster of closely driven piles used as a fender for a dock or as a mooring or guide for boats. Dry Gas Seals .........................Seals on compressors that use dry gas as the sealing medium as opposed to liquids such as oil. ed ............................................Edition ESD ........................................Emergency Shut Down FEED......................................Front End Engineering and Design



Appendix B: Glossary of Terms and Conditions Frost Heave ............................A condition that occurs when the moisture in soil expands when frozen. This can develop very high upward forces when constrained under foundations such as those supporting LNG tanks. Full Containment (FCT) ........An LNG storage tank design in which concrete surrounds a two wall tank such that in the event of an inner tank rupture, the LNG will be fully contained within the concrete wall boundary. Gross Heating Value ..............The total heat obtained from the combustion of a specified amount of fuel which is at 60°F when combustion starts, and the combustion products of which are cooled to 60°F before the quantity of heat released is measured. Head .......................................The pressure differential that causes a fluid in a pipeline or system to flow. Usually measured in terms of the height of liquid in a column. Heat Leak ...............................A general term used to describe heat added to the process fluid from the surroundings at any location in the terminal. HP ..........................................High Pressure HTF ........................................Heat Transfer Fluid Impoundment .........................An area defined through the use of dikes or site topography for the purpose of containing any accidental spill of LNG or flammable refrigerants. LNG .......................................Liquefied Natural Gas NEHRP ..................................National Earthquake Hazards Reduction Program NFPA .....................................National Fire Protection Association P&ID ......................................Piping and Instrumentation Diagram ppm ........................................Parts per million ppb..........................................Parts per billion Phase I ....................................First phase of terminal development that encompasses all the work included in this project scope. Phase II...................................A possible future expansion of facilities that shall be taken into consideration in the current project scope. Such things as tie-in locations and plot plan space will be provided in this project scope. Radiograph .............................A picture produced on a sensitive surface by a form of radiation other than light, such as X-ray or Gamma ray. Relief Valve ...........................A valve that opens at a designated pressure and bleeds a system in order to prevent a build-up of excessive pressure that might damage the system.



Appendix B: Glossary of Terms and Conditions RFP ........................................Request for Proposal RFQ ........................................Request for Quotation RTD........................................Resistance Temperature Detector Saturation Pressure.................The pressure at which a vapor confined above a liquid will be in stable equilibrium with it. Below saturation pressure, some of the liquid will change to vapor, and above saturation pressure, some of the vapor will condense to liquid. Seismic Zone ..........................The site-specific seismic conditions that determine the level of design required for the components in the terminal such that they can withstand a probabilistic maximum considered earthquake. SIGGTO .................................Society of International Gas Tankers and Terminal Operators Slug Cooldown.......................To introduce LNG into piping or equipment without requiring prior gradual cooldown. Stages .....................................Higher pressure increases in a centrifugal pump can be achieved by using multiple “stages” in which two or more impellers are mounted in series on a common shaft. The velocity and pressure of the fluid increases as it is accelerated through each stage. Submerged Electric Motor .....A motor used to power cryogenic pumps in which the motor components and bearings are submerged in the process fluid, helping to keep the device lubricated and cooled. TBD........................................To Be Determined TEMA ....................................Tubular Exchanger Manufacturers Association UPS ........................................Uninterruptible Power Supply UV/IR .....................................Ultraviolet/Infrared Vacuum ..................................A pressure below atmospheric pressure. Vapor Handling System .........A pressure controlled system used to guarantee a prioritized distribution of boiloff gas to the appropriate components within the terminal. Vaporizer................................A device used to convert LNG to natural gas by adding heat. VJ ...........................................Vacuum Jacketed w.c. .........................................Water Column



Appendix C: Applicable Codes and Standards The Terminal shall be designed in accordance with 49 CFR Part 193: Liquefied Natural Gas Facilities Federal Safety Standards and NFPA 59A, “Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG)”, editions incorporated by reference therein. Other codes and standards to be used in the design, construction and operation of the LNG Terminal are listed in document 07902-TS-000-022. All applicable local codes and standards that have not been included in the list shall be satisfied in the design. Where there is a conflict between an international standard and a local one, the most stringent requirements shall apply.



Appendix D: Bathymetric Data


C.3 Hazard Detection and Mitigation Philosophy


Oregon LNG Warrenton, OR Hazard Detection and Mitigation Philosophy


HAZARD DETECTION AND MITIGATION PHILOSOPHY By H H C H H

REV NUMBER: ISSUE PURPOSE:

DATE: BY: CHECKED: APPROVED:


0 Issued for Client Review 10/17/2007 OOA RCT AAR

1 INCLUDES APCI DESIGN 04/19/2012 ABR JMW AAR


Section 1


Page

INTRODUCTION ..................................................................................................... 3 1.1

Scope ............................................................................................................................ 3

1.2

Regulations, Codes, and Standards........................................................................... 5

1.3

Equipment Listing and Approvals ............................................................................ 7

2

SUMMARY OF HAZARD DETECTION AND MITIGATION SYSTEM ........ 7

3

TERMINAL DESIGN, LAYOUT, AND FEATURES ........................................ 13

4

5

6

3.1

Description of Spill Impoundment Systems ........................................................... 13

3.2

Description of Other Terminal Features that Will Minimize Hazards ............... 15

HAZARD DETECTION SYSTEM ....................................................................... 18 4.1

Description of Hazard Detection System ................................................................ 18

4.2

Detection System Components ................................................................................ 22

4.3

Spare Capacity and Expandability ......................................................................... 27

HAZARD MITIGATION SYSTEMS ................................................................... 27 5.1

Dry Chemical System ............................................................................................... 27

5.2

Firewater Systems ..................................................................................................... 30

5.3

High Expansion Foam Systems ............................................................................... 36

5.4

Nitrogen Purge System ............................................................................................. 38

MOBILE FIRE FIGHTING AND SAFETY EQUIPMENT .............................. 38 6.1

Portable Fire Extinguishers ..................................................................................... 38

6.2

Personnel Protective Equipment ............................................................................. 39

7

FIRE BRIGADE...................................................................................................... 39

8

FIRE PREVENTION PLAN .................................................................................. 40


1


INTRODUCTION 1.1

Scope This document provides a design philosophy and general overview of the hazard detection and mitigation system that will be provided for the Oregon LNG Terminal ("Terminal") in Warrenton, OR. The Terminal includes: •

A marine facility structure consisting of a pier, loading platform, and loading facilities for one LNG carrier,

•

Two 160,000 cubic meter (m3) full-containment above ground LNG storage tanks (T-201),

•

Two liquefaction trains using the Air Products and Chemicals, Inc. (APCI) C3MR (propane and mixed refrigerant) Liquefaction Process, each with a nominal capacity of 4.5 million metric tonnes per annum (MTPA),

•

One vaporization train using remote heated vaporizers with a nominal capacity of 500 million standard cubic feet per day (MMSCFD),

•

Boiloff Gas Compressor (C-204),

•

Ground Flare for the liquefaction trains and a separate flare for the LNG storage and re-gasification process,

•

High Voltage Switchyard,

•

Propane and Ethane Storage, and

•

Utility systems (compressed air systems, nitrogen system, fuel gas system, fire protection systems, potable water system, and wastewater system).

•

Natural Gas Pretreatment system that removes impurities from the feed gas. The system uses diethanolamine (DEA) to remove carbon dioxide and hydrogen sulfide from the incoming gas, dehydrators for water removal, and mercury removal beds.

The hazard detection and mitigation philosophy detailed in this document is based on the following safety goals: •

Provide for the life safety and property protection of the public and neighboring facilities in the event of an LNG or hydrocarbon-based refrigerant release from the facility that may result in a fire or explosion.

•

Provide for the safety of the Terminal personnel and first responders in the event of hydrocarbon releases/spills, fire/explosion incidents, or releases of hazardous gases.

Oregon LNG Warrenton, OR Hazard Detection and Mitigation Philosophy •


Provide for property protection of the Terminal to minimize property damage and downtime that may be experienced as a result of hydrocarbon releases/spills or fire/explosion incidents.

To accomplish the above safety goals, the Terminal design applies Recognized and Generally Accepted Good Engineering Practices that minimize the potential for severe hazardous conditions to occur and their consequence. D esign features will include: •

Process system design features, arrangements and operating procedures/limits that minimize the potential for and magnitude of leaks and spills of LNG, flammable liquids and flammable gases, associated fires and explosions, nonprocess fires that may damage process equipment, and releases of hazardous gases.

•

Containment of LNG, propane, ethane and mixed refrigerant spills and vapor generation to prevent the generation of vapor clouds that exceed 50% of the lower flammability limit of each hydrocarbon at a property line that can be built upon.

•

Siting and containment of propane and mixed refrigerant storage and process equipment that minimize off-site consequences.

•

Process system, Terminal design features and fire prevention programs that minimize combustible materials and ignition sources.

The Terminal design incorporates a Hazard Detection and Mitigation System (HDMS) that minimizes the magnitude of hazards and minimizes the effects of hazards on the public, neighboring facilities and structures, Terminal equipment and structures, and Terminal personnel as follows: •

Hazard detection systems to detect LNG and refrigerant spills and leaks, natural gas leaks, carbon dioxide leaks, hydrogen sulfide leaks, and fires early during the event to alert personnel of the hazard, to shutdown process equipment and systems (as needed), and to activate hazard mitigation and control systems (as needed).

•

Hazard mitigation and control systems to minimize vapor generation, heat release rates of the fire (including fire extinguishment), and/or to heat fluxes to neighboring facilities as well as Terminal equipment and structures.

•

Hazard control systems to protect Terminal equipment and structures from fire damage and personnel from fire, smoke, and hazardous gas exposure.

•

Hazard detection and mitigation systems designed such that all immediate responses to hazardous conditions are performed automatically or remotely.

A preliminary fire safety evaluation has been performed on the front end engineering design to identify the required hazard detection, mitigation, control features and



systems to provide adequate fire safety. This evaluation was performed in accordance with the requirements of Section 9.1.2 of NFPA 59A, 2001 edition (See 07902-TS-600-400). The fire safety evaluation will be revised during the detailed design of the Terminal to document how the final design provides adequate fire safety. Where appropriate, automatic fire protection systems will be added to provide additional levels of fire safety. The detection and mitigation of hazards associated with the shipping of LNG (including carrier hazards, LNG spills on w ater, etc.) is outside the scope of this philosophy. Hazards associated with the loading, storage, vaporization of LNG, and liquefaction of natural gas are included in the scope of this philosophy. 1.2

Regulations, Codes, and Standards The fire protection system will be designed, manufactured, assembled, installed, tested, and commissioned in accordance with nationally recognized standards, building codes, and federal and state regulations. The following industry codes, standards and guidelines will be used: 1.2.1

US Code of Federal Regulations •

Title 29 CFR, Part 1910.106 -- OSHA Flammable and Combustible Liquids

•

Title 29 CFR, Part 1910.165 -- OSHA Employee Alarm Systems

•

Title 33 CFR, Part 105 -- Maritime Security: Facilities

•

Title 33 CFR, Part 127 -- Waterfront Facilities Handling Liquefied Natural Gas and Liquefied Hazardous Gas

•

Title 49 CFR, Part 193 -- Liquefied Natural Gas Facilities: F ederal Safety Standards

1.2.2

National Fire Protection Association (NFPA) •

NFPA 10 – Standard for Portable Fire Extinguishers – 2010

•

NFPA 11 – Standard for Low, Medium and High Expansion Foam – 2010

•

NFPA 13 – Installation of Sprinkler Systems – 2010

•

NFPA 14 – Installation of Standpipes and Hose Systems – 2010

•

NFPA 15 – Standard for Water Spray Fixed Systems for Fire Protection – 2012

•

NFPA 17 – Standard for Dry Chemical Extinguishing Systems – 2009



•

NFPA 20 – Standard for the Installation of Stationary Pumps for Fire Protection – 2010

•

NFPA 22 – Standard for Water Tanks for Private Fire Protection – 2008

•

NFPA 24 – Standard for the Installation of Private Fire Service Mains and Their Appurtenances – 2010

•

NFPA 25 – Standard for the Inspection, Testing, and Maintenance of WaterBased Fire Protection Systems – 2011

•

NFPA 30 - Flammable and Combustible Liquids Code - 2012

•

NFPA 54 - Fuel Gas Code - 2012

•

NFPA 58 – Liquefied Petroleum Gas Code - 2011

•

NFPA 59 – Utility LP-Gas Plant Code – 2012

•

NFPA 59A – Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG) – 2001/2009 (whichever is more conservative)

•

NFPA 70 – National Electric Code – 2011

•

NFPA 72 – National Fire Alarm Code – 2010

•

NFPA 214 - Standard on Water-Cooling Towers - 2011

•

NFPA 307 – Standard for the Construction and Fire Protection of Marine Terminals, Piers, and Wharves – 2011

•

NFPA 497 – Recommended Practice for the Classification of Flammable Liquids, Gases, or Vapors and of Hazardous (Classified) Locations for Electrical Installations in Chemical Process Areas – 2012

•

NFPA 600 – Standard on Industrial Fire Brigades – 2010

•

NFPA 750 - Water Mist Fire Protection Systems - 2010

•

NFPA 1901 – Standard for Automotive Fire Apparatus – 2009

•

NFPA 1961 – Standard on Fire Hose – 2007

•

NFPA 2001 – Standard on Clean Agent Fire Extinguishing Systems – 2012

1.2.3

Oil Companies International Marine Forum (OCIMF) •

1.2.4

Guide on Marine Terminal Fire Protection and Emergency Evacuation – 1987 American Petroleum Institute

•

API 650 – Welded Steel Storage Tanks for Oil Storage – 2008 with Addendum

•

API 2510 –Design and Construction of Liquefied Petroleum Gas (LPG) Installations – 2001

Oregon LNG Warrenton, OR Hazard Detection and Mitigation Philosophy •

API 2510A – Fire-Protection Considerations for the Design and Operation of Liquefied Petroleum Gas Storage Facilities – 1996

•

API RP500 – Recommended Practice for Classification of Locations for Electrical Installation at Petroleum Facilities Classified As Class I, Division 1 and Division 2 – 2002

1.2.5

American National Standards Institute •

ANSI/ASA S3.41, Audible Emergency Evacuation Signal – 1990 (R2001) American Society for Testing and Materials ASTM

1.2.6 •

1.2.7

1.3


ASTM F 1211-87, Standard Specification for International Shore Connections for Marine Fire Applications (1993) Instrument Society of America

•

ISA 12.13.01, Performance Requirements for Combustible Gas Detectors

•

ISA 12.13.02, Recommended Practice for Installation, Operation and Maintenance of Combustible Gas Detectors

Equipment Listing and Approvals When required within this philosophy or by NFPA codes/standards, hazard detection and fire protection equipment provided shall be Underwriter Laboratories, Inc. (UL) listed or Factory Mutual (FM) approved.

