Appendix 13L-Storage Tanks

Oregon LNG Warrenton, Oregon Public Appendices

Job No. 07902

Resource Report 13 18 CFR 380.12(o) Appendix L.1

Oregon LNG, LLC Warrenton, OR LNG Storage Tank and Foundation Specification

Job No. 07902 Doc No. 07902-TS-200-108, Rev. E Page 1 of 38

LNG STORAGE TANK AND FOUNDATION SPECIFICATION

by H H

C H

EV NUMBER : R EV ISSUE PURPOSE:

DATE: BY: CHECKED: APPROVED:

H

CH·IV International

A Draft for Client Review 07/06/07 AAR RT AAR

B Draft for Client Review 03/25/08 OOA AAR AAR

C Draft for Client Review 05/20/08 MS MHD AAR

D Draft for Client Review 9/21/09 MS MHD AAR

E Include Liquefaction 7/31/12 AAR RT AAR



LNG STORAGE TANK AND FOUNDATION SPECIFICATION

by H H

C H

EV NUMBER : R EV ISSUE PURPOSE:


H


A Draft for Client Review 07/06/07 AAR RT AAR

B Draft for Client Review 03/25/08 OOA AAR AAR

C Draft for Client Review 05/20/08 MS MHD AAR

D Draft for Client Review 9/21/09 MS MHD AAR

E Include Liquefaction 7/31/12 AAR RT AAR


Section

1

2

GENERAL REQUIREMENTS

4

5

Page

4

1.1 Scope of Requirements

4

1.2 Technical Requirements

4

1.3 Codes and Industry Standards

5

DESIGN REQUIREMENTS 2.1 Tank Design

3


8 8

2.2 Concrete Outer Tank Design

15

2.3 Component Design

20

CONSTRUCTION REQUIREMENTS

23

3.1 Materials Requirements

23

3.2 Fabrication and Inspection - Steel Components

25

3.3 Insulation Systems

28

ANCILLARY EQUIPMENT REQUIREMENTS

31

4.1 Accessories

31

4.2 External Piping

32

4.3 Pressure and Vacuum Relief Systems

32

4.4 Electrical

33

4.5 Instrumentation

34

4.6 Painting

36

COMMISSIONING REQUIREMENTS

37

5.1 Hydrostatic/Pneumatic Testing

37

5.2 Calibration

38


5.3 Purging


38


1


GENERAL REQUIREMENTS 1.1

Scope of Requirements

This Specification covers technical requirements for the design, supply, fabrication, construction, inspection, and testing of full containment refrigerated LNG storage tanks T-201A/B and associated foundations for the proposed Oregon LNG Terminal. Each 3 tank shall have a net working capacity of 160,000 m at a temperature of -270°F and a maximum internal pressure of 4.3 psig. The tanks shall consist of a 9% nickel open top inner tank. The outer tank shall be of reinforced concrete consisting of a post tensioned concrete wall connected rigidly to the outer tank concrete slab with a roof constructed of reinforced concrete. Both the inner and outer tanks shall be capable of holding the gross volume of cryogenic liquid without loss of containment, liquid leakage or uncontrolled vapor release. 1.2

Technical Requirements

The following technical requirements are applicable to the design of the LNG storage tanks and associated foundations. 1. Surface and sub-surface site preparation shall be in accordance with the site specific geotechnical investigation. Contractor will specify the requirements for a foundation heating system which, if required, shall be fully redundant. 2. A 9% nickel steel open top inner tank to contain the LNG. 3. A reinforced concrete outer tank consisting of a post tensioned concrete wall connected rigidly to the outer tank concrete bottom, with a roof constructed of reinforced concrete. The inside of the concrete outer tank shall be lined with a carbon steel vapor barrier. 4. A 9% nickel steel Secondary Bottom and 9% nickel steel insulated “Thermal Corner Protection” (TCP) are required and will be linked together. The Secondary Bottom shall be placed above the lower system of Cellular Glass bottom insulation. 5. A carbon steel roof liner, which forms an integral structure with the reinforced concrete roof. 6. A suspended inner deck, supported by hangers from the concrete roof and roof liner. The suspended deck shall be made of aluminum. 7. A tank insulation system including insulation under the inner tank bottom (below the secondary bottom, and between the secondary bottom and the inner tank bottom), insulation in the annular space between the 9% Ni steel inner tank shell and the concrete outer tank, and insulation on top of the suspended inner deck.



8. In-tank pump columns including pump lifting mechanisms, cables (including electrical power supply and instrumentation) from the top of the column to the pump, and junction boxes located at the top of the columns, and internal piping. The pumps shall be provided by others. 9. Platform, staircase, stairs, walkways, caged ladders, monorails, cranes, handrails as further detailed within this specification. 10. Instrumentation for level, pressure and temperature monitoring, leak/gas detection, cooldown control, density monitoring and any other instrumentation specified for supply by the Contractor. 11. Relief valves for pressure and vacuum protection. 12. A fire detection and control system for extinguishing the relief valve stack. 13. Design, supply and erection of all piping associated with the tank. 14. During detailed engineering design, the design of the piping systems on the tank will be modeled to determine pipe loads that anchors must accommodate. 1.3

Codes and Industry Standards

The Full-Containment LNG Tanks shall be designed in accordance with the following Codes and Industry Standards: 1.3.1

American Petroleum Institute (API) th

API 620, 11 Edition, February 2008, with Addendum 1, March 2009, “Design and Construction of Large, Welded, Low Pressure Storage Tanks.” th

API 650, 11 Edition, June 2007, with Addendum 1, November 2008, “Welded Tanks for Oil Storage.” th

API 2000- 5 Edition, April 1998, “Venting Atmospheric and Low Pressure Storage Tanks.” th

API 2003, 6 Edition, September 1998, “Protection Against Ignitions Arising Out of Static, Lightning and Stray Currents.” API - MPMS C2 S2B - “Calibration of Upright Cylindrical Tanks by the Optical Reference Line Method” (R2002).


1.3.2


American Society of Mechanical Engineers (ASME) ASME Boiler and Pressure Vessel Code, 2007 Edition, including all mandatory addenda: Section II

“Material Specifications”

Part A

“Ferrous Materials”

Part C

“Welding Rods, Electrodes, and Filler Metals”

Section V

“Nondestructive Examination”

Section VIII, Div. 1

“Pressure Vessels”, as applicable

Section IX

“Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing Operators”

ASME B31.3 with year 2006 Addenda, “Process Piping.” 1.3.3

American Concrete Institute (ACI) ACI 318-2008, Building Code Requirements for Structural Concrete (ACI 318-08) and Commentary, for prestressed and reinforced concrete portions of the tank. ACI 373, 1997 Edition, Design and Construction of Circular Prestressed Concrete Structures with Circumferential Tendons.

1.3.4

American Society of Civil Engineers (ASCE) ASCE-7 2005 “Minimum Design Loads for Buildings and Other Structures.”

1.3.5

American Institute of Steel Construction (AISC) AISC “Manual of Steel Construction, Allowable Stress Design”, Ninth Edition. AISC 3rd Edition, January, 2003 “Load and Resistance Factor Design Manual of Steel Construction.”

1.3.6

American Society for Testing and Materials (ASTM) ASTM C549-81, “Perlite Loose Fill Insulation” (R1986). ASTM C520-98, “Standard Test Methods for Density of Granular Loose Fill Insulations.”


1.3.7


FEMA FEMA 450: NEHRP Recommended Provisions and Commentary for Seismic Regulations for New Buildings and Other Structures. 2003 Edition

1.3.7.1

FERC Draft Seismic Design Guidelines and Data Submittal Requirements for LNG Facilities dated January 23, 2007.

1.3.8

National Fire Protection Association (NFPA) NFPA 59A-2001 and NFPA 59A-2006, “Production, Storage and Handling Of Liquefied Natural Gas (LNG)”. NFPA 780-2000, “Standard for Installation of Lightning Protection Systems.”

1.3.9

Perlite Institute (PI) PI-201-77, “Compacted Density.”

1.3.10

Federation Internationale De La Precontrainte (FIP) FIP-Recommendation, “Acceptance and Application of Post-Tensioning Systems” – 1981. FIP-Recommendation, “FIP Recommendations for the Approval, Supply and Acceptance of Steels for Pre-stressing Tendons.”


