LNG Design Standard

Oregon LNG Project Warrenton, OR

Job No. 07902 Doc No. 07902-TS-000-001 Rev 2

Engineering Design Standard

Page 1 of 41

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

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.

Oregon LNG Project Warrenton, OR Engineering Design Standard

Job No. 07902 Doc No. 07902-TS-000-001 Rev 2 Page 2 of 41

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 .................................................................. 8 3.1

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

3.2

Continuous Sendout................................................................................................. 8

3.3

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

3.4

Plant 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 ........................................................................................... 10

4.2

Boiloff Gas (BOG) Calculation Assumptions .......................................................... 11

4.3

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





Page 3 of 41

5 TERMINAL LABELING / NUMBERING STANDARD........................................ 13 5.1

Terminal Areas ....................................................................................................... 13

5.2

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

5.3

Equipment Classification ........................................................................................ 15 5.3.1

5.4

5.5

Equipment Sub-classification .................................................................................. 15

Equipment, Instrument and Valve Numbering Convention .................................... 16 5.4.1

3-Digit Rule.............................................................................................................. 16

5.4.2

Identical Equipment in Parallel Service................................................................... 16

5.4.3

Valve Numbering..................................................................................................... 16

Line Specification ................................................................................................... 17

6 PIPING & INSTRUMENTATION DIAGRAM (P&ID) STANDARD ..................... 17 6.1

Basic Considerations ............................................................................................. 17

6.2

P&ID Numbering .................................................................................................... 17

6.3

P&ID Organization.................................................................................................. 18

6.4

PSV/TSV Standardization ...................................................................................... 18 6.4.1

Thermal Safety Valves (TSV).................................................................................. 18

6.4.2

Pressure Safety Valves (PSV) ................................................................................ 20

6.5

Vent/Drain Valves................................................................................................... 21

6.6

Field Instrumentation.............................................................................................. 22 6.6.1

Local Indication ....................................................................................................... 22

6.6.2

Combined Pipe Penetrations .................................................................................. 22

7 PIPING - GENERAL........................................................................................... 22 7.1

Design Fluid Velocities ........................................................................................... 22

7.2

Design Pressure..................................................................................................... 22

7.3

Use of Flanges ....................................................................................................... 22

7.4

De-Inventory of LNG Transfer System ................................................................... 23





Page 4 of 41

7.5

LNG Pipe Penetrations........................................................................................... 23

7.6

Thermal Relief Valves ............................................................................................ 23 7.6.1

Set Pressure............................................................................................................ 23

7.6.2

TSV Take-Off Elevation .......................................................................................... 23

7.6.3

TSV Discharge ........................................................................................................ 23

7.7

LNG Sample Points................................................................................................ 24

7.8

LNG Piping Headers .............................................................................................. 24

8 CRYOGENIC INSULATION ............................................................................... 24 9 CRYOGENIC INSTRUMENT PIPING DETAILS ................................................ 24 9.1

Vessel Level Instruments - General ....................................................................... 24

9.2

Liquid Level Taps on a Vessel ............................................................................... 25

9.3

Liquid Differential Pressure Taps on a Vessel ....................................................... 26

9.4

Liquid Pressure Tap on a Vessel ........................................................................... 26

9.5

Horizontal Liquid DP Flow Meters .......................................................................... 27

9.6

Vertical Liquid DP Flow Meters .............................................................................. 27

10 LNG TRANSFER AND COOLDOWN ................................................................ 28 10.1 Transfer Piping ....................................................................................................... 28 10.2 LNG Unloading Arm Cooldown and Draining......................................................... 28 10.2.1 Arm Cooldown Vent ................................................................................................ 28 10.2.2 Arm Drain ................................................................................................................ 28

10.3 Vapor Return System ............................................................................................. 28

11 LNG TANK DESIGN REQUIREMENTS............................................................. 29 11.1 LNG Tank Discretionary Vent................................................................................. 29 11.2 LNG Tank Vapor Makeup....................................................................................... 30 11.3 LNG Tank Recirculation ......................................................................................... 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.