2

SUMMARY OF HAZARD DETECTION AND MITIGATION SYSTEM The Hazard Detection and Mitigation System (HDMS) will be based on providing a Proprietary Supervising Station Fire Alarm System that meets the requirements of NFPA 72 with the Central Station (main fire alarm panel) located in the Main Control Room, which will be attended 24-hours per day. Hazard detection equipment will monitor the Terminal and signal the main fire and gas alarm panel through local panels and a fiber optic network that serves the HDMS. Table 2.1 provides a hazard, detection and mitigation matrix for the Terminal to show the types of features, detectors, and mitigation systems available to address specific expected hazards. Selection of systems and components and their design conditions will be documented within the NFPA 59A Fire Protection Evaluation 07902-TS-600-400.



Table 2.1 Types of Hazards and Their Control Features, Detection Methods and Mitigation Methods Hazard

Control Features

Detection

Mitigation

- Vapor

• Piping materials designed for LNG temperatures.

- Vapor Cloud Ignition (delayed ignition)

• Piping design considers anticipated loads

• Audible and visual alarms locally and within the control room.

- Pool Fire (immediate or delayed ignition)

• Low temperature detectors in troughs/trenches and basins to detect LNG spills.

• Process control to minimize operational deviations.

LNG Spill Dispersion

• Minimization of the use of flanges. • Spill collection troughs/ curbed areas/ trenches under all LNG piping/equipment that route LNG to spill containment basins. • Minimization of ignition sources in the process areas. • Non-flammable and heat resistant/fireproofing materials used for process structures.

• Gas detection along spill paths and around process equipment to detect releases. • Flame and/or high temperature detectors around process equipment, transfer areas, vents, troughs/ trenches, basins, and other potential spill locations to detect fires. • Manual detection via operators and closed circuit television.

• Distances between process equipment to reduce fire exposures and heat fluxes. • Spacing of air intakes for fired equipment and building ventilation systems away from sources of vapor. LNG Tank Failure/Fire

• Flame roof.

• Overpressure/vacuum protection.

• Gas Detection on roof.

• Area around designed to capacity

tanks contain

• Hi-Expansion foam in basins to minimize vapor cloud formation and pool fire heat release rates. • Dry chemical extinguishers/ hose systems near LNG spill curbed areas, trenches/ troughs, and collection basins. • Water spray systems/ Monitors/hydrants with hoses to provide cooling to process equipment/ structures potentially exposed to at least 9,500 Btu/hr/ft2 thermal radiation for over 10 minutes. • Monitors/hydrants with hoses to provide increased vapor dispersion.

• Full containment design, 110% net capacity.

• Site layout to minimize exposure to structures or people off-site and on-site.

• Emergency Shutdown (ESD) (manual and/or automatic) to minimize spill duration.

detection

• Manual detection.

on

• Audible and visual alarms locally and within the control room. • Deluge system to cool other tank (as needed) from radiant energy of fire.



Hazard

Control Features

Detection

Mitigation

Liquid Propane/Mixed Refrigerant Spill/Release

• High integrity construction for refrigerant systems, hydrocarbon liquids collection systems.

• Combustible gas detection in areas with process equipment

• Audible and visual alarms locally and within the control rooms

- Vapor Dispersion - Vapor Cloud Ignition (delayed ignition) - Pool Fire (immediate or delayed ignition) - Jet/Spray Fire - Vapor Cloud Explosion - BLEVE

• Minimization of the use of flanges. • Minimization of ignition sources in the process areas • Electrical design in accordance with electrical area classifications to minimize electrical ignition sources. • Mounding of propane storage tanks for passive fire protection. • Grading/sloping of areas to prevent pooling of refrigerant liquid leaks under equipment • Spill impoundment systems (dikes, curbs, etc.) to route spills to impoundments (e.g., basins or drainage swales) • Distances between process equipment to reduce fire exposures and heat fluxes • Spacing of air intakes for fired equipment and building ventilation systems away from sources of vapor • Thermal insulation to serve as passive fire protection for large liquid propane and large liquid mixed refrigerant containing vessels.

• Visual detection via operator rounds and closed circuit television monitors and manual local emergency buttons • Gas detection at air intakes for fired equipment and building ventilation systems to shutdown equipment • Flame and heat detectors around process equipment, transfer areas, vents, troughs, impoundments, and other potential spill locations to detect fires

• ESD (manual and/or automatic) to minimize spill/release duration • Dry chemical systems and extinguishers in areas with process equipment • Water spray systems protecting exposed tanks and process equipment with liquid refrigerants. •

Monitors, hydrants with hoses and water spray systems to provide protection and cooling of process equipment/structures from adjacent equipment fires



Hazard

Control Features

Detection

Mitigation

Flammable Gas (natural gas, propane, ethane, MR) Leak/ Rupture

• Piping materials designed for process temperatures.

• Gas detection located around process equipment to detect releases. For cold heavier than air gas hydrocarbons, detection is located low to the ground.


- Vapor Dispersion - Vapor Cloud Ignition (delayed ignition) - Jet Fire (immediate or delayed ignition)

• Piping design considers anticipated loads • Process control to minimize operational deviations. • Minimization of the use of flanges. • Overpressure protection/vent system to flare. • Electrical design in accordance with electrical area classifications to minimize electrical ignition sources. • Minimization of ignition sources in the process areas. • Process equipment enclosures are equipped with non-load bearing walls to mitigate consequences of explosions due to gas/LNG leaks. • Process equipment enclosure ventilation systems provided to control gas concentration below flammability limits. For enclosures containing systems with heavier than air gases, ventilation draws air from the lower area of the buildings. • Spacing of air intakes for fired equipment and building ventilation systems away from sources of vapor.

• Gas detection located within enclosures with LNG/NG process equipment. • Gas detection within ventilation system air intakes for other buildings. • Gas detection within air intakes for fired equipment. • Flame and/or Heat detection within enclosures to detect fires. • Manual detection.

• ESD (manual and/or automatic) to minimize leak duration. • Dry chemical systems and extinguishers in areas with process equipment. • Water spray systems/ monitors/ hose systems to cool process equipment exposed to jet fires. • Water systems/hose systems to fight nonLNG/gas fires in process areas.



Hazard

Control Features

Detection

Mitigation

Carbon Dioxide or Hydrogen Sulfide Gas Releases (Gas Pretreatment Area)

• High Integrity construction for systems with high concentrations.

• Fixed gas detection at exposed operator stations

• Outdoor locations better dispersion

for

• Portable gas detectors during maintenance work


• Relief valve layout to minimize ignition sources near valves.

• Flame detection located at LNG storage tank relief valve vents.

• Site layout to minimize effects of flaring on onsite structures and personnel, and on off-site structures and people during Flare operation.

• Manual detection.

• Relief to flare system Gas Venting/Flaring - Relief valve - Flare

• High integrity construction for hydrocarbon liquids collection systems, refrigerant systems, lube oil systems, and fuel oil systems. • Minimization of threaded connections • Spill systems etc.).

impoundment (dikes, curbs,

• Dry chemical systems for LNG storage tank relief valve discharge pipes. • Nitrogen purging system for Flare header to minimize oxygen within the Flare stack.

• Flare design to include features to prevent flash back of flame into piping system.

Fires caused by Other Flammable (e.g., Liquids/Gases collected liquids, refrigerants, lube oil, fuel oil, heat transfer oil)


• Monitors for cooling water for other equipment near relief valves. • Combustible gas detection in areas with equipment. • Heat and/or smoke detection within enclosures to detect fires. • Flame and/or Heat detection in outdoor areas with equipment. • Manual detection.

• Audible and visual alarms locally and within the control room. • Ventilation systems within enclosures to control gas concentration below flammability limits. • Dry chemical systems and extinguishers in areas with process equipment. • Sprinkler systems/ hose systems to fight non-process fires, lube oil fires, and fuel oil fires, and to cool and equipment structures.



Hazard

Control Features

Detection

Mitigation

Electrical Systems

• Electrical design in accordance with electrical area classifications.

• High sensitivity smoke detection in areas with electrical, computer, and/or control system components.


– Failure/Fire

• Fault protection. • Fire Separation of oilinsulated transformers. • Fire resistant insulation.

cable

• Heat detection within areas with high voltage, oil insulated equipment. • Manual detection.

• Clean Agent systems in unoccupied remote, electrical or control rooms. • Carbon dioxide portable extinguishers in areas with electrical equipment. • Hose systems with fog nozzles in electrical areas.

Exposure Fires

• Minimize use of flammable or combustible materials in construction. • Use of fire rated construction materials for critical structures.

• Smoke detection. • Heat detection. • Manual detection.

• Appropriate portable extinguishers in area.

• Facility layout to separate combustibles from ignition sources to greatest degree practical.

• Suppression systems appropriate for the hazard. • Hose systems.

• Fire prevention program to minimize transient combustibles and ignition sources. Fired (including engines)

Equipment combustion

• Facility layout to minimize potential for natural gas vapors to enter the combustion air inlets. • Facility layout to separate fired equipment from potential sources of natural gas vapors and other combustible materials to extent possible.

Diethanolamine Releases

• Spill impoundment system to prevent release to environment.


• Combustible gas detectors in air inlets. • Heat detection. • Manual detection

• Audible and visual alarms locally and within the control room. • Automatic shutdown of fired equipment. • Suppression systems. • Hose systems.

• Manual Detection

• Hose systems with fog nozzles • Dry Chemical portable extinguishers in area


3


TERMINAL DESIGN, LAYOUT, AND FEATURES 3.1

Description of Spill Impoundment Systems All areas with piping, tanks, and process equipment that contain LNG, liquid propane, liquid ethane or liquid MR will be designed to capture and contain any leaks and spills. This helps minimize vapor generation and dispersion rates as well as reduce the potential for and consequences of fires. The impoundment system will be designed and located in accordance with NFPA 59A-2001 and 49 CFR193 to avoid or minimize impact on t he public due to the hazards of vapor cloud formation or radiant heat from a fire within the impoundment. Impoundment systems will be constructed of concrete or steel. Active systems to reduce vapor formation rates and fire exposure may be provided as well but no credit is taken for these in spill impoundment design or locations. The location and routing of these impoundment systems will be illustrated on a plot plan showing direction of flow and dimensions. Calculations for containment basin sizes will be included in the Thermal Radiation and Flammable Vapor Exclusion Zone report 07902-TS-000-011. The key components that make up spill impoundment systems are discussed below. 3.1.1

LNG Storage Tank – Full Containment Tank The LNG storage tanks will be a full containment tanks consisting of a secondary reinforced concrete outer wall and roof. Sizing of the secondary tank is in accordance with 49 CFR193.2181 and NFPA 59A-2001 to contain a full rupture of the primary tank. Tank penetrations will be located at the top of the inner and outer tanks to minimize potential leaks below the LNG liquid level. L eaks from penetrations or piping on t op of the tank (such as for the fill lines from liquefaction or the ship loading lines/pumps) will be channeled to the LNG Spill Containment Basin, S-606. The tank roof will be protected by sacrificial concrete where LNG spills may occur.

3.1.2

LNG Loading Curbs will be provided around the marine loading arms to minimize the spread of LNG spills at the loading arms. These curbed areas will channel the LNG to a trough that runs to the Tank Area LNG Spill Containment Basin (S-606). In addition, the loading arm lines have emergency shutdown safety shutoff valves to limit the size of a spill due to the rupture of a loading arm. The loading arms are also equipped with emergency release systems that enable the arm disconnect from the carrier in an



emergency situation during loading. Any leakage from the piping between the loading arms and the storage tanks will also be collected in a trough that channels the spill to the Tank Area LNG Spill Containment Basin (S-606). The troughs and basin will be insulated to minimize vapor generation. In addition, detection systems and hazard mitigation systems will be provided in the troughs and basin to alert operators and/or activate the emergency shutdown system to stop LNG flows and limit the volume of LNG released, and to provide further control of vapor generation and potential for fire. 3.1.3

Process Areas The process area containing the vaporization train and the two liquefaction trains is located in a b ermed area separate from the LNG Storage Tanks. LNG, liquid propane, and liquid MR leaks in the process area are most likely to occur at valves, flanges, fittings and pipe penetrations in vessel walls. Accordingly, to reduce the possibility of leaks, process piping used at the Terminal to convey liquid and gaseous hydrocarbons will be of a welded design to the extent practical. In addition, the number and size of penetrations in vessels will be minimized. Equipment in the re-gasification process area that contains LNG will be curbed such that all spills and leaks will drain into open trenches that feed into the Re-Gasification Area LNG Spill Containment Basin (S-608). Equipment in the liquefaction process area that contains LNG or liquid mixed refrigerant will be curbed such that spills and leaks from LNG and liquid mixed refrigerant piping and equipment will drain into open trenches that feed into the Liquefaction Area LNG Spill Containment Basin (S-607). The process areas in the liquefaction trains that contain liquid propane, including the Propane Condenser (E-2603), Propane Accumulator (E-2604), Propane Subcooler (E-2605), Propane Feed Gas Coolers (E-2001/2002/2003/2004), and Propane MR coolers (E-2621/2622/2623/2624), will be curbed and the ground sloped to channel liquid propane away from the process equipment and to a propane drainage swale. Active systems to detect spills or ruptures within the process systems will be used to alert operators and/or activate the emergency shutdown system to stop LNG, mixed refrigerant, and/or propane flows and limit the volume released. The emergency shutdown system will be designed to shut down flows well within the ten minutes assumed for the worst spill case.