2


DESIGN REQUIREMENTS 2.1

Tank Design

2.1.1

General The LNG storage tanks (T-201A/B) shall be full containment type tanks, with a primary inner container and a secondary outer container. The tanks shall be designed and constructed so that the self-supporting primary container and the secondary container shall be capable of independently containing the LNG. The primary container shall contain the LNG under normal operating conditions. The secondary container shall be capable of containing the LNG (110% capacity of inner tank and which shall be demonstrated by calculation by Contractor) and of controlling the vapor resulting from product leakage from the inner container. The insulated 3 tank shall be designed to store a net volume of 160,000 m (1,006,000 barrels) of LNG at a temperature of -270°F and a maximum internal pressure of 4.3 pounds per square inch gauge (psig). The double-walled tank shall consist of: 

A 9% nickel steel open top inner container;



A pre-stressed concrete outer container wall;



A reinforced concrete dome roof;



A reinforced concrete outer container bottom;



A friction pendulum isolation system;



A secondary tank bottom on a pile cap foundation; and



An insulated aluminum deck over the inner container suspended from the roof.

The aluminum support deck shall be insulated on its top surface with fiberglass blanket insulation material. The vapor pressure from the LNG shall be equalized through ports in the suspended deck and contained by the outer container. The internal design pressure of the outer container roof shall be 4.3 psig. The space between the inner container and the outer container shall be filled with expanded Perlite that shall be compacted to reduce long term settling of the insulation. The insulation shall allow the LNG to be stored at a minimum temperature of -270°F while maintaining the outer container at near ambient temperature.



The insulation beneath the inner container shall be cellular glass load bearing insulation that shall support the weight of the inner container and the LNG. Contractor shall determine if a foundation heating system is required and, if so, the design shall provide full redundancy. The outer container shall be lined on the inside with carbon steel plates. This carbon steel liner shall serve as a barrier to moisture migration from the atmosphere reaching the insulation inside the outer concrete. This liner also forms the barrier to prevent vapor escaping from inside the tank in normal operation. There shall be no penetrations through the tank inner container or outer container sidewall or tank bottom. All piping into and out of the tank inner or outer containers shall enter from the top of the tank. The inner container shall be designed and constructed in accordance with the requirements of API Standard 620 Appendix Q. The tank shall meet the requirements of NFPA 59A and 49 CFR Part 193. Table 2.1.1.1 LNG Tanks Basis of Design

Number of tanks Net capacity of each inner container Maximum internal design pressure Minimum internal design pressure Operating pressure Design wind load Inner tank minimum design metal temperature Corrosion Allowance of inner container Allowable Boiloff Rate 2.1.2

3 3 160,000 m (1,006,000 bbl) 4.3 psig -0.073 psig 0.5 to 3.7 psig 150 mph -270F None 0.05% per day

Service Conditions The inner and outer tank and associated foundation shall be designed for all specified loading conditions/combinations which may occur during construction, testing, commissioning, operation, maintenance and decommissioning of the tank. The following specific design loading cases shall be taken into account: 

Hydrotest of the inner tank to a height based on the hydrotest pressure at the base of the inner tank being 1.25 times the maximum design



product pressure at the base of the inner tank. But, water level shall be the maximum level that does not increase the tank foundation over that required for product.

2.1.3



Normal operation of the tank containing LNG at maximum design product level.



The external pressure on the inner tank shell, exerted by the Perlite insulation in the annular space, in particular for the situation of an empty inner tank.

Wind Loads on Outer Tank The outer container shall be designed to withstand a wind velocity of 150 mph in accordance with 49 CFR Part 193.2067. Also, the seismic isolators shall be studied for wind loads according to ASCE 7-05 Sec.17.2.4.2 requirements.

2.1.4

Earthquake Seismic design of the inner and outer tank shall be in accordance with site specific design criteria in addition to NFPA 59A. Seismic design spectra used for calculation of earthquake load conditions shall be taken from the seismic design response spectra contained in the site specific seismic design basis. Seismic isolation systems shall be designed for the recommended SSE ground motions provided in the site specific seismic design basis report. Seismic isolator may be used to reduce the seismic force to the LNG tank. In that case, all design and construction shall be in accordance with the requirements in ASCE 7-05 Chapter 17.

2.1.4.1

Inner Tank: The inner tank shall be designed using the methods in API 620 Appendix L, modified as appropriate to apply site specific Operating Base Earthquake (OBE) and Safe Shutdown Earthquake (SSE) criteria as described in the seismic design design response spectra and as required required by NFPA 59A. It shall be assumed that the inner tank is filled with LNG to its maximum normal operating level level (which is not an overfill or alarm level). When designing for the SSE condition, allowable stresses shall be determined in accordance with NFPA-59A. NFPA-59A.

Oregon LNG, LLC Warrenton, OR LNG Storage Tank and Foundation Specification 2.1.4.2


Outer Tank: The outer tank shall be designed using Operating Base Earthquake (OBE) and Safe Shutdown Earthquake (SSE) criteria as described in the seismic design response spectra and as required by NFPA 59A. The overall response of the total LNG storage tank system shall be determined by combining the significant modes using “Square Root Sum of the Squares” Squares ” The results shall be combined with other load effects that are calculated using a finite element analysis method. For axial symmetric conditions, the concrete tank may be modeled using axially symmetric elements, including foundation elements. Where appropriate, a 3-D model of the tank shall be used.

2.1.4.3

Load Conditions and Combinations The horizontal and vertical response spectra for both the OBE and SSE shall be input to the model as acceleration spectra. Vertical components (acceleration and the relationship between amplitude and freq uency) shall be based on spectra contained in the site specific seismic design basis . The responses of the composite tank structure for each mode shape shall be determined from the appropriate response spectrum, modal frequency and composite damping. . The horizontal and vertical responses shall be combined as follows. 

100% horizontal +/- 40% vertical



40% horizontal +/- 100% vertical



Load combinations that include vertical acceleration (hydrodynamic) components producing hoop (circumferential) tension in the inner tank shell plates may be evaluated using strength properties as permitted per Section 2.1.4.4 of this Sepcification. The hydrodynamic hydrodynamic pressure components shall be directly added to (combined with) static liquid pressure when using strength properties permitted per Section 2.1.4.4 Section 2.1.4.4 of this Specification.

For seismically isolated tanks (base isolated foundation), seismic load shall be calculated calculated with the procedure procedure which confirms confirms to ASCE ASCE 7-05 Ch.17. Ch.17. The response and displacement of each LNG storage tank component in two horizontal directions may be combined by using the SRSS. Material Structural Damping factors shall be as follows (Unless higher system damping factors are justified by soil structure interaction analysis).

Oregon LNG, LLC Warrenton, OR LNG Storage Tank and Foundation Specification 2.1.4.3.1


Damping:

Structural Damping factors shall be as follows, 

OBE = 5%, SSE = 5% for the steel tank, and liquid sloshing = 0.5% for the inner tank contents



OBE = 2%, SSE = 5% for the outer post tensioned concrete wall



OBE = 2%, SSE = 5% for the reinforced concrete roof and base slab (Reference; Earthquake Engineering Research Institute (EERI) publication, “Earthquake Spectra and Design”, by Newmark & Hall, page 54, Table 3).



When seismic isolators are used and a model is developed for Finite Element Analysis, the vertical model damping for the isolators may be taken as 2% for OBE and SSE.

2.1.4.3.2

Soil Structure Interaction and Reduction Factors

Soil Structure Interaction (SSI) and/or flexibility of a pile foundation system, analysis shall be performed per the requirements of NFPA 59A. A Reduction factor (R) for the SSE from over-strength, or ductility, and/or other phenomena may may be used if justified by proper analysis. The use of SSI damping ratios and reduction factors in addition to total system damping is subject to approval of the Owner/EPC Contractor and jurisdictional regulatory regulatory authorities. In evaluating vertical earthquake loads using the response spectra approach, it shall be confirmed that the loads used in the static analysis are at least 80% of the loads that would occur if soil-structure interaction is not accounted for. 2.1.4.3.3

Sloshing:

Seismic slosh wave shell freeboard allowances shall be added to the NMLL (Normal Maximum Liquid Level) to determine required inner tank shell height. Calculate shell freeboard allowance including slosh wave per the API 620 L.4.2.8 for OBE and L.4.3.2 for SSE. For the SSE condition the SSE calculated slosh wave height may be added to NMLL without any any extra allowance. allowance. Alternative sloshing height calculation methods may be used providing the calculated sloshing height height is not less than 80% of the value required by these provisions, subject to approval by Owner/EPC Contractor and jurisdictional regulatory authorities.



The response acceleration for the sloshing mode shall be computed using the horizontal seismic design spectra without consideration of the resultant of two horizontal ground motion acceleration components. 2.1.4.4

Maximum allowable stresses for the inner tank design shall be in accordance with API 620, Appendix Q. An allowable stress strength increase factor which is based on operating temperature properties of welded 9% nickel material at the component location under consideration may be applied to the SSE seismic design case and for OBE load combinations that include vertical acceleration (hydrodynamic amplification) pressure components as shown below. Operating temperature allowable stress data may be taken from ASME Section VIII, Division 1/2, Part ULT, Table ULT-23 for Welded Construction. 