11.4 LNG Tank Isolation ................................................................................................ 30 11.5 LNG Tank Boiloff Gas Flow Measurement............................................................. 30 11.6 LNG Tank Top and Bottom Fill Flow Measurement ............................................... 30

12 MAINTENANCE COOLING OF THE IMPORT TERMINAL ............................... 31 12.1 Vertical Risers ........................................................................................................ 31 12.2 Standby LNG Pumps.............................................................................................. 31 12.3 Small Bore LNG Piping .......................................................................................... 31 12.4 Zero Sendout ......................................................................................................... 31

13 VENT / DRAIN SYSTEM .................................................................................... 31 13.1 Vent System ........................................................................................................... 31 13.2 Double Block & Bleed Vents .................................................................................. 32 13.3 Vent and Drain Systems......................................................................................... 32

14 DRYOUT AND COOLDOWN ............................................................................. 32 14.1 Initial Dryout and Cooldown ................................................................................... 32 14.2 LNG Tank Cooldown .............................................................................................. 32

SAFETY DESIGN ...................................................................................... 33 15 EMERGENCY SHUTDOWN SYSTEM STANDARD.......................................... 33 15.1 Position Indicators on ESD Valves......................................................................... 33 15.2 Use of Control Valves to Serve as ESD Valves ..................................................... 33 15.3 Positioners on ESD Valves .................................................................................... 33 15.4 Emergency Shutdown System (ESD) Logic........................................................... 33 15.4.1 ESD-1: LNG Transfer Operations ........................................................................... 34 15.4.2 ESD-1-1: Unloading Arm Breakaway...................................................................... 35 15.4.3 ESD-2: Balance of Terminal.................................................................................... 35 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.



16 CAR SEALING STANDARD.............................................................................. 36 16.1 Introduction ............................................................................................................ 36 16.2 Use of Car Seals .................................................................................................... 37

17 DOUBLE BLOCK AND BLEED STANDARD.................................................... 37

ELECTRICAL DESIGN.............................................................................. 38 18 STANDBY AND BACK-UP ELECTRIC POWER............................................... 38 18.1 Standby Electric Power Generator ......................................................................... 38 18.2 Uninterruptible Power Supply (UPS) Systems ....................................................... 38

CONTROL SYSTEM DESIGN ................................................................... 39 19 CONTROL SYSTEM DESIGN STANDARD ...................................................... 39 19.1 Description ............................................................................................................. 39 19.2 Design Philosophy ................................................................................................. 39 19.2.1 Control Rooms ........................................................................................................ 40 19.2.2 Field Instruments..................................................................................................... 40 19.2.3 Instrumentation Power Supply ................................................................................ 40




INTRODUCTION 1

PURPOSE OF STANDARD This Standard establishes essential requirements and minimum standards for the design, installation, and safe operation of the Oregon LNG Import Terminal that is to be constructed on the 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 in 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 Import 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 Import Terminal provided shall be of proven design, built to current design codes and standards listed in the codes and standards document. 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 Import Terminal. This equipment shall include but not be limited to LNG unloading arms, compressors, pressure vessels, pumps, vaporizers, vapor condensers, valves and instrumentation. The 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 Import Terminal and to consolidate and therefore minimize the holding of spare parts required. The Import 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 Sendout The Import Terminal shall be designed to ensure that sendout gas can be maintained continuously 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 gas sendout rate. A Reliability, Availability, Maintainability (RAM) analysis, acceptable to the Owner, shall be completed by the Engineer for the proposed design. The Import Terminal shall be designed for 24 hour per day continuous service factor for full 365 annual days of operation.

3.3

Designed for Maintenance The Terminal design shall facilitate ease of on-site maintenance of all equipment, including adequate clearance for maintenance access to all compressors and pumps. 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. Removable roof panels shall not be employed.