The LNG spill impoundment system will be insulated and sized to minimize vaporization rates due to LNG spills. The basin designs will limit their surface area to further control vaporization rates and heat release rates if ignited. 3.1.4

Propane and Ethane Storage Area Curbed areas that slope away from the storage tanks will be provided at the propane and ethane storage area that will route any liquid spills to an impoundment located away from the storage tanks. Ethane spills will be routed to the Liquefaction Area LNG Spill Containment Basin (S-607). Propane spills will be routed to the propane drainage swale.

3.1.5

Storm Water Drainage The site will be graded to minimize the amount of storm water that enters the spill impoundment systems. Storm water falling outside the spill impoundment systems will be removed using conventional drain systems. Storm water that falls into potential LNG, propane, and MR spill areas will collect in the impoundment system and will flow to the spill containment basins or the liquid propane drainage swale. Storm water systems will be sized to handle the worst possible storm based on a tenyear storm history of the site per 49 CFR 193.2173.

3.1.6

Storm Water Removal The spill containment basins will have redundant pumps to pump any rain water that may collect within the impoundment systems. The pumps will be automatically or manually operated, with interlocks from the hazard detection system that will shut down the pumps if LNG, propane, or MR is detected in the basin. T hese features will prevent accidental pumping of LNG, propane, or MR into areas that may allow an uncontrolled release. The pumps will be sized to remove water at the rate of 25% of the 1 hour rainfall rate for the 10 year storm in accordance with 49 CFR 193.2173.

3.2

Description of Other Terminal Features that Will Minimize Hazards 3.2.1

Explosion Prevention Features 3.2.1.1

Building Construction Ignited natural gas vapor clouds do not result in overpressure conditions unless the ignition occurs within an enclosed space. Ignited propane gas vapor clouds can result in overpressure conditions when unconfined. To minimize damage to structures,



most process equipment will be located outdoors. Where enclosures are used for process equipment handling natural gas, LNG, or refrigerants, the enclosure shall be constructed with noncombustible materials and have non-structural walls in accordance with NFPA 59A-2001. Buildings will be equipped with monitors to detect combustible gas releases and hazardous conditions, and active systems to operate the building ventilation systems so as to maintain flammable gas concentrations below their Lower Flammability Limit (LFL) value. If a building shares space with process equipment containing natural gas, LNG, or refrigerants, then fire rated barriers that can withstand a static pressure load of at least 100 lbs/ft2 (psf) shall be installed to separate parts with LNG and flammable gas from those other areas without in accordance with NFPA 59A-2001. The Main Control Building and Field Instrument Buildings shall be constructed to be blast resistant for the expected overpressure from a potential unconfined vapor cloud explosion. Remaining buildings shall be evacuated upon detection of major refrigerant releases and so do not require blast resistance. 3.2.1.2

Ventilation Systems For enclosures containing natural gas, LNG or refrigerant process equipment, ventilation systems designed in accordance with NFPA 59A-2001 will be provided to minimize the concentration of flammable gases within the enclosure. Where the vapor may be heavier than air, the ventilation system will be designed to ventilate lower areas of the enclosure where these gases may accumulate. The systems may rely on natural as w ell as f orced ventilation and achieve an exhaust rate of at least 1 cfm/ft2 of floor space. For other buildings, the HVAC supply air will be monitored for flammable/combustible gas at the air intakes (discussed later).

3.2.1.3

Air Intakes of Combustion Equipment In accordance with NFPA 59A-2001, the air intakes for combustion equipment shall be located outside a co mpletely enclosed structure. The air intakes will be monitored for flammable/combustible gas.

3.2.2

Materials of Construction LNG piping for the Terminal will be designed for cryogenic service. Buildings, structures, equipment will be constructed of non-combustible materials to the greatest extent possible, generally of steel and/or concrete.



Equipment and piping insulation materials shall be non-combustible, and fire resistance features shall be provided if exposed to fire conditions. 3.2.3

Ignition Sources Ignition sources shall be minimized and located away from impoundments. The following specific requirements from NFPA 59A2001 for ignition sources shall be considered in the design: 3.2.3.1

Heat and Flame Sources Fired equipment and other sources of ignition shall be located at least 50 ft from any impounding area. Process equipment containing LNG, flammable liquids, or flammable gases shall be located at least 50 ft from sources of ignition. Integral heated vaporizers (if used) shall be located at least 50 ft from any impounding area or paths of travel.

3.2.3.2

Electrical Ignition Sources Electrical classification areas for hazardous locations will be established in accordance with NFPA 59A-2001 and API RP500. Electrical equipment that will be installed in a hazardous location in the Terminal shall be: • Intrinsically safe; • Designed for the appropriate hazardous area classification; or • Installed in an enclosure, which is designed for the

appropriate hazardous area classification.

Fire, temperature, and gas detection equipment will be required to operate in site areas classified as hazardous. The electrical equipment and circuits within the classification areas shall be designed in accordance with NFPA 70, the National Electric Code. P lans shall be developed to adequately maintain the safety of these devices.


4


HAZARD DETECTION SYSTEM 4.1

Description of Hazard Detection System A hazard detection system (HDS) will be provided to detect, notify, and activate mitigation actions associated with the hazards of spills and leaks of LNG, natural gas, and refrigerants; leaks of other hazardous gases; and fires. A single plant-wide system based on a Proprietary Supervising Station Fire Alarm System that meets the requirements of NFPA 72 will be provided. The supervising station shall be located in the Main Control Room (MCR) which will be attended 24-hours per day. All fire system control and monitoring will be provided from the MCR with displays at alternate locations. In addition, fire and gas alarm system signals will be provided to the Distributed Control System (DCS) for display at the operator stations. Call outs to the designated fire department(s) will also be made through the system. The hazard detection system shall be fully addressable to indicate both the type of hazard and location of the hazard. The system shall have self-diagnostics and fault detection using Class A wiring systems. The Terminal will be divided into areas that will be monitored separately and which may have local panels networked to the central station. Alarms shall be both audio and visual alarms locally and in the MCR. The Platform Control Room (PCR) will be provided with a local control panel for local operation of platform fire control and firewater systems during LNG loading operations. This is the only time that the PCR is expected to be constantly occupied. All controls provided at this location will also be provided at the MCR. The system located on the platform shall meet the requirements of 33 CFR127 with alarms, controls, and communications located both in the PCR and the MCR. The platform and pier shall have sirens and amber warning lights in accordance with 33 CFR127.207. Leak detection at the Terminal will be accomplished using low temperature detectors (for LNG leaks) and combustible gas detectors in areas with potential LNG, natural gas, or refrigerant leaks. Fire detection will be accomplished with the use of smoke, heat, flame, and/or high temperature detectors. Manual pull stations will also be provided at key process area access points. T he site will be monitored by closedcircuit TV from the MCR which provides additional detection capability. Gas detection will also be provided for areas that do not contain LNG, natural gas, or refrigerant, but where the presence of combustible gas or other hazardous gas may result in a significant hazard. This will include air intakes for fired equipment and for occupied buildings.



The hazard detection system will include logic to provide signals to the Terminal’s Emergency Shutdown (ESD) Systems and/or to activate automatic fire protection systems. The capability to manually activate some of the fire protection systems will be provided through hard-wired switches in the MCR and PCR. Manual activation of systems will also be provided locally. 4.1.1

Specific Requirements for the Hazard Detection System 4.1.1.1

A stand-alone independent Hazard Detection System shall be provided to continuously monitor and alert the operator to hazardous conditions throughout the Terminal due to leaks of LNG, flammable liquids, and flammable gases, and fires.

4.1.1.2

Monitoring capability shall be provided via graphic display screens and mimic panel displays located in the Main Control Room (MCR) and the Platform Control Room (PCR).

4.1.1.3

In response to the Fire & Gas alarm, the Operator will manually initiate appropriate fire fighting and/or shutdown actions via hardwired switches provided on t he MCR and the PCR control consoles.

4.1.1.4

Selected fire zone alarms and overview graphics shall also be repeated on the Terminal’s Distributed Control System (DCS) via communications links. The fire zones shall be defined based on the Terminal layout.

4.1.1.5

Fire & Gas detection and protection of offices and other buildings will be via networked fire panels. T hese fire panels will be located in individual buildings and networked to the Central Station (main fire alarm control panel) in the MCR. T hey will provide common alarms and status information to the Central Station.

4.1.1.6

Building-related common alarms will be displayed on the Terminal’s central station and associated mimic panels and also transmitted to the DCS.

4.1.1.7

The Terminal’s Hazard Detection System shall consist of the following components: • Field mounted fire & gas detectors and other sensors located

in areas that can have flammable gas, LNG or other hazardous gas present, and fire, as required by the Fire Protection Evaluation required per NFPA 59A (Section 9 of NFPA 59A-2001). These instruments shall be accessible for maintenance and readability.



• A main fire alarm control panel, which shall be located in the

MCR. A high-integrity system listed for fire monitoring service is required.

• Operator interface – video display units and printers located

at MCR and PCR.

• Mimic panels, located in other buildings such as t he admin

office.

• Hard-wired switches located in the MCR and PCR. T he

number and location of these switches will be defined during detailed design.

4.1.1.8

The Terminal’s Hazard Detection System will have interfaces with the following systems: • DCS – redundant Ethernet or serial links • Emergency Shutdown (ESD) System – hardwired • Safety Instrumented System (SIS) – hardwired • Public Address/ General Announcement (PA/GA) system –

hardwired

The level of integration among systems will be defined during the detailed design. 4.1.1.9

All hazard signals will alarm both in the control room and locally. Local signals will be both audible and visual (strobe lights) and have distinctive alarms and colors for fire and flammable gas (leak) hazards. Where appropriate, a hazard trip may initiate automatic shutdown of equipment and systems and may activate the ESD system.

4.1.1.10

Audible signals shall have a sound level of not less than 75 dBA at 10 ft. Horns can be used where louder and/or more distinctive signals are needed. The audible alarm for the marine transfer area shall meet the requirements of 33 CFR127.207.

4.1.1.11

The audible hazard alarm signal used to notify building occupants of the need to evacuate shall be in accordance with ANSI/ASA S3.41.

4.1.1.12

Emergency voice/alarm communications service shall be provided by the HDS with automatic or manual voice capability over the Terminal PA system to provide voice instructions to the building occupants. Speakers shall be located in each notification zone.

4.1.1.13

Visual indication shall be provided in the protected zone. If a light pulse is installed, the flash rate shall not exceed two flashes per



second (2 Hz). T he light source color shall be clear or nominal white for fire. Combustible gas leaks shall use an amber colored strobe or beacon. T he warning light for the marine transfer area shall meet the requirements of 33 CFR127.207. 4.1.1.14

Actuation of alarm notification via devices or warning systems, fire safety functions, and annunciation at the protected area and in the MCR and PCR shall occur within 10 s econds after the activation of an initiating device.

4.1.1.15

The signal from an initiating device shall be acknowledged at the control panel for the HDS by trained personnel within 15 seconds of annunciation.

4.1.1.16

If any other initiating device is actuated, notification signals in accordance with the Terminal fire plan shall be immediately activated. If two initiating devices are adjacent, the HDS shall consider this an ESD level alarm.

4.1.1.17

A hazard alarm signal shall take precedence or be clearly recognizable over any other signal even when the non-fire signal is initiated first. Distinctive alarm signals shall be used so that hazard alarms can be distinguished from other process alarms.

4.1.1.18

Fire hazard detection systems for protected areas shall be capable of being reset or silenced only from the HDS panel at the MCR.

4.1.1.19

If non-passive ventilation systems are used, gas detection within buildings with natural gas, mixed refrigerant, ethane, propane or LNG shall activate building ventilation systems upon detection of gas at no more than 25% of the LFL.

4.1.1.20

Closed-circuit TV (CCTV) provided in the MCR and PCR shall provide capabilities of surveillance of different areas in the Terminal, enabling the detection of events in site areas possibly rarely visible by operational personnel, particularly at night.

4.1.1.21

CCTV facilities shall be provided to secure as full as possible coverage of process area in a f ire, gas, and LNG spill detection role, and support also monitoring of site perimeter and other areas in a general site security role.

4.1.1.22

Communications with the designated fire department(s) and other emergency response organizations will be established within the Terminal Emergency Response Plan.

Oregon LNG Warrenton, OR Hazard Detection and Mitigation Philosophy 4.2


Detection System Components 4.2.1

Addressable Fire Alarm Panels The main fire alarm control panel shall be located in the MCR. The PCR shall also have a fire alarm control panel to monitor, control, and alarm the platform and pier detector devices and the hazard mitigation systems. Other panels shall be located for local control and alarm as determined during the final design. The fire panels shall be networked to the main fire alarm control panel. The panels shall specify devices and areas in alarm, maintain an alarm log, and provide for individual acknowledgement of alarms from the main fire alarm control panel. L ogic to initiate hazard mitigation systems and to activate local notification devices shall be provided by local fire alarm control panels or the main fire alarm control panel if there is no l ocal panel. All components in the system shall be compatible. The panels shall be UL listed or FM approved for fire service. P ower supplies shall be in accordance with NFPA 72. Mimic panels for display shall be provided in other buildings as determined during final design.

4.2.2

Combustible Gas Detectors 4.2.2.1

Combustible gas detectors shall be capable of detecting the combustible gases that may be present in the area (e.g., methane, propane, ethane). The combustible gas detectors shall be calibrated and setpoints established to the likely gas release in that area but will still be set up to detect any of the hydrocarbon gases. Specific calibrations and setpoints in certain areas are: • LNG Spill Containment Systems - Methane • Re-Gasification Area - Methane • Propane Curbed Area - Propane • Propane Compressor - Propane • MR Spill Area - Ethane • MR Compressors - Ethane • Platform Control Room Ventilation Intake- Methane • Heater Building Ventilation Intake - Methane • Other Building Ventilation Intakes - Propane



• Fired Equipment Combustion Air Intakes - Propane

4.2.2.2

Combustible gas detectors will be located outside in various locations throughout the Terminal where LNG, natural gas, or refrigerants may leak or accumulate (e.g., troughs and basins). It must be recognized that gas detectors located outside are subject to reduced sensitivity to an actual spill or leak due to wind direction and obstacles. Redundant leak detectors (gas detector and/or low temperature detector) shall be provided for each area.