Allowable Table ULT-23 stress values in tension are factored as follows: Table ULT-23 value x 3.5 */3.0** x (4/3)*** *ASME Section VIII, Appendix P, Table P-1 factor on tensile strength **API 620-Q, Q.3.3.2 factor on tensile strength ***API 620, 5.5.6 permitted allowable stress increase factor for design loading, except as permitted in Appendix L

2.1.4.4.1 Compliance with Requirements of Draft Seismic Design Guidelines issued by FERC In addition to the above requirements, the Contractor shall design the tanks in accordance with the requirements of the draft "Seismic Design Guidelines and Data Submittal Requirements for LNG Facilities" issued by FERC on January 23, 2007. This includes submittal of the following documents as required by the guidelines:

2.1.5



Tank and Containment Preliminary Design Drawings and Calculations (sufficient to meet the requirements of Part II, Section 3.9 of the guidelines); this includes preliminary structural calculations for the tanks, based on seismic information to be provided by Oregon LNG.



A list of codes, standards, specifications, regulations, general design criteria, and other industry standards used in the design, fabrication, and construction, along with a list of the specific edition (per Part II, Section 3.13 of the guidelines);



A study of the determination and acceptability of LNG liquid levels for seismic forces and freeboard (per Part II, Section 3.15 of the guidelines).

Heat Leak The total heat in-leak shall be such that the boiloff rate shall not exceed 0.05% of the gross tank contents per day.


2.1.6 2.1.6.1


Hazard Design Conditions Heat Radiation/Fire Exposure The outer tank roof and sidewalls shall be capable of withstanding fire exposure and heat radiation from a relief valve discharge fire with the relief valves discharging at the maximum relieving rate.

2.1.6.2

LNG Spill Conditions In addition to the specified service loading, the post-tensioned concrete tank wall and its connection to the foundation shall be designed to contain LNG in the annular space. The outer tank shall be capable of containing 110% of the full inner tank contents and Contractor shall provide calculations confirming this. Such calculations will provide data substantiating assumptions made for the volume taken up by insulating materials (e.g., Perlite and fiberglass) in the annular space. The temperature gradient shall also be analyzed during detailed design for critical steady state spill levels. Since the annular space will fill gradually, there is no specified leakage rate. Note that NFPA-59A requires that the impounding system (the outer concrete tank wall and bottom) be designed to withstand an OBE by holding the volume “V”, which is the full inner tank contents. After an OBE, there shall be no loss of containment capability.

2.1.6.3

Combination of Loading Conditions The inner 9% nickel container and outer post-tensioned concrete tank shall be designed for all service and hazard loading conditions.

2.1.6.4

Impact Loads During detailed design, the maximum acceptable projectile impact load for outer tank wall and roof shall be calculated.

2.1.7 2.1.7.1

Hazard Protection Requirements LNG Spill Protection Spill protection of the LNG storage tank roof shall be designed to comply with the requirements of NFPA 59A. The protection shall extend over the edge of the roof dome. Any structural carbon steel on the roof shall be protected from potential spills.

2.1.7.2

Relief Valve Discharge Lines Tailpipes of relief valves discharging to atmosphere shall be provided with a dry chemical snuffing system for the RV discharge pipes to extinguish accidental fire during pressure venting.


2.2


Concrete Outer Tank Design

2.2.1

Design Requirements The outer tank shall be designed to contain the product pressure at ambient temperature and shall contain the insulation system. The outer tank shall be designed for the following conditions: 

The specified maximum and minimum pressures of 4.3 psig and -1.17 ounce per square inch (-0.073 psig), respectively.



The specified wind design speed of 150 mph as specified in 49 CFR Part 193, Section 2067.



Seismic loads in accordance with NFPA 59A and the site specific seismic design basis.



Internal pressure imposed by insulation loads.



Sensitive analysis of soil stiffness shall be incorporated in dynamic analysis according to ASCE 7-05 Sec.12.13.3.

Roof and platform dead loads shall be in accordance with the following: 

Roof live load (to be determined during detailed design) applied to the entire projected area of the roof and combined with the specified external pressure of 1.17 ounce per square inch (-0.073 psig) and the platform global live load.



Platform live load (to be determined during detailed design) combined with a crane handling live load that shall be determined during detailed design and external pressure load of 0.5 ounce per square inch. Roof live load shall not be combined with the platform live load.

The suspended deck shall be composed of B209-5083-O aluminum. The suspended deck hangers shall be Type 304 stainless steel. 2.2.1.1

Tank Bottom The LNG Storage Tank foundation design shall be based on the detailed site specific geotechnical investigations and seismic design basis. For the access for inspection and replacement of isolators, required by ASCE 7-05 Sec.17.2.4.8.a, there are 4’ space between the outer container bottom and the secondary tank bottom and isolators shall be fixed by bolts/nuts.

2.2.1.2

Tank Wall The wall shall be a monolithic connection to the foundation. A monolithic connection shall also be made between the wall and concrete roof.



The outer tank wall shall be constructed of post-tensioned concrete. Pre – stressing shall be accomplished with an impermeable duct and tendon system. Vertical post-tensioning (if used) shall be accomplished with a duct and tendon system. 2.2.1.3

Tank Roof The roof shall be spherical in shape, and made of reinforced concrete with an interior steel vapor barrier (liner). The steel liner located on the inside of the roof shall be used as formwork for concrete placement. During construction, concrete may be poured in layers to restrict loading on the liner. As part of the construction sequence, the construction contractor shall demonstrate by analysis that the roof plates and framing are adequately designed for non-symmetrical loading due to the concrete pouring sequence.

2.2.1.4

Ringbeam Under Inner Tank Shell A concrete ringbeam shall be installed under the inner tank shell. The ringbeam shall be designed such that the shell loads are properly distributed onto the bottom insulation under the ringbeam. Horizontal forces, caused by possible movements of the annular plate, shall be determined during detailed design.

The concrete ringbeam shall be reinforced with cryogenic rebar or carbon steel rebar if alternative deigned in accordance with NFPA 59A. 2.2.2

Concrete Tank Design Code The design of the prestressed concrete outer tank, and reinforced concrete roof and base slab (pile cap) shall be in accordance with ACI 318.

2.2.3 2.2.3.1

Design/Analysis Tank Wall Design Method The foundation and prestressed concrete wall shall be designed for the following two states: 

Serviceability Limit States (SLS), Includes construction, normal operating, and spill load conditions. This design state shall be utilized to determine concrete crack widths for construction and normal operating loads, and liquid tightness of the wall for the spill condition. All material and load factors shall be taken as 1.0.



Ultimate Limit States (ULS). Includes all load conditions. This design state shall be utilized to determine concrete section adequacy per the strength requirements of ACI 318. ACI 318 designs consider the material



strength reduction factors (Table 2.2.3 1) and the load factors (Table 2.2.3 2) All appropriate load cases and combinations shall be incorporated in the design of the concrete outer tank during the detailed design phase. Upon completion of detailed design a detailed loading summary table, such as shown in Table 2.2.3 3, shall be prepared to cover all phases of the tank lifetime. Seismic load combinations shall consider all possible combinations of the sum of 100% of the effect in one direction (horizontal or vertical) and 40% of the effect in the other direction. Adverse and beneficial effects of the pre-stress and shrinkage loads shall be considered for construction, maintenance and normal operating load conditions. In all cases the detailed design shall take into account the effects of the loads, shrinkage strains, and pre – stressing forces during and after tensioning, and conditions of edge restraint at the wall j unctions with the foundation and roof. 2.2.3.2

ACI 318 Strength Design ULS Material Strength Reduction Factors

Table 2.2.3-1 ACI 318 Strength Design ULS Material Strength Reduction Factors Concrete Strength Parameter

Normal, Test, and OBE Eq Conditions

Emergency Conditions

Flexure without axial load

0.90

1.00

Axial tension w/flexure

0.90

1.00

Axial compression w/flexure

0.70

1.00

Shear and torsion

0.85

1.00

Bearing on concrete

0.70

1.00



ACI 318 Strength Design ULS Load Combinations and Load Factors

Table 2.2.3-2 ACI 318 Strength Design ULS Load Combinations and Load Factors Load Component and Load Factor

Load Combination

d a e D

e g g n i a t k s a s n t d r d i r s a e a h e o p o S T L O L

s s e r t s e r P

e n v i o c c i i i L t s s i s m f d E m d l s d s d l n d o a i a E i a i a o o B e o S e o p o o R L O S L S S L S C L