Platforms, ladders, stairways, walkways and landings shall be provided as required for access to buildings, equipment, valves and instrumentation. Generally, all valves, instrumentation and inspection ports that are mounted at an elevation of 6 feet or higher shall be provided with platforms for operational access. The overall Import 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 Import Terminal. Walkways shall be provided throughout the Import Terminal for pedestrian access. 3.4

Plant Lighting Adequate lighting shall be installed in all operational areas such that work may be safely performed at any time. These areas include, but are not limited to the process area, all roads and accesses, office and maintenance areas, the jetty area and tanks. Plant 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 Import Terminal shall be designed for a life cycle of at least 25 years. After 25 years operation the Import 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. This equipment shall, however, be designed to have maximum practical life and shall be designed with adequate sparing so as to allow for Import Terminal continuous operation at full load.

3.6

Electromagnetic Interference The Import 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

Page 10 of 41

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 base project to allow for this expansion with minimum future interruption of Import 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). Where 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 4.1

Process Flow Streams The following specific streams (conditions), at a minimum, shall be included in Heat & Material Balance (H&MB) tables with identifying labels for each on the Process Flow Diagram (PFD): •

LNG cargo in LNG Ship upon arrival at terminal

•

LNG at unloading arm flange

•

LNG immediately prior to entering LNG Storage Tank

•

LNG in LNG Storage Tank receiving LNG cargo

•

LNG at discharge of LP 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





4.2

•

Vapor leaving LNG Storage Tank receiving LNG cargo

•

Vapor at inlet to BOG Compressors, if used

•

Vapor exiting BOG Compressors, if used

•

Vapor at inlet to Vapor Return Blowers, if used

•

Vapor at outlet of Vapor Return Blowers, if used

•

Vapor returning to ship at vapor arm flange

•

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.

Page 11 of 41

Boiloff Gas (BOG) Calculation Assumptions The items in Table 4.2 provide the detailed assumptions that are used in process simulation. The results of such simulation define the sizing of the BOG handling systems.





Page 12 of 41 Table 4.2 BOG Calculation Assumptions

Item

Value

1) Maximum saturation pressure on arrival

1,2

of ship’s cargo

See Design Basis

2) Ship Boiloff Rate (based on mass)

See minimum boiloff rate specified in the Design Basis

3) Ship pump head

490 feet of head at ship’s pumps discharge flange; see Design Basis for head at ship’s manifold3

4) LNG Tank Pressures, Full Containment Tank •

Max Allowable Working Pressure (MAWP)

See Design Basis

•

Set point of discretionary vent:

See Design Basis

•

Normal operating pressure range

See Design Basis

•

Operating pressure to size BOG Compressor

See Design Basis

5) Vapor Return to the ship (at Vapor Arm flange) •

Flow

Ship displacement less ship boiloff

•

Maximum temperature

See Design Basis

•

Minimum pressure

See Design Basis

6) LNG Tank Boiloff Rate (based on mass)

See Design Basis

7) Excess BOG Compressor Sizing (Worst case)

0%

8) Subcooled condition of Effluent from BOG Condenser

Subcooled by 10°F

4.3

Process Simulation Cases The FEED shall include, at minimum, the following design cases with the typical LNG compositions listed in the Design Basis: Case 1 - Zero Sendout, No Carrier Unloading Case 2 - Minimum Sendout Rate required for full vapor handling (no venting), No Carrier Unloading

1 2

3

The saturation pressure is the equilibrium pressure, not to be confused with the ship tank vapor pressure. This is an extremely important parameter in sizing of the Vapor Handling Systems and should be stated explicitly in any LNG purchase agreement. To be confirmed after shipping agreements are completed.