4.2.2.3

Combustible gas detectors will be installed inside buildings where natural gas, LNG, or refrigerant is processed to monitor for gas leaks within the buildings. These gas detectors shall “pre-alarm” and activate the building exhaust fans (if active exhaust systems are installed) upon sensing 20% LFL and alarm upon detection of a 40% LFL. G as detector placement shall consider whether the gas is buoyant (detectors placed high) or not (detectors placed low). If the gas has the potential to leak into other spaces that do not have gas or LNG equipment, then these spaces shall also have gas detectors. Gas detectors shall include 4-20 mA transmitters mounted in a junction box suitable for hazardous location.

4.2.2.4

To monitor leaks at outdoor equipment, the combustible gas detectors shall be installed as close as possible to the likely points of leakage (e.g., flanges, valves, pressure reducers, etc.) For area monitoring, gas detectors shall be located to take into account local flow conditions (e.g., type and rate of ventilation system, ambient conditions, etc.).

4.2.2.5

Combustible gas detectors shall be installed in the air-intake of each heating, ventilating & air conditioning (HVAC) unit of the buildings in the Terminal to prevent the introduction or recirculation of gas. There shall be one or more duct-mounted gas detectors located in the air-intake for each building. E ach duct mounted gas detector shall “pre-alarm” upon s ensing 20% LFL. Upon sensing 40% LFL, a second alarm will activate and the HVAC system will be automatically shutdown through the hazard detection system. The transmitter shall be mounted separately from the detector sensor.

4.2.2.6

Combustible gas detectors shall be installed at the combustion air inlet for fired equipment. E ach duct-mounted gas detector shall “pre-alarm” upon sensing 20% LFL. Upon sensing 40% LFL, a second alarm will activate in the case of diesel fired systems. For gas fired heaters upon sensing a 4 0% LFL, a seco nd alarm will activate and the heater and its inlet air flow will be automatically shut down by the hazard detection system. Diesel fired systems will not be shutdown because they are more robust systems and



are needed for emergency situations. The transmitter shall be mounted separately from the detector sensor.

4.2.3

4.2.4

4.2.2.7

Combustible gas detectors shall be placed on the tank top platform and at the exhaust of the LNG tank relief valves. These detectors shall “pre-alarm” at 20% LFL and alarm at 40% LFL to alert the technicians of a release.

4.2.2.8

Combustible gas detectors shall be provided with local status and fault indication.

Toxic Gas Detectors 4.2.3.1

Toxic gas detectors shall be capable of detecting the appropriate toxic gas that may be released in the area (e.g., carbon monoxide, carbon dioxide, hydrogen sulfide). T he toxic gas detectors shall be calibrated and setpoints established to the likely gas release in that area.

4.2.3.2

Toxic gas detectors shall be installed at outdoor work stations that are likely to be visited regularly by plant personnel and are near potential release points.

4.2.3.3

For enclosed spaces with the potential for a t oxic gas release internally, toxic gas detectors shall be installed throughout the space. Placement shall consider the buoyancy of the gas.

4.2.3.4

For enclosed areas with fired equipment, carbon monoxide detectors shall be installed.

Low Temperature Spill Detectors 4.2.4.1

Resistance Temperature Detectors (RTD) and/or thermocouple type detectors shall be installed in process locations where LNG spills are possible. Specifically, low temperature detectors should be placed at the bottom of the spill impoundment system, in curbed areas under LNG equipment, and near LNG leak locations. Redundant leak detectors (gas detectors and/or low temperature detectors) shall be provided for each area.

4.2.4.2

The detectors shall alarm upon sensing temperatures less than or equal to -75°F. Detector outputs will be used to activate alarms on the MCR and PCR panels. T he locations of any detected spills shall also be annunciated on all mimic panels and associated graphic displays.

Oregon LNG Warrenton, OR Hazard Detection and Mitigation Philosophy 4.2.5

4.2.6

4.2.7


High Temperature Detectors 4.2.5.1

RTD and/or thermocouple type detectors shall be installed in process locations to detect fire conditions where heat detectors may not be practicable.

4.2.5.2

High temperature detectors shall be located in the LNG spill impoundment system (troughs and basins), at locations near low temperature detectors but located above the trough or basin. The detectors shall alarm upon sensing temperatures equal to or greater than 165°F.

4.2.5.3

Detector outputs will be used to activate alarms at the MCR and PCR panels. T he locations of any detected spills will also be annunciated on all fire alarm panels and associated graphic displays.

Heat Detectors 4.2.6.1

Heat detectors shall be installed in areas where smoke detectors are not suitable. Specific locations include over fired equipment, in outdoor areas, and within buildings/enclosures where fast growing fires are likely.

4.2.6.2

Heat detectors shall be addressable, compatible with the fire alarm control panels, and UL listed or FM approved. Heat detectors may be fixed temperature, rate of rise, or compensated. Temperature setpoints shall be based on expected ambient conditions. The rate of rise setpoint shall be 15°F/min.

4.2.6.3

Heat detectors shall be located in small spaces or where high heatoutput fires are expected if an automatic sprinkler system is not provided.

4.2.6.4

Heat detectors located outdoors shall be rate of rise or compensated heat detectors.

Smoke Detectors 4.2.7.1

Spot-Type Smoke Detection Spot-type detectors shall be used for general fire detection. These detectors shall be provided in enclosed areas with ordinary combustibles and electrical hazards where fire growth is likely to be slow (smoldering fires likely). Smoke detectors shall be suitable for non-hazardous locations.



Smoke detectors shall be addressable with an alarm LED for identification in the event of an alarm condition. The detectors shall be compatible with the fire alarm control panel and be UL listed or FM approved. 4.2.7.2

Highly Sensitive Smoke Detection (HSSD) System A Highly Sensitive Smoke Detection System may be provided for critical electrical rooms that may or may not be occupied and it is not desirable to install sprinkler systems. These rooms include the MCR, PCR, computer/DCS rooms, local control shelters, and MCC rooms. The system shall provide early warning of smoke presence in critical areas and will annunciate alarms to the fire alarm control panels, the DCS, and all mimic panels. The HSSD systems allows for an earlier manned response than a standard smoke detector. H SSD with a m anned response may be used in lieu of fixed extinguishing systems in areas with high concentrations of electrical components and equipment where: • inadvertent sprinkler system actuation or rupture could cause

electrical system damage and faulting,

• very focused application of fire suppression agents (e.g., from

an extinguisher) would be effective and desirable,

• personnel may be exposed to gaseous clean agents, and/or • frequent room access o r activities can result in room

passageways being left open often (e.g., doors left open) such that gaseous clean agent suppression systems are not effective.

4.2.8

Products of Combustion 4.2.8.1

4.2.9

The Terminal will not use Products of Combustion detection systems except those described in the smoke detectors section.

Flame Detectors 4.2.9.1

UV/IR flame detectors will be used to detect radiation emissions from LNG/natural gas fires on an area basis. Detectors located outside shall be selected to minimize the potential of false activation due to sunlight and other light sources.

4.2.9.2

Flame detectors shall provide fire and fault digital outputs to the HDS panel and be compatible with the fire alarm control panels. The detectors shall be UL listed or FM approved.

4.2.9.3

Flame detectors shall be strategically positioned to ensure that all potential fire locations are within their cone of vision.



4.2.10 Manual Pull Stations

4.3

4.2.10.1

Manual pull stations shall be strategically located in the process and building areas of the Terminal. T hese stations shall be used only for fire alarm-initiating purposes, but shall be regarded as a valid signal for initiation of fire, gas or spill mitigation systems, and emergency shutdown…

4.2.10.2

A Manual pull station shall be located within 5 ft of all building entrances/exits.

4.2.10.3

Manual pull stations shall be clearly visible and distinctly identified so that a technician can manually activate the alarm.

4.2.10.4

Manual pull stations located in hazardous locations shall be suitable for a minimum classification meeting or exceeding Class I, Div 2, Groups C/D. Manual pull stations installed in buildings will not be required to meet this classification.

Spare Capacity and Expandability At least 10% spare capacity shall be available within Hazard Detection Systems. This includes relay cabinets, marshalling cabinets, terminations, monitor switches, I/O points, user program memory, etc. For I/O points the 10% spare is on a point type basis. A ll spare points shall be fully wired to marshalling cabinet Terminals. At least 10% available spare space shall exist within each safety and control subsystem for future expansion. This includes space in system and marshalling cabinets for terminations, monitors switches, additional I/O modules, etc. T his 10% spare space is in addition to installed 10% spare capacity required above.

5

HAZARD MITIGATION SYSTEMS 5.1

Dry Chemical System Dry chemical systems are effective against hydrocarbon pools and 3-dimensional fires (e.g., jet fires), particularly those involving pressurized natural gas or LNG spills, provided re-ignition potential is low. The dry chemical agent to be used at the Terminal shall be potassium bicarbonate (“Purple-K®”) as this has been found to be the most effective of the dry chemical agents. In addition, dry chemical systems may be used in conjunction with high expansion foam systems in select areas; accordingly, the dry chemical agent must be compatible with the high expansion foam agent. Dry chemical systems may consist of total flooding systems, local application (fixed nozzle and/or hose line systems), and/or portable extinguishers (both handheld and



wheeled). System selection, as discussed in the Basis of Design section below, will depend on t he type of hazard, the location of the hazard, the size of the hazard, existence of nearby ignition sources, ability to access the hazard, and the potential consequences of the fire on the public, Terminal personnel, and Terminal equipment. These systems will be located in strategic locations to facilitate effective fire extinguishment. 5.1.1

Basis of Design for Dry Chemical System Dry Chemical System selection will be based on the configuration of the area containing the hydrocarbon hazard. Specifically: •

Enclosed areas that contain natural gas, LNG, or refrigerant processing equipment shall be protected with a total flooding system due to the risk of a three-dimensional fire. This includes within the tail pipes of LNG tank relief valves. These systems will be automatically activated by the Hazard Detection and Mitigation System using heat and/or flame detectors.

•

Areas where LNG or liquid refrigerant spills may collect shall be provided with a local automatic or manually operated application system or portable extinguishers, depending on the results of a hazards evaluation that considers the size of the hazard, ignition sources available, time required for response, and other factors.

•

Open areas where plausible leaks, sprays, or ruptures involving natural gas, LNG, or refrigerant may occur shall be provided with a local application system or portable extinguishers. A s these potential fires are likely to be small and less likely to significantly affect the public or Terminal personnel or equipment, manual systems (either hose lines or portable extinguishers) shall be applied.

Systems shall be designed and sized in accordance with NFPA 17 and be UL listed or FM approved. In accordance with 33 CFR127.609, a dry chemical system shall be provided for the marine transfer area (i.e., under the loading arms). This system shall be for local application with at least two discharge systems, one of which must be a monitor. The second may be either a monitor or a hose line. System capacity will be designed to provide 45 second discharges from each system either sequentially or simultaneously. Manual systems consisting of either hose line units or portable extinguishers will be employed provided the area to be protected does not typically have ignition sources, is easily accessible, the fire size is such that personnel can approach the fire to effectively apply the dry chemical



agent, and the consequences of the fire to the public and the Terminal are found to be low, allowing time for a manual response. If an automatic system is determined to be needed for a local application, then the dry chemical will be applied by either nozzles or monitors. Sufficient detection equipment, such as heat and/or flame detectors, will be provided for system activation. Portable dry chemical extinguishers will be provided throughout the process area for fast response to small fires. The placement and sizing of these portable extinguishers shall be based on N FPA 10. T he extinguishers shall be UL listed or FM approved. 5.1.2

Dry Chemical System Sizing Dry chemical system sizing will be performed during detailed design. System sizes are based on the required flow rate, the minimum discharge time, and the system quantity. For preliminary engineering, system sizes based on a potassium bicarbonate agent are estimated per Table 5.1.2-1. Table 5.1.2-1 Dry Chemical System Sizing Type of System

Total Flooding System (3) Local Application (4) Marine Unloading Area Local Application (5) Pressure Jet (6) Hose Lines (7)

Minimum Discharge Time (sec)

Required Flow Rate(1) (lbs/sec)

Dry Chemical Quantity(1) (lbs)

30 30 45

0.00125V 0.04A 2 x 0.04A

0.115V (2) 1.2A 2 x 1.8A

30 30

1.0/mmscfd gas 8-10/hose line

30/mmscfd gas Per Local Application

Notes: (1) V = Volume of enclosure in ft3. A = footprint area of protected space in ft2. (2) A Safety Factor of 3 is applied to the quantity. It is assumed for preliminary design that there are no un-closable openings, that ventilation systems will be shut off, and that doors will automatically close. F or final design, system quantity shall be adjusted to account for un-closable openings in accordance with NFPA 17. (3) Per Chemguard Data Sheet D10D03210 (Note: Reference to Chemguard data is only for estimating purposes and not to imply that Chemguard systems will be used. EPC will specify system and select vendor during final design). (4) Per “Considerations Relating to Fire Protection Requirements for LNG Plants” by H.R. Wesson, (75-T-47) AGA Operating Section Proceedings, 1975 for earthen dikes (for conservatism). (5) Per 33 CFR127.609. (6) Per Chemguard Data Sheet D10D03212, "Calculations/Design Procedures Basic Fire Protection Requirements for Hydrocarbon Hazards Offshore Platforms." This is consistent, after applying a safety factor of 2 with “Extinguishment of


(7)

5.2


Natural Gas Pressure Fires” by A. Guise (Fire Technology August 1967) where horizontal impingement fires required about 0.4 lbs/sec/mmscfd gas. G uise’s data does not extend to the maximum flows expected at Oregon LNG but the factor of safety provides some margin. Per “Considerations Relating to Fire Protection Requirements for LNG Plants” by H.R. Wesson, (75-T-47) AGA Operating Section Proceedings, 1975.