Construction or Maintenance C, M

1.4

1.2

1.4

--

--

1.7

--

--

--

Test

1.4

1.2

--

1.3

--

--

--

--

--

0.9

1.0

--

1.3

--

--

--

--

--

1.4

1.2

1.0

--

1.6

1.7

--

--

--

0.9

1.0

1.0

--

1.6

--

--

--

--

1.4

1.2

1.0

--

1.6

1.7

--

--

--

Uplift Case

0.9

1.0

1.0

--

1.6

--

--

--

--

Operating (Empty)+OBE EQ O3

1.05 1.05 1.0

--

1.28 --

1.4

--

--

Uplift Case

0.9

1.0

--

1.2

--

1.3

--

--

1.05 1.05 1.0

--

1.28 --

1.4

--

--

0.9

1.0

1.0

--

1.2

--

1.3

--

--

T

Uplift Case Operating (Empty)

O1

Uplift Case Operating (Full)

O2

Operating (Full)+OBE EQ

O4

Uplift Case

1.0

Operating (Empty)+SSE EQ

U1

1.0

1.0

1.0

--

1.0

--

--

1.0

--

Operating (Full)+SSE EQ

U2

1.0

1.0

1.0

--

1.0

--

--

1.0

--

Spill Condition

U3

1.0

1.0

1.0

--

--

--

--

--

1.0

Spill + OBE

U4

1.0

1.0

1.0

--

--

--

1.0

--

1.0

2.2.3.4

Tank Modeling and Analysis During detailed design, the concrete tank shall be analyzed for service and emergency loads using a combination of 2D and 3D finite element modeling and analysis techniques. The analysis model shall also include both heat transfer and nonlinear thermal effects. The overall model shall include the foundation stiffness effects (soil-structure interaction), the concrete base slab (or pile cap), the concrete wall, the outer tank roof, the inner tank, the suspended deck, the insulation system and allowance for piping and tank top structures. The following specific points shall as a minimum be considered during detailed design:



Table 2.2.3-3Tank Modeling and Analysis

2.2.3.5

Analysis or Model

Description

Heat Transfer

Heat transfer analysis shall be performed to determine the temperature distributions for both service and spill loading conditions. The results shall be used with coincident mechanical loading for nonlinear stress analysis.

Stress Analysis

The stress analysis shall take into account the nonlinear behavior of the concrete; i.e., reduced stiffness due to cracking.

Foundation Stiffness

The stiffness effects of the foundation shall be included using spring elements.

Preload

The preload effects due to post-tensioning (including relaxation), creep and shrinkage of the concrete shall also be considered.

Differential Settlement

Predicted edge to center differential settlements shall be included as normal service loads.

Acceptance Criteria The following acceptance criteria for calculations are required for load conditions as applicable:

Table 2.2.3-4 Acceptance Criteria Criteria

Description

Strength Criteria

Concrete strength criteria per ACI 318 shall be satisfied for all load conditions using the material and load factors in Tables 2.2.3.2 and 2.2.3.3, as applicable. For shear strength evaluations of concrete cross sections with significant tension, ACI 318 provisions may be applied.

Crack Control

For construction and normal operating conditions, concrete crack widths in the wall shall be limited to 0.2 mm for prestressed zones. Crack widths in the slab and concrete roof shall be limited to 0.3 mm.

Wall Liquid Tightness

Above the TCP, a compression zone shall be maintained in the wall of at least 10%, but not less than (Applies to Inner Tank 80 mm. In addition, an average compressive stress of Spill Condition Only) 1 MPa [150 psi] shall be maintained in the compression zone.


2.3


Component Design

2.3.1

General The following components shall be designed, fabricated, supplied, erected, inspected and tested in accordance with the standards, guidelines, specifications, documents specified herein and additional requirements as given in this specification. Components include: the inner tank, secondary bottom plus the thermal corner protection (TCP), suspended deck, bottom liner, wall liner, and the roof liner.

2.3.2 2.3.2.1

Inner Tank Allowable Stress Maximum allowable stresses for the inner tank design shall be in accordance with API 620, Appendix Q.

2.3.2.2

Welding Welding of the inner tank bottom annular plates shall comply with API 620 Q 7.1.1. Shell to annular plate welds shall conform to API 620 sections 3.9.5 and Q 7.1.1 requirements.

2.3.2.3

Temporary Access Temporary access through the inner tank shell, using “door sheets” or manways shall be permitted.

2.3.2.4

Welded Attachments All permanent structural attachments welded directly to the 9% nickel steel inner tank shall be of the same material as that to which it shall be welded. Contractor shall prepare an alloy verification procedure.

2.3.2.5

Plate Thickness Minimum plate thickness shall be calculated per API 620.

2.3.2.6

Design Temperature The minimum design temperature shall be -270°F.


2.3.3 2.3.3.1


Liners (Vapor Barriers) Bottom Liner A vapor tight bottom liner connected to the wall liner shall be provided. The design shall account for stresses, strains and thermal considerations. The bottom liner plates shall be lap welded.

2.3.3.2

Wall Liner A vapor tight wall liner connected to the bottom liner, the T CP embed plate, and the roof liner shall be provided.

2.3.3.3

Roof Liner A carbon steel roof liner shall be installed at the inside face of the concrete roof. The liner shall function as an integral part of the concrete roof and may be used as formwork for the concrete during construction.

2.3.4 2.3.4.1

Suspended Deck Vents The suspended deck shall be provided with open vents to ensure pressure equilibrium on both sides of the suspended deck.

2.3.4.2

Plate Design The suspended deck shall be aluminum (B – 209 – 5083 – O AL) and the suspended deck hangers shall be Type 304 Stainless Steel.

2.3.5 2.3.5.1

Secondary Bottom and Thermal Corner Protection (TCP) General The secondary bottom shall consist of ASTM A 553 Type 1 lap-welded inner bottom plates and annular plates at the perimeter.

2.3.6 2.3.6.1

Piping and Roof Nozzles General The tank internal piping shall enter the tank through the concrete outer tank roof. No penetrations through the outer wall or inner tank shell shall be permitted. All roof nozzles shall have vertical axes, with the flange bolt holes straddling the north-south centerline of the nozzle.



External flanges up to 24 inches NPS shall conform to ASME B16.5. Flanges larger than NPS 24 shall conform to ASME B16.47. The design shall satisfy the requirements of API 620, paragraph 5.20.2. Contractor shall provide a listing of nozzle penetrations and also drawings that illustrate the location of the nozzle penetrations. 2.3.6.2

Pump Columns Each LNG Storage Tank shall be equipped with three in-tank pump columns. The size of the columns will be provided separately. The pump columns shall be fully installed and include electrical supplies, supports, instrumentation, piping, etc., for a complete system. The columns shall be designed to ASME pressure vessel codes, as they operate at higher pressures than the LNG storage tank.

2.3.6.3

Liquid Inlet-Top Fill A liquid inlet with a roof nozzle for top filling the LNG Storage Tank shall be provided.

2.3.6.4

Liquid Inlet-Bottom Fill A liquid inlet with a roof nozzle for bottom filling the LNG Storage Tank shall be provided.

2.3.6.5

Vapor Outlets Liquid entrainment shall be avoided in the vapor outlets and relief valves by positioning the vapor outlets away from the deflector plate and standpipe of the liquid inlet line.

2.3.6.6

Purge/Venting System The purge/venting system shall include means for both inerting all areas of the tank using nitrogen and pistoning out nitrogen from the inner tank with introduced natural gas prior to cooldown .

2.3.7

Structural Steel Design of steel structural components shall be in accordance with the USA AISC Steel Construction Manual.


3


CONSTRUCTION REQUIREMENTS 3.1

Materials Requirements

3.1.1 3.1.1.1

Concrete Outer Tank Concrete Concrete shall be per ACI 318 and shall have 28 day specified compressive strengths of 27.6 MPa [4000 psi] for reinforced concrete components, and 41.4 MPa [6000 psi] for post-tensioned components, or higher. Blinding concrete used as a “mud mat” shall be C20. Concrete mix design and production and testing shall comply with ACI 318.

3.1.1.2

Steel All reinforcement, excluding cryogenic reinforcing steel, shall be uncoated deformed bars conforming to the requirements of ASTM A615 Grade 60 or alternatively BS 4449 Grade 460. Cryogenic reinforcing steel shall also be uncoated, but marked in a way as to be clearly distinguishable from noncryogenic reinforcing steel.