Page 13 of 41

Case 3 - Minimum Sendout Rate required for full vapor handling (no venting), With Carrier Unloading Case 4 - Peak Sendout (1.5 bscfd), With Carrier Unloading Case 5 - Peak Sendout (1.5 bscfd), No Carrier Unloading

5

TERMINAL LABELING / NUMBERING STANDARD 5.1

Terminal Areas The Terminal shall be divided into a finite number of process4 and other system areas with equipment in any given area being numbered to identify that area; e.g., Area 100 equipment will be “100 series” equipment. Terminal area codes are used for both document and equipment identification; for example, drawings involving low pressure process will be “200” series drawings and equipment and line numbers involving low pressure process will be “200” series numbered equipment and lines. Code

5.2

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

800

Civil Works (Buildings, Roads, etc.)

900

Utilities

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

4

LNG, NG, Vent and Fuel Gas; may also show nitrogen lines associated with process.





Page 14 of 41 Figure 5.2 – Line Numbering Convention

where, •

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. Note that; o Where line sizes change due to a change in line function, separate line numbers will be assigned o Where line sizes change in telescoping headers for economical purposes, it is not necessary to assign unique line numbers

5

•

Line Number Modifier is typically A – B – C, etc. for identical, parallel equipment5.

•

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

Page 15 of 41

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 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 sometimes 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

Page 16 of 41

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 would be D-203. 5.4.1

3-Digit Rule Due to the relatively small number of systems and “units” of an LNG import terminal, equipment, instrument and valve numbers shall be limited to 3 digits. For example: a pressure control valve in Area 100 – PV-102; an LNG pump in Area 200 – P-202, a flow controller in Area 300 – FIC-302. If the Engineer’s design software requires 4 digits, then the first digit shall always be 0 (zero). The three digit equipment number shall be unique.6 For example if the C-204 is the BOG Compressors, there should be no other 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. For example: FV-110A and FV-110B; T-201A and T-201B; PIC-320A and PIC-320B; TSV-310A and TSV-310B; and LNG-205A-12" and LNG-205B-12". 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. All valve numbers shall be shown on the P&IDs. Manual (hand) valves shall use the designation “V.” Please 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

6

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





control, and each piece of instrumentation. installed by the vendor supplying each item. 5.5

Page 17 of 41

These shall be supplied and

Line Specification Due to the relatively small number of piping classes typically used in an LNG import terminal, line specifications shall be limited to 4 digits, with a fifth digit permitted to indicate above or below grade, if necessary. The Engineer’s standard line specifications might have more digits, in which case the Engineer shall use the 4 digit convention with a cross reference. The 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 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.

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 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.




Page 18 of 41

• PI = Document Type (here PI = Piping & Instrumentation Diagram) • YYY = Terminal Area, as described in Section 5.1 • 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 6.3

P&ID Organization The P&IDs shall be in numerical sequence organized7 in the following order; the Sequence Number is the first number of the 3-digit page number:

6.4

Sequence Number

Contents

0

Introductory (Index of P&IDs, Abbreviations, Line Service, Symbols, General Notes, “Typical” sketches, Line Specifications, etc.).

1

LNG, Boiloff, Natural Gas and Fuel Gas Piping and Systems

4

Auxiliaries Supporting Sequence Number 1 Equipment, e.g., heat transfer fluid systems, lube oil systems for compressors/blowers, etc.

6

Hazard Detection and Mitigation Systems

9

Utility Systems, e.g., Instrument Air, Nitrogen Systems, various non-fire water systems, etc.

PSV/TSV Standardization 6.4.1

Thermal Safety Valves (TSV) All TSVs (Thermal Safety Valve) systems (including all valves) shall be shown on the P&IDs. Valve numbering and arrangement for each TSV shall follow the convention shown in Figures 6.4.1-1 and 6.4.1-2 unless there is a

7

Not to be confused with Terminal Area (See Section 5.1).