Firewater Systems The firewater system will be based on a freshwater distribution fire main loop that is fed via fire pumps from a firewater storage tank. The distributed loop will provide firewater to various sprinkler systems, automatic water systems, hydrants, monitors, and other systems as needed. The storage tank capacity will be sufficient to provide water to the largest system demand for 2 hours. The largest system demand is the demand from the largest subsystem (including monitor protected areas) plus a 1,000 gpm hose stream allowance per NFPA 59A-2001. The tank will be supplied from the municipal water system. In addition, the Terminal will use an LNG storage tank deluge system to wet the storage tank that could be exposed to the heat from a fire involving the other tank. The deluge system will be fed from dedicated pumps taking suction from the Skipanon River. A cross-connect with a normally closed valve between the deluge system and the fresh water system will be provided to allow the Deluge Firewater Pumps to back up t he Diesel and Electric Firewater Pumps in the highly unlikely event that the main fire pumps become unavailable. The main firewater pumps consist of two jockey pumps and two 100% firewater pumps, one electric motor driven (Electric Firewater Pump) and the other diesel driven (Diesel Firewater pump). T he Deluge Firewater Pumps will all be diesel driven with sufficient fuel for 8 hours of operation. The offshore section of the fire main will not be looped but it will have international shore to carrier connections for the moored LNG carriers in accordance with the OCIMF guidance in “Guide on Marine Terminal Fire Protection and Emergency Evacuation.” In addition, pump-in points for fire boats shall be provided for further backup capability. 5.2.1

Firewater System Basis of Design The firewater system shall be designed based on t he requirements and guidance in 49 CFR193, 33 CFR127, NFPA 59A-2001, the OCIMF “Guide on M arine Terminal Fire Protection and Emergency Evacuation,” and API2510A “Fire Protection Considerations for the Design and Operation of Liquefied Petroleum Gas Storage Facilities.” System components shall be UL listed or FM approved for fire service.



The firewater storage tank shall conform to the requirements of NFPA 22. The fire pumps shall conform to the requirements of NFPA 20. The fire main shall conform to the requirements of NFPA 24. Non-process buildings will be protected by sprinkler systems and meet local building codes. Because water is not effective at extinguishing LNG fires, the primary function of the firewater systems in process areas will be to provide water to cool process equipment and other structures due to fire exposure. Firewater systems may also be used to help control vapor dispersion. As a result, most systems will consist of monitors and hydrant coverage. Specific aspects of the system design are provided below. 5.2.2

Firewater System Design Demand 5.2.2.1

Terminal Firewater System The design of the firewater supply and distribution systems shall be based on the volume of water required to combat and protect against the maximum credible fire event, thereby establishing the “design basis firewater demand” for the Terminal, plus a hose stream allowance of 1000 g pm per NFPA 59A-2001. S eparate, unrelated simultaneous fires in two or more Terminal locations are not considered to be credible and will not be provided for in the design.

5.2.2.2

LNG Storage Tank Deluge System For the LNG storage tank deluge system demand, the maximum credible fire is due to a fire in an adjacent LNG storage tank. Coverage is provided for the surfaces of all tanks that may be exposed to radiant heat fluxes in excess of 9,500 Btu/hr/ft2. This is based on the concrete’s ability to withstand this heat flux. The deluge rate will provide 0.1 gpm/ft2 of firewater. The deluge rate is based on guidance from API2510A for tanks exposed to radiant heat assuming no flame contact.

5.2.3

Firewater System Components 5.2.3.1

Firewater Storage Tank The firewater storage tank shall be a suction tank at grade in accordance with NFPA 22. The working capacity of the tank will be sufficient to handle the maximum credible fire event demand for two hours. Make-up water will be obtained from the municipal water system.

Oregon LNG Warrenton, OR Hazard Detection and Mitigation Philosophy 5.2.3.2


Firewater Pumps The entire pump installation, including the Electric and Diesel Firewater Pumps, Firewater Jockey Pumps, drivers, controllers, piping, valves, fuel tanks, interconnecting wiring, etc. shall be in accordance with NFPA 20. The firewater system will be pressurized to 100 psig by means of the Firewater Jockey Pumps (2 x 100% ). T he Electric and Diesel Firewater Pumps will be arranged for automatic, sequential start upon a d ecrease in the pressure in the fire main. The first fire pump to operate will be the Electric Firewater Pump. If this pump fails to start, or if the header pressure continues to fall, the backup pump, the Diesel Firewater Pump, will automatically start. Each Firewater pump shall be sized to provide the demand capacities at the required residual pressures for each credible fire scenario. The design flow for each Firewater Jockey Pump shall be 250 gpm to provide system makeup under leakage conditions per NFPA 20. Sufficient fuel shall be provided for the diesel driven pump for 8 hours operation.

5.2.3.3

LNG Tank Deluge Firewater Pumps N+1 diesel-driven fire pumps will be provided dedicated to the tank deluge system. The pumps will be housed in a pump house on the Skipanon River which will be the source of water for the system. These pumps will be designed per NFPA 20 e xcept the operating pressure requirements shall be based on supplying water to the top of the LNG tanks and starting controls shall be based on LNG tank containment fire. Sufficient fuel shall be provided for the diesel driven pumps for 8 hours operation.

5.2.3.4

Firewater Piping A looped, underground firewater distribution network shall be provided around all areas of the Terminal in accordance with NFPA 24. The layout of the system shall provide a supply to each area from a minimum of two directions except for the pier and loading platform area, which will be supplied by a single firewater line. I solation gate valves (Post Indicating Valves) shall be provided to isolate sections of piping in the event of failures and still maintain the ability to supply firewater to each designated area. The distribution system shall be sized to deliver the design firewater demand to the most hydraulically remote location in the network at the demand's minimum residual (flowing) pressure. Aboveground piping shall deliver firewater to the pier and loading platform area via a pipe rack.



All piping shall be listed or approved for fire service. A bove ground piping (pier & berthing area) shall be welded carbon steel, with fused epoxy internal coating and seawater corrosion-resistant outer coating if piping is exposed to seawater. Post Indicator Valves (PIVs) shall be Resilient Type Gate Valves. Butterfly valves shall not be used. These valves shall be locked open so as not to require electrical supervision. A PIV shall be located at each branch connection and downstream of each branch connection as a minimum requirement per 33 CFR127.607. For the marine transfer area (loading platform), the fire main system must provide at least two water streams to each part of the LNG transfer piping and connections, one of which must be from a single length of hose (1-1/2 in. or greater hose of length no greater than 100 ft) or from a fire monitor per 33 CFR127.607. The hose shall be connected to the hydrant or standpipe and be on a reel or hose rack. The nozzle shall be Coast Guard approved combination solid stream and water spray nozzle. 5.2.3.5

Hydrants Fire hydrants shall be provided around the Terminal (process areas, pier and loading platform areas) in accordance with NFPA 24 and the OCIMF guidelines. Hydrants shall be spaced at not more than 150 f eet in Terminal process areas and loading platform areas and not more the 300 feet along the pier and Terminal roads. Three types of fire hydrants shall be provided: • 2-way fire hydrants with 2½" hose connections • 3-way fire hydrants (with one 3½" pumper connection and

two 2½" hose connections)

• 3-way monitor mounted fire hydrants with two 2½" hose

connections.

Hydrants located along the pier and roadways shall be 2-way type. Hydrants located in the LNG loading area, LNG tank storage area, and process areas shall be 2-way or 3-way types or 3 way monitor mounted types. Hydrants shall be red or some other conspicuous color in accordance with 33 CFR127.601 (this applies only to the unloading area but to maintain consistency throughout the Terminal, all shall be the same color).



Monitors Monitors shall be located as needed to provide cooling to equipment, vapor dispersion and thermal radiation exposure protection. Berthing area monitors, if provided, shall be tower elevated brass monitors, electrical or electro-hydraulic operated remote controlled type suitable for hazardous locations, each with a fog/straight stream nozzle. M onitor remote controls shall be located at least 50 ft from the probable fire location. Process areas shall be provided with monitors as n eeded to cool equipment and structures and support vapor dispersion. All monitors shall be remotely controlled to minimize local manual actions in areas with hazardous conditions. Monitor mounted hydrants shall be provided with brass monitor outlet attachments. Monitors shall be complete with a combination fog/straight stream brass nozzle. Capacity of monitors shall be based on r equired flows and reach for the cooling flow. In general, monitor selection is based on a 100 psig pressure and a narrow fog flow. Based on this, 500 gpm monitors are considered to have a reach of about 100 f t (with a capability to reach 170 f t with solid stream flow), and 1000 gpm monitors are considered to have a reach of about 150 f t (with a capability to reach 280 ft with solid stream flow). Monitors shall be red or some other conspicuous color in accordance with 33 CFR127.601 (this applies only to the unloading area but to maintain consistency throughout the Terminal, all shall be the same color).

5.2.3.7

Hose Reels and Hose Houses Outside hose houses with fire hose carts, nozzles, hydrant wrenches, spanners and other necessary equipment shall be provided strategically around the Terminal, storage, LNG berthing areas and along the pier in accordance with NFPA 24. Hose houses at hydrants will have hoses pre-connected to the hydrant. Hose reels and hose houses shall be red or some other conspicuous color in accordance with 33 CFR127.601 (this applies only to the unloading area but to maintain consistency throughout the Terminal, all shall be the same color).



Standpipe and Hose Systems Standpipe and hose systems may be provided for large buildings or buildings with large fire hazards with the potential of fast fire growth. D esign and installation shall be in accordance with NFPA 14. • Standpipes shall be semiautomatic-wet, Class I systems. • Piping shall be steel pipe per NFPA 14. • Indoor hose rack units shall be designed for Class I standpipe

in accordance with NFPA 14. Hose connection/ hose rack quantity and location will be determined in detailed engineering and will be in accordance with NFPA 14.

Standpipe and hose systems shall be red or some other conspicuous color in accordance with 33 CFR127.601 (this applies only to the unloading area but to maintain consistency throughout the Terminal, all shall be the same color). Based on c urrent Terminal design and layout no bui lding at is expected to have a standpipe. 5.2.3.9

International Ship to Shore Connection International ship to shore connections (ISCs) (2½" hose connections) complete with nuts and bolts shall be provided at the unloading platform for connection between the LNG carrier and the firewater supply. A minimum of four ISCs shall be provided. The ISCs shall be in accordance with ASTM F 1121 w ith sufficient 2-1/2 inch hose to connect to the carrier per 33 CFR127.611.

5.2.3.10

Firewater Connection for Fire Boats Ship to shore connection shall be provided where fire-fighting boats can hook up t o supplement the firewater supply line. The manifold shall be sized for the tugboat’s flow and firewater line size.

5.2.4

Sprinkler and Water Spray Systems 5.2.4.1

Automatic Sprinklers Automatic (either wet pipe or dry pipe) Sprinkler Systems shall be provided in non-process areas in accordance with NFPA 13 and local building codes. Sprinkler systems may also be provided in structures in process areas where water fire suppression is effective. Systems shall be hydraulically designed for the occupancy classification of the application.



Fixed Water Spray Systems Local water spray systems may be used for cooling storage and process vessels and equipment exposed to fires. Systems shall be designed per NFPA 15 and/or API 2510A. Systems may be automatically or manually activated in response to hazard detection.

5.2.4.3

LNG Tank Water Deluge System The Tank Water Deluge System will consist of spray ring headers for the roof and side walls of each tank. T hese rings will distribute the water over the tank outer surface for cooling when there is a fire in an adjacent tank. The application rate shall be 0.1 gpm/ft2 to ensure complete wetting of the surfaces considering rundown. Only those surfaces that may be exposed to heat fluxes in excess of 9,500 Btu/hr/ft2 will be protected. The deluge system will be supplied by the Deluge Firewater Pumps through deluge valves and the system normally operates dry from these valves to the tank distribution rings.

5.2.4.4

Water Supply for High Expansion Foam The fire main system shall supply water to the high expansion foam skids. The fire main shall be verified to meet the flow and pressure demands for firewater used in the high expansion foam systems, but the peak flow demand for the foam systems shall not be used to determine the fire main system maximum demand since the foam system operates intermittently based on need to maintain the foam blanket.

5.3

High Expansion Foam Systems High expansion foam systems will be provided at all LNG Spill Containment Basins to reduce the vaporization rate of LNG that is being contained, provide additional protection/vapor dispersion control (vapors traveling through the foam warm sufficiently to better disperse in the atmosphere), and to reduce the heat release rate of a basin fire, if ignited, by reducing the vaporization rate from the basin under fire conditions. The high expansion foam systems will consist of a foam concentrate storage tank, a proportioning device to mix the concentrate with water from the fire main, and foam generator(s) powered by a w ater-driven reaction motor to distribute the foam over the basin surface. T he foam concentrate will have an expansion ratio of at least 500:1. The system will be activated automatically by detection of spills within the basins or manually by technicians as required. T he foam generator is designed to withstand high temperatures and will be of a design proven for LNG service. Foam



fences will also be employed around the basins to minimize the loss of foam as a result of wind. The foam system will provide at least 1 foot deep coverage over the basin area within 30 s econds of system actuation and 5 ft deep coverage over the basin area within one minute of activation. System capacity will be sufficient to maintain this foam blanket for a 24 hour period by periodically adding more foam. 5.3.1

Foam System Basis of Design The Hi-Ex foam system will be designed in accordance with NFPA 11 and be UL listed or FM approved. The design will further be proven for LNG service. System capacity will be based on an initial foam discharge rate of 6 CFM/ft2 and on maintaining a depth of 5 ft. The discharge rate and foam depth are based on LNG spill testing where the 6 CFM/ft2 rate resulted in total foam coverage within 30 seconds of system actuation. The 5 ft depth was selected to provide margin over testing that showed 3 feet was sufficient to significantly reduce downwind gas concentrations. T hese values were based on the assumption that the system response time is less than 30 seconds. The 5 ft depth provides additional conservatism for the Terminal since the basins are insulated, resulting in lower LNG boil-off rates, which in turn has been shown to provide additional protection time per foot of foam. ( See “Considerations Relating to Fire Protection Requirements for LNG Plants (75-T-47)” by H. R. Wesson, Operating Section Proceedings, American Gas Association, Los Angeles, CA May 57, 1975, pp. T-121 - T-136.) System capacity to maintain a 5 ft depth of foam for 24 hours for the LNG Spill Containment Basin will be conservatively selected to provide sufficient time to disperse the LNG vapors in a controlled and safe manner. This capacity also provides margin to account for wind-driven or rain-driven foam depth loss. The Hi-Ex foam system shall be used for local application, where the foam is discharged directly onto the fire or LNG spill. T he system shall consist of fixed foam generating apparatus complete with a piped supply of foam concentrate and water that is arranged to discharge foam directly onto a fire or spill hazard. For the sizing of the system, the cubic area of risk to be protected, available residual water flow and pressure and method of proportioning (i.e., Balanced Pressure and In-line Balanced Pressure) shall be taken into consideration. The foam generator shall be powered by a water reaction motor. It shall be suitable for use with fresh water and salt water. The Hi-ex foam shall be stable, long-lasting, with uniform bubble structure.