3.1.2 3.1.2.1

Inner Tank, Secondary Bottom, and TCP Materials Plate All inner tank primary component plate materials shall comply with ASTM A553 Type 1. ASTM A553 Type 1 shall also have restricted sulfur (max 0.005%) and restricted phosphorus (max 0.010%). The following additional requirements shall be prepared during preparation for construction:

3.1.2.2



A reference list of proposed material suppliers giving details of their experience in the supply of 9% nickel materials.



Before leaving the steel mill, the four corners of all 9% nickel steel plates shall be checked using a gauss meter. Residual magnetism shall not exceed 50 Gauss.



For the quenched and tempered grade of 9% nickel steel, a heat treatment in accordance with the steel manufacturer’s recommendation is required if it has been cold deformed between 3% and 5%. Cold deformation shall not exceed 5%.

Internal Piping Components Material for piping, tubing, forging, and bolting shall conform with the requirements of Appendix Q of API 620 (Table Q-1).



Secondary Bottom and TCP Components The secondary bottom and thermal corner protection shall be made of ASTM A553 Type 1. Material requirements for this A553 Type 1 shall comply with the requirements of API 620 Appendix Q for primary component material.

3.1.3 3.1.3.1

Bottom Liner, Wall Liner, and Roof Liner (Vapor Barriers) Plate The outer bottom plate the steel plate vapor barriers on the concrete wall and their embedment materials, and all roof plate material shall be carbon steel conforming to API 620 Appendix R-4 requirements. Structural framework under the roof plates used for roof plate erection and to provide support during concrete pouring shall be ASTM A36, A572, or equivalent. This framework shall be welded to the roof plates.

3.1.3.2

Welding Welding procedures shall comply with API 620, Appendix R.6 requirements for components that do not qualify as secondary components for all conditions or applicable combinations of normal and emergency loads. Contractor shall prepare an alloy verification procedure that includes details for welding procedures on alloy materials.

3.1.4 3.1.4.1

Suspended Deck Deck Materials The suspended deck shall be ASTM B209 aluminum alloy 5083-O.

3.1.4.2

Hangers Suspension rods/hangers shall be stainless steel Type 304.

3.1.4.3

Testing Procedure - Materials All 9% nickel materials shall be tested in accordance with the requirements of API 620, Q.2.2.2, Q.2.2.3 and Q.2.2.4 and in accordance with the alloy verification procedure prepared by Contractor. Testing methods and controls shall comply with ASTM A370.

3.1.4.4

Welded Joints Impact testing procedure requirements shall be in accordance with API 620, Q.6.2.



The required weld metal and HAZ impact values are 37 ft-lb at -320°F for deposited weld metal and HAZ for full size specimens. Retests, if required, shall be conducted in accordance with ASME Section VIII, Division 1, UHT-6(a)(4). In addition, no single specimen shall have an impact energy value less than 75% of the specified value.

3.2

Fabrication and Inspection - Steel Components

3.2.1 3.2.1.1

Fabrication 9% Nickel Handling Use of magnets for handling the 9% nickel steel plates shall be pr ohibited.

3.2.1.2

9% Nickel Edge Preparation Plate edge preparation of 9% nickel plates shall normally be done by machining. Plasma cutting is permitted subject to approval of submitted procedures. For specific cases, where flame cutting is necessary for weld bevel preparation, the cut edges shall be ground to a bright metal finish.

3.2.1.3

Production Tests for 9% Nickel Production tests for 9% nickel steel plate fabrication for the inner tank are required per API 620 Appendix Q. Contractor shall prepare alloy verification procedures.

3.2.1.4

Temporary Attachments Temporary attachment welding to the inner tank shall be qualified in accordance with API 620. The welds shall be removed prior the hydrostatic testing of the tank.

3.2.1.5

Arc Strikes Arc strikes on primary components shall be avoided, and temporary attachment welds on primary components shall be removed. The surface of the primary components where arc strikes have occurred and where temporary attachment welds have been removed shall be properly conditioned to eliminate surface stress risers. Such surfaces shall be liquid penetrant examined and any defects removed, and the surface repaired and re-examined before the tank is hydro tested.

3.2.1.6

Installation Procedures The welding and installation method of the primary and secondary bottoms shall be such that voids are minimized under the bottom liner. Procedures



shall be prepared for installation of the bottom, the cellular glass insulation and the concrete ringbeam. A mouse-hole shall be made in the horizontal butt-welds of the inner tank stiffeners in accordance with Figure Q-1 of API 620 to allow liquid to completely drain.

3.2.2 3.2.2.1

Welding Procedures General Welding shall be in accordance with API 620 and in accordance with an alloy verification procedure that is to be prepared by Contractor. All vertical and horizontal seams of the inner tank shell may be welded manually, semiautomatically, or by machine.

3.2.2.2

Documentation All welding procedure specifications (WPS) and procedure qualification records (PQR) to be used for the construction of the tanks, including those for prefabrication, repair, tack and attachment welds, shall be approved prior to the work being performed.

3.2.2.3

Welding and NDE Maps Welding procedures used for all welds and the radiographic or ultrasonic inspection procedure shall be clearly indicated in construction documents.

3.2.2.4

Post Hydrotest No welding shall be permitted on the inner tank after completion of the hydrotest.

3.2.3 3.2.3.1

Welding Consumables General Filler metal for 9% nickel welding shall conform to AWS SFA-5.11 and/or SFA-5.14.

3.2.3.2

Code Compliance Each lot or heat of the austenitic stainless steel welding (filler) materials shall meet the requirements of ASME Section VIII, Division 1, UHA-51 (e) and (f). All welding procedures shall be qualified as required by API 620.

3.2.4

Welding Qualification and Identification



All welding shall be performed by qualified welders, tested and certified to each process including fit up. Tank welding shall be performed in accordance with the requirements of API 620.


3.2.5 3.2.5.1


Inspection Radiographic Inspection The radiographic techniques, acceptance criteria and extent (except where NFPA 59A applies) for the inner tank shall be in accordance with API 620. Radiographic inspection of butt welds in plates shall be in accordance with the requirements of API 620, Q.7.6 and NFPA 59A.

3.2.5.2

Liquid Penetrant Examination Liquid penetrant examination for the inner tank shall be carried out in accordance with API 620. The secondary bottom annular plates shall have the same liquid penetrant examination requirements as the inner bottom annular plates. TCP welds shall have the root pass and the final weld examined by liquid penetrant. The weld between the secondary bottom and the TCP shall have the root pass and the final weld examined by liquid penetrant.

3.2.5.3

Solution Film Testing Vacuum box testing shall be carried out in accordance with API 620. All welds of the roof liner plates shall be vacuum box tested before concrete placement on the roof. Vacuum box testing of the bottom slab and side wall vapor barrier welds shall be completed before covering up the plates. Welds between liner components (e.g. wall liner to bottom liner) shall be vacuum box tested. All secondary bottom, TCP and outer bottom vapor barrier plate welds shall be vacuum box tested. Inner tank bottom plate welds shall be vacuum box tested before and after hydrostatic testing. The inner tank shell-to-bottom Tee joint annular space shall be pressure tested for leakage using a solution film in accordance with API 620, Paragraph Q.8.2.2.

3.3

Insulation Systems

3.3.1

Tank Bottom Insulation System The tank bottom shall be insulated with cellular glass block insulation, which is a load bearing insulation designed to support the tank and product weight.



A concrete bearing ring shall be located under the inner tank shell to distribute the shell loads into the underlying bottom insulation. The cellular glass blocks shall be located between the outer bottom and inner bottom and laid on a concrete leveling course on top of the outer tank bottom. Inter-leaving material shall be placed over the concrete leveling course and between bottom insulation layers to fully develop the strength of the load bearing bottom insulation. A layer of dry sand shall be placed over the cellular glass block bottom insulation prior to installation of the inner tank bottom.

3.3.2

Tank Wall Insulation The annular space between the inner and outer tanks shall be filled with loose fill expanded Perlite and resilient glass wool blanket insulation. The following parameters are applicable to the Perlite that shall be used: 3

3



Perlite density is between 3 lb/ft and 5 lb/ft



Thermal conductivity not greater than 0.305 Btu-in/hr-ft at 32°F



Moisture content limit 0.5% maximum

2

An important consideration for the installation of the Perlite in the annular space is the Perlite vibration after filling. Vibration will be used to settle the Perlite to eliminate potential voids or pockets in the Perlite volume and maximize the insulating value of the system. The design of the LNG Storage Tank shall include a reservoir of Perlite that shall be placed at the top of the annular space to compensate for future, long-term settlement of the Perlite. 3.3.3

Suspended Deck Insulation The outer tank roof shall support a suspended deck above the top of the inner tank. Roof deck plates shall be fully seal welded before the beginning of any glass fiber blanket installation. If a formed plate (trough system) is used, then lapping and fixing details must completely seal against insulation leakage. Identification markers shall be provided to gauge the finished level of blanket insulation by means of easily identifiable colored tape or an acceptable alternative at all roof hangers and deck penetration collars.