Page 19 of 41

site-specific reason to deviate. The pressure set point for the TSV shall be shown adjacent to the TSV number. Figure 6.4.1-1 – TSV System – Valve Arrangement and Numbering Standardization Low and Medium Pressure Systems





Page 20 of 41

Figure 6.4.1-2 – TSV System – Valve Arrangement and Numbering Standardization, High Pressure Systems

6.4.2

Pressure Safety Valves (PSV) A very similar standardization shall be used for Process Safety Valves (PSV).





6.5

Page 21 of 41

Vent/Drain Valves All low and intermediate pressure 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. These configurations are shown in Figure 6.4.2-1. Figure 6.4.2-1 – Vent / Drain Valve Standardization





6.6

Page 22 of 41

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 local 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 LNG ........................ 10 ft/sec High Pressure LNG ........................ 15 ft/sec LNG Unloading Lines......................20 ft/sec LNG Vapor .................................... 75 ft/sec Heat Transfer Fluid ........................ 10 ft/sec

7.2

Design Pressure Note: For FERC jurisdictional facilities such as Oregon LNG, 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 meet the intent of NFPA 59A-2006 Section 9.3.1.4 shall be met by minimizing the use of flanges in cryogenic piping. All cryogenic valves are to be welded unless specifically identified otherwise. Vessels 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





Page 23 of 41

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 LNG Transfer Systems following start-up of the Import Terminal. Every isolation/control/ESD valve in the LNG Transfer system 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. All 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". All 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 flange 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. Similarly, 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. Piping that serves in intermittent operation shall also be provided with a means for maintenance cooling.

8

CRYOGENIC INSULATION See the Cold Service Insulation Specification 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






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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 Unloading Arm Cooldown and Draining 10.2.1 Arm Cooldown Vent The cooldown vent for each unloading arm shall be located as high on the arm riser as possible to facilitate the removal of cooldown vapor. The vent line should be routed to the Jetty Drum. LNG from the Jetty Drum can be forced into the LNG header with nitrogen. 10.2.2 Arm Drain The piping for each arm shall be sloped toward the LNG header with a remotely 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.

10.3

Vapor Return System The vapor return system shall be configured with the minimum configurations as depicted in Figure 10.3 below: •

A Spray Desuperheater for cooling of the vapor return at the beginning of the vapor return operation.

•

A bi-directional Jetty Drum (located downstream of the Spray Desuperheater) sized for carryover of LNG from unloading arm cooldown, build-up of heavies during desuperheater operation and residual LNG following unloading arm draining. Capability to use either nitrogen to empty residual LNG into the LNG circulation stream following each unloading. Note: For FERC jurisdictional facilities such as Oregon LNG, the elevation of the Jetty Drum must also allow for the future addition of LNG pumps.





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•

The capability to take vapor from the ship, with the expectation that the ship will be required to use its onboard vapor compressors.

•

Pressure control of vapor return arm when returning vapor to the ship.

•

A separate pressure control for accepting vapor from the ship. Figure 10.3 Vapor Return System

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. The 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 if, at high sendout rates when a ship is not unloading, there is the need to send gas to the vapor spaces of the LNG Storage Tank due to the draw down of the LNG from the tank(s). If required, the primary source of this make-up gas is from vaporized LP Pump discharge. This vaporized LNG shall be injected into the BOG Header upstream of the BOG Drum. The lowest pressure from the low select relay from the LNG Storage Tank vapor pressure transmitters shall serve as the process variable from which the pressure controller operates. A backup BOG make up system shall also be incorporated into the design. 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. This recirculation shall be accomplished without interfering with normal LNG Jetty recirculation and sendout 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 tanks. 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.





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12 MAINTENANCE COOLING OF THE IMPORT 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. The 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

Zero Sendout During periods when there is no LNG 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. All LNG and NG relief valves (excluding LNG Storage Tank, fuel gas and vaporizer outlet relief valves) 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. See Section 11.1 also.



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 (See Section Error! Reference source not found.).

13.3

Vent and Drain Systems There shall be separate vent and drain header system for gas and for liquids. These header systems shall drain into an uninsulated Low Point Drain Drum, which vents into the BOG Header. The 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 car sealed closed drain line will be provided to return liquids to the LNG Tanks.