The units shall be easy to install. The foam system shall have foam outlets arranged to supply foam to cover the design fire area within the specified time. Foam solution piping and discharge nozzle shall be of open design allowing passage of particles up t o 1/4" in diameter without use of a strainer. Inlet gauge tap for system testing shall be provided. The Hi-Ex foam system shall be compatible with standard proportioning equipment. Since potassium bicarbonate dry chemical agents will also be used, the dry chemical and foam agents need to be compatible. The foam generating equipment shall be capable of operating in a high temperature environment without distorting or buckling. 5.4

Nitrogen Purge System A Nitrogen gas sweep will be applied to the Terminal’s flare. A small amount of continuous purge flow will be sent to the Flare to prevent air from entering the stack and piping system during periods of no or low methane release rates.

6

MOBILE FIRE FIGHTING AND SAFETY EQUIPMENT Provisions for automotive and mobile fire fighting and safety equipment will be determined. Fire-fighting tug boats may be provided on a stand-by basis during off-loading periods for additional fire protection at the marine berth. 6.1

Portable Fire Extinguishers Portable fire extinguishers will be located throughout the Terminal in accordance with NFPA 59A-2001. T ype, quantity and mounting will be in accordance with NFPA 10. 20-lb tri-class dry chemical (ABC) portable fire extinguishers, complete with mounting brackets/cabinets, will be installed inside selected buildings and spaced in accordance with NFPA 10. These shall be applied to primarily Class A and Class C fires. Where combustible gas, LNG, or refrigerant fires may occur, Purple-K dry chemical (BC) portable fire extinguishers, complete with mounting brackets/cabinets, shall be



provided around the Terminal, including the marine berth, based on the local hazard level with spacing in accordance with NFPA 10 and the fire safety evaluation. 30-lb hand-held extinguishers shall be provided near locations of potential gas fires. Where larger gas fires are possible, wheeled 150-lb or 300-lb extinguishers shall be provided, for example at the marine berth. 20-lb CO2 extinguishers, complete with wall mounting brackets/cabinets, will be provided in the Main Control Room, Platform Control Room, electrical and power substations, MCC rooms, switchgear rooms, and other rooms/buildings where electrical hazards are present. Extinguishers will have corrosion resistant painting and be supplied with a weather resistant cover or cabinet if located outdoors. If provided, automotive and trailer-mounted fire apparatus shall not be used for any other purpose. Automotive vehicles assigned to the Terminal shall be provided with a minimum of one portable dry chemical (Purple-K) extinguisher having a capacity of not less than 18 lb. 6.2

Personnel Protective Equipment Personnel protective equipment (PPE) will be provided throughout the Terminal. PPE will include items such as flame resistant personal clothing, hard hats, safety footwear, safety harnesses, hearing protection, gloves, goggles/face shields, and aprons. In accordance with NFPA 59A-2001, protective clothing that provides protection against the effects of exposure to LNG shall be available and readily accessible at the Terminal. At least three portable flammable gas indicators shall be readily available. At least two portable gas detectors with a r ange of 0-100% LFL shall be provided in the marine transfer area per 33 CFR127.20. Portable gas detectors for carbon dioxide and hydrogen sulfide shall be available for personnel working around the amine stripper and reflux drum in the gas pretreatment system. Protective clothing and respirators that provide protection against the effects of exposure to ammonia shall be available and readily accessible at the Terminal.

7

FIRE BRIGADE Oregon LNG will not have an on-site fire brigade. Personnel will be trained on the use of portable extinguishers and 1 1/2" hose lines to attack incipient fires. The local municipal fire department will provide the manual fire fighting capability.


8


FIRE PREVENTION PLAN The Terminal personnel are the primary responders to a hazard condition on s ite. T he operators will establish communications with the designated fire department(s) and Coast Guard on a regular basis in accordance with the Emergency Response Plan to review fire plans, perform site inspections, provide training and joint drills, and other activities to better coordinate responses during potential hazard events. H azard alarms will be communicated to the designated fire department(s) for support and will be further described in the Emergency Response Plan. An Emergency Response Plan will include the following policies, procedures and practices for providing fire protection: •

The fire protection organization and their responsibilities.

•

Control of hot work.

•

Control of transient combustibles.

•

Confined space/hazardous space entry.

•

Fire brigade training, including drills.

•

Fire protection equipment maintenance and testing.

•

Pre-fire planning.

•

General housekeeping and inspections for hazardous conditions.

•

Coordination with the designated fire department(s) and Coast Guard.


C.4 Rainfall Design Basis


Oregon LNG Warrenton, OR Rainfall Design Basis

Job No. 07902 Doc No. 07902-CA-900-301, Rev: 1 Page 1 of 7

RAINFALL DESIGN BASIS By H H C H H

REV NUMBER: ISSUE PURPOSE: DATE: BY: CHECKED: APPROVED:


0 1 Issued for Include Client Review Liquefaction 10/08/2007 1/26/2012 RCT ABR DAA AAR AAR AAR



1

Purpose

3

2

Summary of Results

3

3

Background

3

4

Calculation

4

4.1

Calculation of 10-Year, 1-Hour Rainfall

4

4.2

Calculation of Design Rainfall for Non-Process Areas

6

4.3

Calculation of Equivalent Continuous Rainfall for Site

7

5

References

7


1


PURPOSE The purpose of this calculation is to document the rainfall rates for the Oregon LNG Terminal. This information will be used for design of systems at the site for handling storm water.

2

SUMMARY OF RESULTS The following values for rainfall shall be used for the Oregon LNG terminal:

3

Parameter

Event

Design Rainfall

Impoundment Water Removal Rainfall Design Basis

10-year, 1-hour storm

0.9 inches per hour

Non-process Area Rainfall Design Basis

Bounding hourly rainfall

0.6 inches per hour

Equivalent Continuous Rainfall for Site

Average During Typical Wet Month

0.016 inches per hour

BACKGROUND Requirements for water removal systems from LNG impoundment areas are set forth in the Federal Safety Standards listed in 49CFR193. Specifically, Section 193.2173 of 49CFR193 states: (a) Impoundment areas must be constructed such that all areas drain completely to prevent water collection. Drainage pumps and piping must be provided to remove water from collecting in the impoundment area. Alternative means of draining may be acceptable subject to the Administrator's approval. (b) The water removal system must have adequate capacity to remove water at a rate equal to 25% of the maximum predictable collection rate from a storm of 10-year frequency and 1-hour duration, and other natural causes. For rainfall amounts, operators must use the ``Rainfall Frequency Atlas of the United States'' published by the National Weather Service of the U.S. Department of Commerce. This calculation documents the rainfall occurring during a storm of 10-year frequency and 1-hour duration for use in sizing the water removal system for the site impoundment.



Requirements for water removal systems from process area impoundment areas and impoundment areas surrounding flammable refrigerant liquid storage tanks are set forth in NFPA 59A- 2001 Edition. The requirements for water removal systems for these impoundments are the same as for those in 49CFR193.2173 for LNG impoundment areas. In addition, this calculation documents the rainfall to be considered in design of other parts of the terminal not specified by the above federal safety standard or NFPA 59A.

4

CALCULATION 4.1

Calculation of 10-Year, 1-Hour Rainfall As stated above in Section 3, 49CFR193.2173 requires use of the Rainfall Frequency Atlas of the United States as the source for rainfall amounts. The current version of this information for Oregon can be obtained from the following website: http://www.weather.gov/oh/hdsc/currentpf.htm#N2 Specifically, Volume X of NOAA Atlas 2, entitled Precipitation-Frequency Atlas of the Western United States, contains information for Oregon. For Oregon, NOAA provides a methodology for calculating the 10-year, 1-hour storm using interpolation from data for a 2-year storm and a 100-year storm. The equations vary by region of the state. The Oregon LNG Import Terminal is located near Astoria, Oregon, which is in Region 3 (Coastal Plains). The equations to be used for calculating the 2-year and 100-year rainfall data for this region are listed in Table 12 of Volume X as follows: Y2 = 0.157 + 0.513*X1*(X1/X2)

Equation (1)

Y100 = 0.324 + 0.118*(X3/X1) + 0.386*X1*(X3/X2)

Equation (2)

Where: Y2 = the estimated rainfall for a 2-year, 1-hour storm Y100 = the estimated rainfall for a 100-year, 1-hour storm X1 = the 2-year, 6-hour estimated rainfall value X2 = the 2-year, 24-hour estimated rainfall value X3 = the 100-year, 6-hour estimated rainfall value



All of the X values are read from precipitation frequency (isopluvial) maps provided in Volume X. Figure 4.1-1 below presents excerpts of the relevant maps the sections of each map:

From Volume X, Figure 19: 2-yr 6-hr

From Volume X, Figure 25: 2-yr 24-hr

From Volume X, Figure 24: 100-yr 6 hr

Figure 4.1-1. Isopluvial Maps for Astoria, Oregon

Note: The information in the above figure is presented in units of tenths of an inch of precipitation. From these figures, X1 = 1.8 inches, X2 = 3.5 inches and X3 = 3.5 inches. Using these values of X, Equations (1) and (2) yield the following values: Y2 = 0.157 + 0.513*1.8*(1.8/3.5) = 0.63" Y100 = 0.324 + 0.118*(3.5/1.8) + 0.386*1.8*(3.5/3.5) = 1.25" Per Volume X, the rainfall for periods other than 2-years and 100-years can be determined by plotting the 2-year, 1-hour and 100-year, 1-hour points on the nomograph in Figure 6 of Volume X, and drawing a straight line between the two points, as shown below in Figure 4.1-2:



Figure 4.1-2. Precipitation Depth versus Return Period

The 10-year, 1-hour rainfall is represented where the line intersects with the 10-year line. This value is approximately 0.9 inches. 4.2

Calculation of Design Rainfall for Non-Process Areas The table below summarizes the rainfall listed in the Volume X isopluvials for the Astoria region: Table 4.2-1. Precipitation, Monthly and Annual Averages (1971-2000) Volume X Figure

Frequency (years)

Duration (hours)

Intensity (tenths of inches)

Inches per Hour

19

2

6

18

0.30

20

5

6

22

0.37

21

10

6

26

0.43

22

25

6

30

0.50

23

50

6

35

0.58

24

100

6

35

0.58

25

2

24

35

0.15

26

5

24

45

0.19

27

10

24

50

0.21

28

25

24

55

0.23

29

50

24

60

0.25

30

100

24

65

0.27



From the data above, limiting average rainfall rate is about 0.6 inches per hour. This value can be used for design storm water flow. 4.3

Calculation of Equivalent Continuous Rainfall for Site The table below provides the average monthly rainfall in the vicinity of the site. This information was obtained from Reference 3. Table 4.3-1 Precipitation, Monthly and Annual Averages (inches), 1971-2000

Location

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Annual

Astoria Airport

9.62

7.87

7.37

4.93

3.28

2.57

1.16

1.21

2.61

5.61

10.50

10.40

67.13

Seaside

10.27

9.57

8.44

5.74

3.96

3.00

1.63

1.34

3.00

6.07

11.38

11.34

75.74

The month with the most average rainfall is November, with 11.38 inches. On a continuous basis, this is equivalent to an hourly rainfall of about 0.016 inches. This rate shall be used for the equivalent continuous rainfall rate for the site.

5

REFERENCES 1. Title 49, Part 193: Liquefied Natural Gas Facilities: Federal Safety Standards, revised October 1, 2005. 2. NOAA Atlas 2, Precipitation-Frequency Atlas of the Western United States, Volume X – Oregon, 1973. 3. http://www.ocs.orst.edu/county_climate/Clatsop_files/Clatsop.html.


C.5 Seismic Design Basis


Report

Seismic and Structural Design Criteria for Equipment and Structures, Oregon LNG Bidirectional Terminal

Prepared for

LNG Development Company, LLC (d/b/a Oregon LNG)

June 2012

Prepared by

Contents 1.0 Introduction....................................................................................................................... 1-1 2.0 Structural Design Criteria............................................................................................... 2-1 2.1 References and Design Codes ................................................................................. 2-1 2.2 Design Loads and Load Combinations .................................................................. 2-1 3.0 Structural Materials........................................................................................................... 3-1 Appendix A Specification for Seismic Anchorage and Bracing

i

SECTION 1.0

Introduction This report describes seismic and structural design criteria, including codes and standards, that will be used for design of all equipment and structures, except for the LNG storage tanks, at the Oregon LNG Bidirectional Terminal. For seismic and structural design criteria to be used for the LNG storage tanks, refer to the LNG Storage Tank and Foundation Specification in Appendix L.1 of Resource Report 13. Also, seismic and structural design criteria for the Marine Facilities are not covered by this report; see Marine Facilities Design Criteria in Appendix C.6 of Resource Report 13. As currently planned, the only structures or equipment that will incorporate damping devices (for seismic isolation) into the foundation design will be the LNG Storage Tanks. Therefore, seismic criteria (such as damping values, damping reduction factors, ductility or inelastic reduction factors) that are used for design of damping devices are not described herein. Where applicable, these criteria are described in the LNG Storage Tank and Foundation Specification. For specifications regarding anchoring and bracing requirements for equipment, refer to the Seismic Anchorage and Bracing specification provided in Appendix A.

1-1

SECTION 2.0

Structural Design Criteria The loads, load combinations, materials and analysis requirements to be used for the structural design of the various elements of the facility, excluding the LNG storage tanks and the offshore docking facility, are discussed below.

2.1

References and Design Codes

1. 2006 International Building Code (IBC), International Code Council 2. American Society of Civil Engineers, Minimum Design Loads for Buildings and Other Structures, ASCE 7-05 3. Draft FERC Seismic Design Guidelines and Data Submittal Requirements for LNG Facilities (draft FERC guidelines), January 23, 2007 4. Seismic Categorization, Oregon LNG Import Terminal, prepared by CH IV International, March 17, 2008 5. AISC Manual for Steel Construction Manual, Thirteenth Edition, 2005, American Institute of Steel Construction 6. American Welding Society, Structural Welding Code – Steel, AWS D1.1 7. ACI 318 Building Code and Commentary 8. American Society of Civil Engineers, Seismic Analysis of Safety Related Nuclear Structures and Commentary, ASCE 4-98 9. 2007 Oregon Structural Specialty Code, International Code Council

2.2

Design Loads and Load Combinations

All structures will be designed using the following general loading criteria and load combinations, unless stated otherwise.