At each penetration through the suspended deck there shall be a flexible shroud fitted to prevent fiberglass material from falling into the inner container. 3.3.4

Insulation of Nozzles and Internal Piping Nozzle connections with internal piping located in the LNG Storage Tank dome space shall be provided with thermal distance pieces to allow the line temperature to warm to near ambient temperature at the point of penetration into the roof. The thermal distance pieces shall be insulated with fiberglass blanket to provide insulation between the cold line and distance piece and also to provide a convection stop. The outside insulation layer can be bonded foil or open weave glass fabric and shall be specified during detailed design.

3.3.5 3.3.5.1

Protection of Insulation Storage All insulation materials shall be stored in an enclosed and ventilated dry place and shall be protected against water fr om the time they are dispatched to site until they are required for installation.

3.3.5.2

Installation Adequate provisions shall be made to ensure the complete absence of moisture in the insulation and in the zones where insulation is to be installed. The methods proposed for ensuring dryness shall be specified during detailed design.


4


ANCILLARY EQUIPMENT REQUIREMENTS 4.1

Accessories

4.1.1

Roof Platform The pump platform shall be sized to provide sufficient working space around the pump wells and piping.

4.1.2 4.1.2.1

Access to Platform and Roof Stairways, Ladders and Tank Access A stairway with intermediate landings attached to the outer tank shall be provided to access the roof platforms. This staircase shall provide access from the platform to the tank roof. An emergency escape ladder shall also be provided at a location that is opposite the main roof platform and accessed via a roof walkway. This shall be of the caged ladder type with side stepping platforms. It shall be attached to and supported by the outer tank. Platforms shall be provided on the tank roof for access to the pump columns, nozzles and instrumentation. Stairways with handrails shall provide access to the top of the roof.

4.1.2.2

Internal Tank Ladder Internal tank access shall be provided through roof man-ways. A stairway shall be provided to the inner tank bottom.

4.1.2.3

Walkways and Handrails Handrails for exterior stairways and platforms shall be galvanized.

4.1.3

Cranes/Hoists The pump handling system shall consist of a monorail type hoist. Explosion proof electric motors and components shall be provided to meet hazardous rating requirements.

4.1.4

Supports During detailed design, specifications for the design and supply of reinforced pads, embedments and sleepers for attachment of pipe supports, electrical/ instrument cable, platform, and handrail supports shall be prepared.


4.1.5


Lighting General tank lighting systems shall be provided. Lighting levels shall be as defined in Illuminating Engineering Society of North America (IESNA) recommendation. Emergency escape lighting shall be provided using self contained battery fittings. A dual aircraft warning light shall be provided at the highest point on the tank in accordance with FAA directives. Outdoor convenience receptacles shall be provided at the tank with a minimum of two at the top platform. The electrical system shall be designed in accordance with the National Electrical Code (NEC). To the greatest extent possible, all lighting shall be directed inward to the Terminal and shall consist of low yellow lighting.

4.2

External Piping

In case of earthquake, large displacement of LNG storage tank in the horizontal and vertical directions may be generated due to the lateral motion of the isolators. For the layout design and the strength study of the LNG storage tank external piping, the displacement of LNG storage tank shall be considered. Differential settlement due to ground deformation shall be considered also. 4.3

Pressure and Vacuum Relief Systems

The tank shall be ultimately protected against over-pressure and under-pressure by the provision of pressure and vacuum relief valves. 4.3.1.1

Over-Pressure Protection Over-pressure protection shall be provided by spring-loaded remote sensing pilot operated relief valves. These valves relieve from the inner tank to atmosphere, ensuring that cold gas is not drawn into the dome space in a relief event. When the relief valves lift, cold LNG vapor is discharged to atmosphere. The required relieving rate is dependent on a number of factors, but sizing shall be based on the NFPA 59A Section 4.7.3.2 (2001 ed.) requirement that: “The minimum pressure relieving capacity in kg/hr (lb/hr) shall not be less than 3 percent of full tank contents in 24 hours”. Also, NFPA 59A 4.7.2.1 (2001 ed.) requires: “Sufficient pressure and vacuum relief valves shall be installed on the LNG container to allow each valve to be isolated individually for testing or maintenance while maintaining the full relieving



capacities required.” The number of relief valves shall be determined accordingly. Each valve shall be provided with an inlet isolation valve. Valve discharges shall be independently routed to atmosphere. Each relief valve shall discharge to atmosphere locally at a safe location via a vertical tailpipe. NFPA 59A Section 4.7.2 (2001 ed.) requires: “Relief devices shall communicate directly with the atmosp here.” A safe location is considered to be a minimum of 3m from platforms and walkways and 5m above local grade (tank roof). To protect against the ingress of foreign matter, the tailpipe shall be provided with a coarse screen; and to protect against rain ingress a small bore piped low point drain shall be provided. To protect against snow and ice, the tailpipe shall be provided with appropriate winterization. 4.3.1.2

Under-Pressure Protection Under-pressure protection shall be provided by weight-loaded, pallet-type vacuum relief valves. These valves relieve from atmosphere to the dome space, ensuring, insofar as possible, that moist air is not drawn into the inner tank in a relief event. When the relief valves lift, air is drawn into the tank from the atmosphere. Vacuum relief valves shall be designed in accordance with the requirements of NFPA 59A Section 4.7.2.1 (2001 ed.), which requires that: “Sufficient pressure and vacuum relief valves shall be installed on the LNG container to allow each valve to be isolated individually for testing or maintenance while maintaining the full relieving capacities required.” Therefore, sufficient redundancy shall be installed to provide the total required relief capacity. Each valve shall be provided with a dedicated tank-side isolation valve. Valve inlets will draw independently from the atmosphere. To protect against the ingress of foreign matter, the inlet of each vacuum relief valve shall be provided with a coarse screen; and to protect against rain and snow ingress a protective cowl shall be provided. To protect against ice, each valve shall be provided with winterization. A monorail crane shall be positioned for relief valve service.

4.4

Electrical

4.4.1

LNG Tank Grounding (Earthing) The tank shall be provided with a grounding system. The grounding grid shall consist of stranded copper wire. Grounding electrodes are spaced such that the overall grounding resistance shall not exceed 10 Ohms.


4.4.2


Lightning Protection During detailed design, a complete lightning protection system shall be specified. The system shall be comprised of air terminals, bonding conductors and down conductors on each tank. The down connectors shall terminate at ground busses, which shall be connected directly to the grounding grid ring with insulated grounding cable. The lightning protection system shall be designed in accordance with API 2003 and NFPA 780.

4.4.3

Foundation Heating System Contractor shall determine the need for a foundation heating system to prevent frost heave of the subsoil. If required, the foundation heating system shall consist of a constant wattage cable system installed in parallel galvanized steel conduits. The conduits shall be spaced at appropriate intervals to provide an even heating layer for a designed 100% surplus heating system (available heat versus required heat). The system shall be fully redundant and include: Power Controller, Temperature Controller/Monitor, Temperature Sensors, Heating Cable, Junction Boxes, Marshalling Cabinets and all cables necessary to provide a complete system from the marshalling panels to the under tank components. Foundation heating system monitoring, alarm and status data shall be available through the Terminal DCS system.

4.5

Instrumentation

Contractor shall provide drawings and specifications for the LNG storage tank instrumentation requirements. The following is a summary of the instrumentation systems that shall be installed. 4.5.1.1

Cool-Down Sensors To assist in cool-down and subsequent temperature measurement during commissioning and decommissioning of the tank, resistance temperature detector (RTD) elements shall be installed. All cabling from these RTDs shall be terminated at a junction box external to the tank roof.

4.5.1.2

Temperature Sensors RTD elements shall be placed on the inner shell, the inner container bottom and on the suspended deck. These temperature elements shall be used to monitor the tank temperature during cool-down. RTDs shall be located in the tank bottom annular space for leak detection and they shall be spaced equally around the circumference of the tank.



RTDs shall be located in the vertical portion of the annular space at two different heights. 4.5.1.3

Liquid Level Instruments Each tank shall include two liquid level gauges installed in stilling wells. The gauges shall be servo-motor operated type and shall include field indicators and a data transmitter to allow information to interface with the Terminal DCS system.