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 in preparation for unloading the first LNG ship. 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. Appropriate design temperatures for this equipment shall be used.





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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 case-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 case-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. All other shutdowns that are process related trips are not emergency shutdowns. The ESD system has three elements: ESD-1:

Shutdown of unloading operations and isolation of the jetty

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

Shutdown of LNG/NG sendout operations including ESD-1.

The demarcation of the various ESD zones is depicted in Figure 15.4.





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Figure 15.4 – ESD Zones

15.4.1 ESD-1: LNG Transfer Operations Actuation of ESD-1 leads to suspension of unloading operations, isolation of loading arms and vapor return arm and isolation of Pier/Shore transfer line. The following actions are performed on activation of ESD 1 for the Pier/Offshore area:

ESD valves on unloading arms and vapor return arm are closed.

Process valves on the off-shore piping with ESD function are closed.

LNG unloading pumps on the ship trip and ship’s manifold valves are closed (through ship/ shore umbilical signal).

Pier/shore ESD isolation valves are closed.

ESD-1 is manually actuated by:

ESD push buttons located in the Platform Control Room and the Main Control Room.





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ESD push buttons centrally located close to the LNG unloading arms and vapor return arm.

ESD push buttons are located at the Pier/Shore interface.

The ship’s Cargo Officer.

ESD-1 is automatically operated on the following:

Actuation of the 1st stage over-reach alarm (apex or slew angle) on any of the unloading arms or vapor return arm.

Activation of cross-zoned fire or spill detectors.

Activation of a cross-zoned gas detector’s HH limit alarm.

ESD-1 leads to complete shutdown of the platform unloading operation and isolation of process lines to/from the pier. 15.4.2 ESD-1-1: Unloading Arm Breakaway Actuation of ESD-1-1 leads to the following actions:

Activation of the Emergency Release Couplings (ERC) on all of the arms.

Activation of ESD-1.

ESD-1-1 is manually actuated through:

ESD push buttons located (TBD during design).

ESD-1-1 is automatically operated on the following:

2nd stage overreach of apex or slew angle alarm on any of the loading arms or vapor return arm.

15.4.3 ESD-2: Balance of Terminal ESD-2 shuts down the operations on the process systems (LNG and NG) so as to minimize potential release of hydrocarbon in an emergency. Activation of ESD-2 automatically initiates ESD-1. Actuation of ESD-2 leads to the following actions:

LP Pumps trip.

The inlet and outlet valves to the LNG Tank close.

HP Pumps trip.





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Vapor Return Blowers and BOG Compressors trip.

Valves on LNG inlet and outlet to the Condenser/HP Drum area close.

Valves on LNG inlet to vaporizers close.

ESD-2 action is initiated manually by activation of any single push button at the following locations:

Near the HP Pumps.

Near the Condenser.

Near the Compressor Building.

Near the Vaporizers.

Main Control Room.

On the pier and at other locations determined during review of the Fire Safety System.

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 a import 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

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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 any 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 Import 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 Import Terminal shall be designed with the following philosophy regarding non-instrumentation equipment isolation: ♦

LNG service - Equipment shall be isolated from all sources of LNG 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.

♦

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.

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.





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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. The Distributed Control System shall allow communication with each instrument sub-system via Modbus RTU protocol, utilizing Ethernet or serial connections, or hardwired connections. The DCS shall provide the sole means of process remote control and supervision of the Import Terminal from the Main Control Room (MCR) and at the Jetty Control Room (JCR). 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 JCR. 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. To achieve this, all provided components shall be readily maintainable during operations. Online 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. The 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





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•

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. The 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. The power system to controllers and I/O for associated process, SIS and HDMS shall be supplied with 24 VDC and have integral automatic and bumpless backup. Power 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 VDC 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. 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.




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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 deenergizing any critical equipment.


LNG Design Standard

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