2.2.1

Dead Loads

Dead loads consist of the weight of the concrete, metal, and fixed equipment. Material weights are as indicated in Table 2-1. TABLE 2-1

Material Unit Weights Unit Weight (pounds per cubic foot)

Material Steel

490

Reinforced concrete

150

2-1

SECTION 2.0 STRUCTURAL DESIGN CRITERIA

2.2.2

Live Loads

Table 2-2 lists the live loads that will be used for design. TABLE 2-2

Live Loads Feature

Uniform or Linear Load

Concentrated Load

Snow Loads

25 psf

NA

Deck

200 psf

2,000 pounds

Platforms and Grating

100 psf

300 pounds

Stairway

100 psf

300 pounds

Guardrail

50 plf

200 pounds

psf = pounds per square foot. NA = not applicable. plf = pounds per lineal foot

2.2.3

Wind Load

The facility will be designed for wind loads using IBC 2006 minimum loads. The following parameters will be used for design: • • • •

Basic Wind Speed (3-second gust): 150 mph for LNG storage tanks per 49 CFR 193.2067; 100 mph for other process equipment and buildings in accordance with ASCE 7-05. Exposure Category: D Importance Factor: Iw = 1.15 (Occupancy Category IV, IBC 2006 Table 1604.5 and ASCE 7-05, Table 6-1) Importance Factor: Iw = 1.00 (Occupancy Category II, IBC 2006 Table 1604.5 and ASCE 7-05, Table 6-1)

2.2.4

Seismic Criteria

The facility will be designed using IBC 2006 seismic design criteria, with FERC Seismic Categories (References 3 and 4). Structures, components and systems integral to the operation of the facility have been classified into FERC Seismic Category I, II or III (see Reference 4). •

Seismic Category I includes the (1) LNG storage containers and their impounding systems; (2) System components required to isolate the LNG container and maintain it in a safe shutdown condition; (3) Structures and systems, including fire protection systems, the failure of which could affect the integrity of (1) or (2).

•

Seismic Category II includes components and systems not included in Seismic Category I that are required to maintain safe plant operations.

•

Seismic Category III includes other structures, components and systems of the LNG facility that are not included in Seismic Categories I and II.

2-2

STRUCTURAL DESIGN CRITERIA

These Seismic Categories shall be taken as equivalent to IBC’s Occupancy Category IV for FERC Seismic Categories I and II; and IBC’s Occupancy Category II for FERC Seismic Category III.

FERC Seismic Category I Seismic parameters for FERC Seismic Category I structures, components, and systems are presented below. A detailed discussion on design response spectra is presented in SiteSpecific Seismic Hazard Evaluation for the Oregon LNG Terminal Project, Appendix I.1 of Resource Report 13. •

Short Period Safe Shutdown Earthquake (SSE) Spectral Response Acceleration, 5 Percent Damped: SMS equals 1.10g

•

1 Second Period Safe Shutdown Earthquake (SSE) Spectral Response Acceleration, 5 Percent Damped: SM1 equals 0.84g

•

Short Period Operating Basis Earthquake (OBE) Spectral Response Acceleration, 5 Percent Damped: SDS equals 0.64g

•

1 Second Period Operating Basis Earthquake (OBE) Spectral Response Acceleration, 5 Percent Damped: SD1 equals 0.39g

•

Occupancy Category: Occupancy Category IV

•

Structure Importance Factor: I = 1.5

•

Component Importance Factor: Ip = 1.5

•

Site Class D; Seismic Design Category D

FERC Seismic Category II, Except Offshore Docking Facility Seismic parameters for FERC Seismic Category II structures, components, and systems are presented below. A detailed discussion on design response spectra is presented in SiteSpecific Seismic Hazard Evaluation for the Oregon LNG Terminal Project, Appendix I.1 to Resource Report 13. •

Short Period Site-Specific Maximum Considered Earthquake (MCE) Spectral Response Acceleration, 5 Percent Damped: SMS equals 1.10g

•

1 Second Period Site-Specific Maximum Considered Earthquake (MCE) Spectral Response Acceleration, 5 Percent Damped: SM1 equals 0.84g

•

Short Period Site-Specific Design Earthquake Spectral Response Acceleration, 5 Percent Damped: SDS equals 0.73g

•

1 Second Period Site-Specific Design Earthquake Spectral Response Acceleration, 5 Percent Damped: SD1 equals 0.56g

•

Occupancy Category: Occupancy Category IV

•


•


•

Site Class D, Seismic Design Category D 2-3

SECTION 2.0 STRUCTURAL DESIGN CRITERIA

FERC Seismic Category III Seismic parameters for FERC Seismic Category III structures, components, and systems are presented below. A detailed discussion on design response spectra is presented in SiteSpecific Seismic Hazard Evaluation for the Oregon LNG Terminal Project, Appendix I.1 to Resource Report 13. •

Short Period Site-Specific Maximum Considered Earthquake (MCE) Spectral Response Acceleration, 5 Percent Damped: SMS equals 1.10g

•

1 Second Period Site-Specific Maximum Considered Earthquake (MCE) Spectral Response Acceleration, 5 Percent Damped: SM1 equals 0.84g

•

Short Period Site-Specific Design Earthquake Spectral Response Acceleration, 5 Percent Damped: SDS equals 0.73g

•

1 Second Period Site-Specific Design Earthquake Spectral Response Acceleration, 5 Percent Damped: SD1 equals 0.56g

•

Occupancy Category: Occupancy Category II

•


•


•

Site Class D, Seismic Design Category D

2.2.5

Loading Combinations

Loads will be combined as listed below. Load Case

Loads

Load Combination (Allowable Stress Design)

1

Dead D Fluids F

D+F

2

Dead D Earth Pressure H Fluid F Live L

D+H+F+L

3

Dead D Earth Pressure H Fluid F Roof Live Load Lr Snow S

D + H + F + (Lr or S)

4

Dead D Earth Pressure H Fluid F Live L Roof Live Load Lr Snow S

D + H + F + 0.75L + 0.75(Lr or S)

5

Dead D Earth Pressure H Fluid F Wind W Seismic E

D +H + F + (W or 0.7E)

2-4

STRUCTURAL DESIGN CRITERIA

Load Case

Loads

Load Combination (Allowable Stress Design)

6

Dead D Earth Pressure H Fluid F Live L Roof Live Load Lr Snow S

D + H + F + 0.75(W or 0.7E) + 0.75*L + 0.75(Lr or S)

7

Dead D Earth Pressure H Wind W

0.6D + W + H

8

Dead D Earth Pressure H Seismic E

0.6D + 0.7E + H

2.3

Seismic Certification and Qualification of Seismic Category I and II Mechanical and Electrical Equipment

All Seismic Category I and II mechanical and electrical equipment will be certified by their supplier to satisfy the seismic qualification requirements of Section 1708.5 of the 2006 IBC and Section 13.2 of ASCE 7-05.

2.4

Seismic Displacements for Category I, II, and III Piping, Utility, and Electrical Lines

The Seismic Category I, II, and III piping, utility, and electrical lines crossing the seismic isolation interface of the LNG tanks are required to accommodate the maximum isolation displacement, in addition to other design loadings. The maximum horizontal isolation displacement that needs to be accommodated is 36 inches in any direction and a vertical isolation upward displacement of 4 inches. In addition, piping, utility, and electrical lines that span between the LNG tanks and adjacent structures need to accommodate an additional 3 and 4 inches of vertical relative settlement for Seismic Category II and III, respectively, because of seismically induced foundation movements.

2-5

SECTION 3.0

Structural Materials The material properties of structural materials anticipated for use at the Oregon LNG Bidirectional Terminal are summarized in Table 3-1.

3.1

Concrete Structures

Design of concrete structures will be in accordance with ACI 318. Concrete cover over reinforcing steel will be as shown in Section 7.7 of ACI 318.

3.2

Steel Structures

Steel structures will be designed using the Allowable Stress Design (ASD) method in accordance with the AISC Manual of Steel Construction. Bolted connections will be highstrength, ASTM A325 galvanized bolts. Welding will be in accordance with AWS requirements. TABLE 3-1

Structural Materials and Properties Material

Property

Cast-in-Place Concrete

F’c = 4,000 psi at 28 days

Reinforcing Steel

ASTM A615, Grade 60, Fy = 60 ksi

Structural Steel Steel Plates, Shapes except W-shapes, and Bars

ASTM A572 Gr. 50, Fy = 50 ksi or ASTM A36, Fy = 36 ksi

W-shapes

ASTM A992, Fy = 50 ksi

Rectangular (and Square) Hollow Structural Sections (HSS)

ASTM A500 Grade B, Fy = 46 ksi

Round Hollow Structural Sections (HSS)

ASTM A500 Grade B, Fy = 42 ksi

Steel Pipe

ASTM A53, Grade B, Type E or S

Stainless Steel Bars, Angles & Shapes

ASTM A276, AISI Type 304L, Fy = 25 ksi

Plate

ASTM A240, AISI Type 316L, Fy = 25 ksi

Bolts and Rods Steel Bolts

ASTM A325, Type 1 bolts with A563 nuts

Anchor Rods

ASTM F1554, Grades 36, 55, and 105 (hooked, headed, or threaded and nutted) as appropriate for application or ASTM A36 (threaded rods either plain or upset ends).

Stainless Steel Bolts

ASTM F593, AISI Type 304, Condition CW

Concrete Adhesive Anchors

Stainless Steel Hilti HY-150 or RE-500

Grating

Galvanized Steel or Aluminum

3-1

Appendix A Specification for Seismic Anchorage and Bracing

OREGON LNG TERMINAL RESOURCE REPORT 13, APPENDIX T.5

355036A

SECTION 01 88 15 SEISMIC ANCHORAGE AND BRACING PART 1 1.01

GENERAL SECTION INCLUDES A.

1.02

This section covers requirements for seismic anchorage and bracing for equipment and nonstructural components required in accordance with the International Building Code (IBC).

REFERENCES A.

The following is a list of standards which may be referenced in this section: 1. American Institute of Steel Construction (AISC). 2. American Society of Civil Engineers (ASCE): ASCE 7-05, Minimum Design Loads for Buildings and Other Structures. 3. Federal Energy Regulatory Commission (FERC): Draft Seismic Design Guidelines and Data Submittal Requirements for LNG Facilities, January 23, 2007. 4. International Code Council (ICC): International Building Code (IBC). 5. International Code Council (ICC): Oregon Structural Specialty Code 6. Sheet Metal and Air Conditioning Contractors’ National Association (SMACNA): Seismic Restraint Manual: Guidelines for Mechanical Systems.

1.03

DESIGN AND PERFORMANCE REQUIREMENTS A.

1.04

General: Contractor shall be responsible for designing code required seismic attachments, braces, and anchors to the structure for elements of the architectural, mechanical, and electrical systems included in the Work in accordance with this section unless a design is specifically provided within the Contract Documents.

DESIGN REQUIREMENTS: 1. In accordance with 2006 IBC, Section 1613, and Chapter 13 of ASCE 7-05. 2. Architectural, mechanical, electrical and other nonstructural systems, components, and elements permanently attached to the structure shall be designed to transfer the component seismic forces specified in ASCE 7-05, Section 13.3.1 to the structure.

MAY 31, 2012 ©COPYRIGHT 2012 CH2M HILL

SEISMIC ANCHORAGE AND BRACING 01 88 15 - 1 REVISION 2

355036A

OREGON LNG TERMINAL RESOURCE REPORT 13, APPENDIX T.5 3. Design forces for anchors in concrete or masonry shall be in accordance with ASCE 7-05, Section 13.4.2. 4. Seismic anchorage and bracing systems shall be designed by a qualified professional engineer registered in the State of Oregon. 5. Nonstructural Components: Design as nonbuilding structures for components with weights greater than or equal to 25 percent of the effective seismic weight of the overall structure. 6. Architectural Components: Includes, but are not limited to, nonstructural walls and elements, partitions, cladding and veneer, access flooring, signs, cabinets, suspended ceilings, and glass in glazed curtain walls and partitions. 7. Design seismic attachments, braces, and anchorages for parts or elements of the architectural, mechanical, and electrical systems in accordance with the provisions of the International Building Code and the following site-specific seismic criteria, unless noted otherwise on the Drawings. a. Site-Specific Spectral Response Coefficients for Seismic Category I: 1) Short Period Safe Shutdown Earthquake (SSE) Spectral Response Acceleration, 5 Percent Damped: SMS equals 1.1g. 2) 1 Second Period Safe Shutdown Earthquake (SSE) Spectral Response Acceleration, 5 Percent Damped: SM1 equals 0.84g. 3) Short Period Operating Basis Earthquake (OBE) Spectral Response Acceleration, 5 Percent Damped: SDS equals 0.64g. 4) 1 Second Period Operating Basis Earthquake (OBE) Spectral Response Acceleration, 5 Percent Damped: SD1 equals 0.39g. b. Site-Specific Spectral Response Coefficients for Seismic Category II and III: 1) Short Period Mapped Maximum Considered Earthquake, 5 Percent Damped: SSM equals 1.1g. 2) 1 Second Period Mapped Maximum Considered Earthquake, 5 Percent Damped: SM1 equals 0.84g. 3) Short Period Design Spectral Response Acceleration, 5 Percent Damped: SDS equals 0.73g. 4) 1 Second Period Design Spectral Response Acceleration, 5 Percent Damped: SD1 equals 0.56g. 8. Site Class: D. 9. Seismic Design Category (SDC): D, unless noted otherwise. Same as supporting structure’s SDC, as shown on Drawings.