4.5.1.4

Tank Gauging and Overfill Protection Requirements The servo type level gauges shall be equipped to provide remote reading and high-level alarm signals in the control room. Each gauge shall be equipped with a transmitter and threshold contact allowing the reading of low level, normal maximum operating level and high-high level with emergency alarm/trip. An independent third instrument for level high alarm and level high-high alarm with trips shall be provided. The trip switches from this third instrument, along with the other two automatic gauges, shall be wired to the SIS system.

4.5.1.5

Density Monitoring An independent level, temperature, density (LTD) system monitor, with density difference alarm, shall be installed. The system shall monitor the level versus temperature versus density profile. This device shall be used to monitor for liquid stratification and potential rollover situations.

4.5.1.6

Procedures for Monitoring and Remediating Stratification The LNG tank shall be equipped with density monitoring instrumentation to indicate stratification and potential rollover problems to allow early action. The LNG storage tank shall be capable of top or bottom filling from an LNG carrier to avoid stratification. In addition, facilities shall be provided to circulate the stored product so that if stratification begins to develop, the tank contents can be thoroughly mixed. This shall involve pumping LNG from the bottom of the tank and returning it to either the top or the bottom as needed.

4.5.1.7

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



Translation and Rotation Movement Indicators Contractor shall provide drawings that illustrate details of translation and movement indicators that shall be designed for the inner tank.

4.6

Painting

4.6.1

Sealing Concrete Outer Surfaces A specification for sealing concrete outer surfaces shall be prepared during detailed design. One option to make the outside surface of the concrete roof and concrete walls water-tight will be by means of a coating or sealer. In this option, the surface will be sweep-blasted and then coated with a light-colored epoxy-based paint. A second option may be to use concrete additives such as Blast Furnace Slag Cement (BFSC), Silica Fume, or Fly Ash cement that may eliminate the need for external coatings on the concrete roof and walls.

4.6.2

Internal Metal Surfaces The internal surfaces of carbon steel liners (bottom, wall, and roof) shall be grit blasted and shop primed, except that a weld strip of approximately 50 mm may be left unprimed. The 9% nickel steel shall be grit blasted only, or grit blasted and shop primed (except for a 50 mm, strip which may be left unprimed) only if the primer is suitable for service at cryogenic temperature.

4.6.3

General Requirements Carbon steel stairs, platforms and pipe supports shall be hot d ip galvanized. Stainless steel, aluminum and galvanized surfaces shall not be painted.

4.6.4

Insulated or Fireproofed Surfaces All external metal surfaces including insulated or fire proofed surfaces, equipment, and piping (excluding stainless steel) shall be coated or painted. Specifications for coating and painting shall be prepared during detailed design.


5


COMMISSIONING REQUIREMENTS 5.1

Hydrostatic/Pneumatic Testing

5.1.1

Hydrotesting of Inner Tank Hydrostatic testing of the inner container shall be in accordance with API 620 Appendix Q.8. Contractor shall prepare hydrostatic test procedures that, in addition to the actual hydrostatic test procedure shall also include the following:

5.1.1.1



Requirements for water quality, including sampling, testing and treatment required to determine suitability prior to use.



Rates at which water is to be pumped into the LNG storage tank. Note: water shall be pumped into the tank at rates not exceeding the limitation set by API 620.



Limits for the period of time that water used for hydrostatic testing shall remain within the tank to prevent corrosion and biological fouling and shall include any requirements for treatment.



Requirements for re-using water for hydrostatic testing of additional LNG Storage Tanks.



Requirements for the disposal of water upon completion of the hydrostatic testing and any treatment prior to discharge. Pressure and Vacuum Testing A pneumatic test of the outer container shall be performed in accordance with API 620 Appendix Q.8. Pump columns shall be tested in accordance with ASME B31.3, Chapter VI, 345.6 - Hydrostatic-Pneumatic Leak Test. The design pressure shall be the pump discharge pressure at shutoff. Prior to the tank hydrotest, the pump wells shall be emptied and sealed.

5.1.1.2

Settlement Monitoring A settlement monitoring system shall be provided to measure and record inner and outer container movements during construction and hydro test. Contractor shall provide details of the survey/reference points and their location around the outer edge of the tank foundation. In addition, settlement of the inner container shall be monitored at the same reference points used for the tank foundation/outer container. Measurements shall be made from the inner container annular plate. Also, a reference point shall be



established on the outer container wall to measure differential settlement between inner and outer containers. Differential settlement and tilting of the foundation shall be monitored and recorded. During the hydro test, settlements, rotation and foundation tilting shall be monitored at approximately each 16-foot increment of water fill height. Measurements shall also be recorded when the tank is emptied. During construction, the settlement of the foundation and inner container shall be monitored on a weekly basis. Contractor shall prepare a detailed civil monitoring specification.

5.2

Calibration

Prior to mechanical completion of the LNG storage tank, the construction contractor shall arrange for calibration of the inner tank by a specialist organization in accordance with the API Manual of Petroleum Management Standard, Chapter 2, Tank Calibration, or other internationally accepted code. The construction contractor shall supply gauge tables or equivalent calibration curves and equations, which relate the actual tank volume under operating conditions and at various product levels to the warm, measured, tank volume. 5.3

Purging

A detailed drying, purging and cooldown procedure shall be provided by the construction contractor.


Job No. 07902


M L (A)

D C B A

20JAN09

11JAN08

Revised based on client comment (Sec.2.2) Revised based on client comment Revised based on client comment Issued for Approval

TH TH TH TH

-

MH MH MH MH

NO.

DATE

DESCRIPTION

PREP’D

CHECKED

APPROVED

28APR08 17JAN08

CAUTION THIS DOCUMENT CONTAINS CONFIDENTIAL AND PROPRIETARY INFORMATION OF IHI CORPORATION. THE DOCUMENT ALWAYS REQUIRES PRIOR WRITTEN CONSENT OF IHI FOR (1) ITS REPRODUCTIONBY ANY MEANS, (2) ITS DISCLOSURETO A THIRD PARTY,OR (3) ITS USE FORANY PURPOSE OTHER THAN THOSE FOR WHICH IT IS SUPPLIED.

CH-IV INTERNATIONAL OREGON LNG FERC FILING PROJECT TANK INSTRUMENTATION SPECIFICATION JOB NO.

TABLE OF CONTENTS 1.0

INTRODUCTION ............................................................................................................3

2.0

TANK GAUGING SYSTEM AND OVERFILL PROTECTION .........................................3

3.0

TEMPERATURE MONITORING FOR LEAK DETECTION.............................................4

4.0

TEMPERATURE MONITORING FOR COOLDOWN......................................................4

5.0

TEMPERATURE MONITORING FOR BASE SLAB ....................................................... 5

6.0

PRESSURE MONITORING............................................................................................5

7.0

TEMPERATURE MONITORING.....................................................................................5

8.0

INNER TANK HORIZONTAL MOVEMENT SYSTEM.....................................................6

JOB NO

1.0

INTRODUCTION This document is to specify the purpose and the general requirement for tank instrumentation. The tank instrumentation comprises the followings. 1) Tank gauging system and overfill protection 2) Temperature monitoring for leak detection 3) Temperature monitoring for cooldown 4) Temperature monitoring for base slab 5) Pressure monitoring 6) Temperature monitoring 7) Inner tank movement system

2.0

TANK GAUGING SYSTEM AND OVERFILL PROTECTION

2.1 Purpose The tank gauging system provides the necessary measurement of product level, temperature and density for tank inventory management and product stratification during normal operation. 2.2 Description The measurement of product level and temperature in the tank will be provided by two level gauges, both equipped to provide remote level reading and level alarm signals in the control room. Each gauge shall be equipped with transmitter and threshold contacts to provide low-low level and high-high level alarms. Both the gauges shall read both level and temperature of the product with multiple temperature sensors. An independent third level gauge for high-high level alarm only shall also be provided. The signal together with the other two tank gauges shall be cabled to the SIS system. A separate level / temperature / density gauge (LTD) shall be provided to monitor the product density at any given level. The LTD shall also monitor the level and temperature at any given density measurement point. The LTD is used to monitor for the onset of product stratification, which can lead to rollover. The use of top and bottom fill lines and product re-circulation ensures that stratification is avoided. A PC based system shall be provided as data acquisition system to collect and manage the data such as level, temperature and density etc. measured by the above tank gauges and shall be provided with hardware and software to permit data transfer to the plant control system by means of serial communications (RS-485 interface).