355036A

10.Occupancy Category: Varies, see Drawings. The anchorage and bracing Occupancy Category shall be the same as that for supporting structure as shown on Drawings. a. Note that FERC guidelines (Reference 3) categorize facilities according to FERC Seismic Category I, II or III. These Seismic Categories shall be taken as equivalent to Occupancy Category IV for FERC Seismic Categories I and II; and Occupancy Category II for FERC Seismic Category III. 11.Analyze local region of body of nonstructural component for load transfer of anchorage attachment if component Ip = 1.5. 12.Component Important Factor: a. Ip = 1.0, unless noted otherwise. b. Ip shall be taken as 1.5 for components needed for or whose failure could impair continued operation of hazardous or essential facilities. c. Ip shall be taken as 1.5 for components that contain hazardous materials or that are required for life safety to be functional after a seismic event. d. Refer to Section 01 45 33, Special Inspection, Observation, and Testing, for list of designated components which Ip equals 1.5. 13.Seismic Displacement for Seismic Category I, II, and III Piping, Utility, and Electrical Lines: All Seismic Category I, II, and III piping, utility, and electrical lines crossing the seismic isolation interface of the LNG tanks are required to accommodate the maximum isolation displacement. The maximum horizontal isolation displacement that needs to be accommodated is 36 inches in any direction and a vertical isolation upward displacement of 4 inches. In addition, piping, utility and electrical lines which span between the LNG tanks and adjacent structures need to accommodate an additional 3 and 4 inches of vertical relative settlement for Seismic Category II and III, respectively, because of seismically induced foundation movement. B.

In accordance with ASCE 7-05, the following are exempt from the requirements of the section for provision of seismic anchorages and bracing, in addition to those items specifically exempted in ASCE 7-05, Part 13.5 for architectural components and Part 13.6 for electrical and mechanical equipment: 1. Architectural components with Ip equals 1.0, other than parapets supported by bearing walls or shear walls. 2. Mechanical and electrical components. 3. Mechanical and electrical components with Ip equals 1.0. 4. Mechanical and electrical components with Ip equals 1.0 that weigh 400 pounds or less and are mounted 4 feet or less above adjacent



355036A

OREGON LNG TERMINAL RESOURCE REPORT 13, APPENDIX T.5 finished floor elevation, or are provided with flexible connections between the components and associated ductwork, piping, or conduit. 5. Mechanical and electrical components with Ip equals 1.0 that weigh 20 pounds or less, are mounted at any height, and are provided with flexible connections to attached ductwork, piping, and conduit. 6. Distribution systems with Ip equals 1.0 weighing 5 pounds per foot or less.

C.

Support drawings and calculations for electrical distribution components shall be provided if any of the following conditions apply: 1. Ip is equal to 1.5 and conduit diameter is greater than 2.5-inch trade size. 2. Ip is equal to 1.5 and the total weight of bus duct, cable tray, or conduit supported by trapeze assemblies exceeds 10 pounds per foot. 3. Supports are cantilevered up from floor. 4. Supports include bracing to limit deflection and are constructed as rigid welded frames. 5. Attachments utilize spot welds, plug welds, or minimum size welds as defined by AISC.

D.

1.05

Other seismic design and detailing requirements identified in ASCE 7-05, Chapter 13, are required to be provided for new architectural, mechanical and electrical component, system, or equipment.

SUBMITTALS A.

Action Submittals: 1. Shop Drawings: a. Submit shop drawings with supporting calculations no less than 4 weeks in advance of installation of component, equipment or distribution system to be anchored to structure. b. Submitted anchorage drawings and calculations are identified as IBC deferred submittals and will be submitted to and accepted by permitting agency prior to installation of component, equipment or distribution system. c. List of architectural, mechanical, and electrical equipment weighing more than 20 pounds, and electrical, piping, and mechanical distribution systems weighing more than 5 pounds per foot shall be anchored, unless specifically exempted hereinafter. d. Manufacturers’ engineered seismic hardware product data. e. Seismic attachment assemblies’ drawing; include connection hardware, braces, and anchors or anchor bolts for nonexempt components, equipment, and systems.



OREGON LNG TERMINAL RESOURCE REPORT 13, APPENDIX T.5 f.

B.

355036A

Submittals will be rejected if proposed anchorage method would create an overstressed condition of supporting member. Revise anchorages and strengthening of structural support so there is no overstressed condition.

Informational Submittals: 1. Seismic Anchorage and Bracing Calculations: For seismic attachments, braces, and anchorages. Include IBC and project specific criteria as noted on General Structural Note Sheets on Drawing, in addition to manufacturer’s specific criteria used for the design; sealed by a civil or structural engineer registered in the State of Oregon. 2. Manufacturer’s seismic hardware installation requirements.

PART 2 2.01

PRODUCTS GENERAL A.

Attachments and supports transferring seismic loads to structure shall be constructed of materials and products suitable for the application and be designed and constructed in accordance with the design criteria shown on Drawings and nationally recognized standards.

B.

In accordance with Section 05 50 00, Metal Fabrications. Source quality control shall be in accordance with the referenced section.

C.

Provide anchor bolts, and concrete and masonry anchors for anchorage of equipment in concrete or masonry in accordance with Section 05 50 00, Metal Fabrications. Size of anchor bolts and anchors, and required minimum embedment and spacing shall be based on calculations submitted by Contractor.

D.

Powder actuated fasteners and sleeve anchors shall not be used for seismic attachments and anchorage where resistance to tension loads is required. Expansion anchors, other than undercut anchors, shall not be used for nonvibration isolated mechanical equipment rated over 10 hp.

PART 3 3.01

EXECUTION GENERAL A.

Make seismic attachments, bracing, and anchorage in such a manner that component seismic force is transferred to the lateral force resisting system of the structure through a complete load path.



355036A

3.02

3.03


B.

Overall seismic anchorage system shall provide restraint in all directions, including vertical, for each component or system so anchored.

C.

Components mounted on vibration isolation systems shall have snubbers in each horizontal direction and vertical restraints where required to resist overturning.

D.

Anchor piping in such a manner as to ensure piping system has adequate flexibility and expansion capabilities at flexible connections and expansion joints. Piping and ductwork suspended more than 12 inches below the supporting structure shall be braced for seismic effects to avoid significant bending of the hangers and their attachments.

E.

Tall and narrow equipment such as motor control centers and telemetry equipment shall be anchored at the base and within 12 inches from the top of the equipment, unless approved otherwise by Engineer.

F.

Architectural, mechanical, or electrical components shall not be attached to more than one element of a building structure at a single restraint location where such elements may respond differently during a seismic event. Such attachments shall also not be made across building expansion and contraction joints.

INSTALLATION A.

Do not install components or their seismic anchorages or restraints prior to review and acceptance by Engineer and permitting agency.

B.

Notify Engineer upon completion of seismic restraints in accordance with Section 01 45 33, Special Inspection, Observation, and Testing.

FIELD QUALITY CONTROL A.

Field Quality Control shall be in accordance with Section 05 50 00, Metal Fabrications. END OF SECTION




C.6 Marine Facilities Design Basis


Final Report

Marine Facilities Design Criteria, Oregon LNG Terminal

Prepared for

LNG Development Company, LLC (d/b/a Oregon LNG)

January 2008 Revised October 2008

Prepared by

Contents 1.0 Introduction..........................................................................................................................1 2.0 Structural Loading...............................................................................................................1 2.1 Dead Loads .................................................................................................................1 2.2 Live Loads...................................................................................................................1 2.3 Earthquake Loads ......................................................................................................1 2.4 Mooring Loads ...........................................................................................................3 2.5 Berthing Loads ...........................................................................................................5 2.6 Wind and Current Loads on Structures..................................................................5 2.7 Load Combinations ...................................................................................................5 3.0 Mooring Lines and Hardware Safety Factors and Allowable Loads ...........................5 4.0 Seismic Analysis...................................................................................................................5 5.0 Mooring and Berthing Analysis ........................................................................................5 6.0 Geotechnical Hazards and Foundations ..........................................................................5 6.1 Liquefaction ................................................................................................................5 6.2 Slope Stability .............................................................................................................6 6.3 Seismic Slope Displacements ...................................................................................6 7.0 Structural Analysis and Component Design ...................................................................6

Tables 1 2 3

Mooring Loads—Wind Speed in Knots (30-Second Gust).................................................. 3 Wind Speed Return Period Data (30-Second Gust).............................................................. 3 Thickness of Liquefiable Material and Post-Liquefaction Settlement ............................... 6

Figures 1 2 3

Design Earthquake 5% Damped Response Spectrum (MOTEMS Level 1) ...................... 2 Maximum Considered Earthquake 5% Damped Response Spectrum (MOTEMS Level 2).................................................................................................................... 2 Maximum Tsunami Water Surface Elevations ..................................................................... 4

iii

MARINE FACILITIES DESIGN CRITERIA, OREGON LNG TERMINAL

1.0 Introduction This report is intended to document the basic design criteria used for preliminary design of the marine facilities at the Oregon Liquefied Natural Gas (LNG) Terminal. Specifically, the marine facilities include the following structures: • • • • •

An unloading platform Four breasting dolphins Six mooring dolphins An LNG trestle Interconnecting walkways

To the extent practical, the marine facilities preliminary design has been performed in accordance with the 2005 Marine Oil Terminal Engineering and Maintenance Standards (MOTEMS), as published by the California State Lands Commission and available at the following Web address: http://www.slc.ca.gov/Division_Pages/MFD/MOTEMS/MOTEMS_Home_Page.html

2.0 Structural Loading 2.1

Dead Loads

See MOTEMS Section 3103F.2.

2.2

Live Loads

•

Equipment and piping area loads: MOTEMS Table 31F-3-2.

•

Uniform traffic load—areas available for vehicle access: 50 pounds per square foot (psf) (applied so as to achieve maximum stress in considered member).

•

Truck loads: American Association of State Highway and Transportation Officials (AASHTO) H15 Truck.

•

Walkways between dolphins: 50 psf or a single 300 pound concentrated load (applied so as to achieve maximum stress in considered member).

•

Unloading Platform Walkways and Elevated Platforms: 60 psf (applied so as to achieve maximum stress in considered member).

2.3

Earthquake Loads

MOTEMS Section 3103F.4 with a site-specific probabilistic seismic hazard analysis (PSHA). See Figures 1 and 2 for design response spectra.

1


FIGURE 1 Design Earthquake 5% Damped Response Spectrum (MOTEMS Level 1)

FIGURE 2

Maximum Considered Earthquake 5% Damped Response Spectrum (MOTEMS Level 2)

2


2.4

Mooring Loads


2.4.1

Wind Speed

TABLE 1

Mooring Loads—Wind Speed in Knots (30-Second Gust) a

1

1

1

Current = 0 kt

Current = 1 kt

Current = 3 kt

Current = 5 kt

Operating Condition

60

60

60

55

Survival Condition

70

70

65

60

a

Current direction within 10 degrees of berthing line.

TABLE 2

Wind Speed Return Period Data (30-Second Gust) Return Period (Years)

Wind Speed (Knots)

2

45.0

5

49.4

10

52.4

15

54.1

20

55.2

25

56.1

30

56.9

40

58.0

50

58.9

75

60.5

100

61.7

2.4.2

Current Speed

Adequate current speed data are not available for the Terminal location. Chapter 10, Columbia River, Oregon and Washington, in United States Coast Pilot 7, Pacific Coast: California, Oregon, Washington, Hawaii, and Pacific Islands, 2007 Edition, published by the National Oceanic and Atmospheric Administration (NOAA), the U.S. Department of Commerce, and the National Ocean Service, indicates that currents vary from 1 to 3 knots in the vicinity of the Terminal. For preliminary design, a maximum 5-knot flood or ebb current with a direction within 10 degrees of the berthing line was assumed. It is important to note that additional current speed and direction data will be required for final design of the Terminal.

3


2.4.3

Wave Forces

Waves are not considered to be significant at the Terminal’s relatively sheltered location. Therefore, wave forces have not been analyzed and are not included in these design criteria.

2.4.4

Seiche

Long-period wave energy is negligible at the Terminal location; therefore, seiche effects have not been analyzed and are not included in these design criteria.

2.4.5

Tsunami

The lowest elevation of all superstructure elements has been placed at an elevation above the design tsunami run-up elevation. As such, inundation and “slamming” effects are avoided. Steel cylinder piles have been designed to resist current speeds associated with a tsunami effect. The presence of significant floating debris is considered to be unlikely; therefore, debris effects have not been analyzed and are not included in these design criteria. The maximum current speed during a tsunami event, based on site-specific hydrodynamic modeling, has been determined to be 4.2 knots. This current speed is less than the design current speed; therefore, tsunami effects are not required as part of the mooring analysis.

FIGURE 3 Maximum Tsunami Water Surface Elevations

4


2.5

Berthing Loads


2.6

Wind and Current Loads on Structures


2.7

Load Combinations


3.0 Mooring Lines and Hardware Safety Factors and Allowable Loads See MOTEMS Sections 3103F.9 and 3103F.10.

4.0 Seismic Analysis See MOTEMS Section 3104F, except for seismic loading (see Section 2.3).

5.0 Mooring and Berthing Analysis See MOTEMS Section 3105F, high risk classification.

6.0 Geotechnical Hazards and Foundations The marine facilities site lies within an area characterized by alluvial soil that may be subject to liquefaction, seismic slope instability, and lateral spreading during and immediately after strong ground shaking. This section provides a summary of these hazards and how they have been mitigated for in the preliminary design. Additional details are provided in Appendix J.1 to Resource Report 13, Geotechnical Investigation Report for the Oregon LNG Terminal Project, dated October, 2008.

6.1

Liquefaction

Potentially liquefiable soil layers have been identified as part of the project geotechnical study as shown in Table 3.

5


TABLE 3

Thickness of Liquefiable Material and Post-Liquefaction Settlement Layer

Thickness of Liquefiable Material (feet)

Estimated Post-Liquefaction Settlement (inches)

Ground Surface to Elevation -12

0 to 15

1 to 4

Elevation -12 to -80

5 to 15

1 to 4


0 to 10

1 to 5


5 to 10

<1


0 to 10

1 to 5


20 to 30

<1

Total

25 to 90

6 to 20

Vertical load carrying capacities for the marine facilities were calculated including the effects of liquefaction.

6.2

Slope Stability

Cut slopes have been designed with a minimum factor of safety of 2.0 under non-seismic conditions. Existing slopes at the location of the marine facilities have been analyzed and the factor of safety is in excess of 2.0.

6.3

Seismic Slope Displacements

The site is vulnerable to seismic slope displacements during the MCE seismic event, with an estimated slope displacement of 9 inches from the ground surface to an approximate elevation of -60 feet. The marine facilities foundations are designed to displace with the slope without collapse.

7.0 Structural Analysis and Component Design See MOTEMS Section 3107F.

6

Basis of Design LNG

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