JOB NO

3.0

TEMPERATURE MONITORING FOR LEAK DETECTION

3.1 Purpose The purpose of the temperature sensor is to monitor the temperature in the annular space between inner tank and outer wall and to generate an alarm when low temperature is detected because of inner tank leakage. 3.2 Description The sensor shall contain a minimum of 4 sensor elements spaced equal around the bottom of the tank annular. At all location, one additional sensor shall be installed on a vertical line along the thermal corner protection to provide an indication of build-up of any liquid inside the annular space. The sensor temperature remains relatively constant and due to the insulation and heat in-leak from outside the tank, it is warmer than the bottom of the inner tank, which will be at the LNG product temperature. In the case of a leakage from the inner tank, the product will enter the annular space and the temperature in the area around the leak will fall. This will be detected by the temperature sensor and an alarm will be raised to control room by plant control system. All the sensors shall be 3-wire RTD (platinum resistance temperature detectors) with a resistance of 100ohms at 32deg.F (0deg.C) and in compliance with IEC 751 Class A.

4.0

TEMPERATURE MONITORING FOR COOLDOWN

4.1 Purpose During tank cooldown, it is necessary to monitor the temperature of the tank shell, bottom and suspended deck so that an adequate temperature profile of the tank can be obtained during the cooldown process to ensure that the tank is being cooled down uniformly and that temperature differences do not occur which would cause unacceptable stresses in the inner tank shell and bottom plates. 4.2 Description A series of sensors shall be located on the inner tank shell, bottom and suspended deck to provide coverage of the complete tank. The temperature elements are routed through nozzles on the tank roof. The number and location of the temperature sensors shall be as follows; a. 13 (thirteen) equally spaced along a vertical line on the outside of the tank shell b. 11 (eleven) distributed strategically along diagonal line on the inside of the tank bottom c. 5 (five) equally spaced along a horizontal line on the suspended deck All cooldown sensors shall be 3-wire RTD (platinum resistance temperature detectors) with a resistance of 100ohms at 32deg.F (0deg.C) and in compliance with IEC 751 Class A.

JOB NO

5.0

TEMPERATURE MONITORING FOR BASE SLAB

5.1 Purpose The temperature sensors are used to know the temperature of the concrete bottom slab. 5.2 Description A continuous temperature monitoring shall be provided for the base slab. The temperature monitoring shall consist of 24 temperature sensors distributed over the base slab. The design could be based on demonstrable previous installation experience. All the sensors shall be 3-wire RTD (platinum resistance temperature detectors) with a resistance of 100ohms at 32deg.F (0deg.C) and in compliance with IEC 751 Class A.

6.0

PRESSURE MONITORING

6.1 Purpose The instrument is used for the BOG compressor control to keep pressure in storage tank within allowable pressure and for over and vacuum pressure protection. 6.2 Description Pressure transmitter for the bellow pressure measurement requirements is provided for storage tank. Absolute tank pressure for BOG compressor control Gauge tank pressure for over and vacuum pressure protection and emergency shutdown (ESD)

7.0

TEMPERATURE MONITORING

7.1 Purpose The purpose of the temperature sensor is to monitor the temperature in the vapor space under the suspended deck and to generate an alarm when the temperature in the vapor space is increased due to some reasons. 7.2 Description The sensor shall be installed under suspended deck to monitor the temperature of the vapor space in storage tank. The sensor shall be 3-wire RTD (platinum resistance temperature detectors) with a resistance of 100ohms at 32deg.F (0deg.C) and in compliance with IEC 751 Class A.

JOB NO

8.0

INNER TANK MOVEMENT SYSTEM

8.1 Purpose Inner tank movement indicators are provided to monitor radial and rotational measurement of inner tank during cooldown and normal operation. 8.2 Description Radial and rotational movement indicators shall be provided in the annular space between inner tank and outer wall. Radial and rotational movement of the inner tank shall be determined assuming the two measured points lie on a circle, and that the radial thermal shrinkage at each position relative to the tank’s center is equal and repeatable. Radial and rotational movement of the inner tank shall be measured relative to the TCP inner wall using the sensors located at two orthogonal tank positions. Two sensors shall be provided for radial and rotational movement respectively at each location.

JOB NO

M L (A)

C

18JAN08

Revised based on client comment

TH

-

MH

B A

17JAN08

Revised based on client comment Issued for Approval

TH TH

-

MH MH

NO.

DATE

PREP’D

CHECKED

APPROVED

11JAN08

DESCRIPTION

CAUTION THIS DOCUMENT CONTAINS CONFIDENTIAL AND PROPRIETARY INFORMATION OF IHI CORPORATION. THE DOCUMENT ALWAYS REQUIRES PRIOR WRITTEN CONSENT OF IHI FOR (1) ITS REPRODUCTION BY ANY MEANS, (2) ITS DISCLOSURETO A THIRD PARTY,OR (3) ITS USE FORANY PURPOSE OTHER THAN THOSE FOR WHICH IT IS SUPPLIED.

CH-IV INTERNATIONAL OREGON LNG FERC FILING PROJECT TYPICAL SPECIFICATION FOR LEVEL/TEMPERATURE/DENSITY MONITORING, LIQUID LEVEL GAUGING AND OVERFILL PROTECTION SYSTEM JOB NO.

５０２５－８ＣＤ

Electrical & Control Dept. TEL 036204-7615

Environmental & Plant Div.

DRAWING NO.

07902-TS-200-204/S7721-9001

IHI Corporation

REV.

C

1 ／21

TABLE OF CONTENTS 1.0

SCOPE ......................... ........................... ......................... ........................... ....................... 3

2.0

CODE AND STANDARD ................................................................................................... 3

3.0

ENVIRONMENTAL CONDITIONS............................ ........................... ............................. . 4

4.0

GENERAL REQUIREMENTS .......................... ........................... ............................ ........... 4

5.0

IDENTIFICATIONS PLATES ............................................................................................. 4

6.0

FACTORY ACCEPTANCE TEST ...................................................................................... 5

7.0

SITE ACCEPTA CE TEST .......................... .......................... ............................ .................. 5

8.0

TECHNICAL INFORMATION (DOCUMENTATION) ......................................................... 6

9.0

INDIVIDUAL SPECIFICATION .......................................................................................... 6 9.1 Level gauging........................ ........................... ......................... ........................... ........... 6 9.2 Temperature monitoring................ ........................... ........................ .......................... ..... 7 9.3 Density monitoring ....................... ............................ .......................... ............................ . 7 9.4 Level gauging for high-high level protection ........................ .......................... ................. 8 9.5 Data acquisition system ........................ ........................ ........................ .......................... 8

ATTA CHMENT-1 VENDOR BROCHURE FOR LEVEL GA UGE ATTA CHMENT-2 VENDOR BROCHURE FOR LTD ATTA CHMENT-3 TYPICAL SYSTEM CONFIGURATION FUL LY REDUNDANT ARCHITECTURE

JOB NO

５０２５－８ＣＤ

Electrical & Control Dept. Environmental & Plant Div.

DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

2 / 21 E399-008

1.0

SCOPE This specification defines general requirements for the design and supply of TANK GAUGING SYSTEM (including separate high-high level gauge) for tank inventory management. TANK GAUGING SYSTEM shall be composed of the following equipment.

2.0

・Level Gauging with multi-type temperature sensor

; 2 sets

・Level, Temperature and Density Monitoring

; 1 set

・Level Gauging for high-high level protection

; 1 set

・Data Acquisition System

; 1 set

CODE AND STANDARD TANK GAUGING SYSTEM design and materials shall comply with latest editions of codes and standards listed below: NEMA Publications NEMA 250

Enclosures for Electrical Equipment

API Pu bl ic ati ons API RP 2350

Overfill Protection for Storage Tanks in Petroleum Facilities Second Edition

API MPMS Chapter 2

Tank Calibration (Section 2A, 2B)

API MPMS Chapter 3

Tank Gauging,

Section 3

Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank Gauging

API MPMS Chapter 7

Temperature Determination

Section 4

Temperature Determination Using Thermometer

API MPMS Chapter 11.1

Volume Correction Factors Table

API MPMS Chapter 12

Calculation of Petroleum Quantities

Fixed

Automatic

Tank

ASME Publ ic ati ons ASME B16.5

Pipe Flanges and Flanged Fittings.

ASME B31.3

Process Piping

ASME B46.1

Surface Texture (Surface Roughness, Waviness and Lay)

NFPA Publications NFPA 59A

Production, Storage and Handling of Liquefied Natural Gas (LNG) JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

3 / 21 E399-008

3.0

ENVIRONMENTAL CONDITIONS The system described herein for LNG Terminal Plant; the site is located in NE King Ave, Warrenton, OR. The site conditions are stated in the Design Basis, 07902-TS-000-002.

4.0

GENERAL REQUIREMENTS The field equipment composing TANK GAUGING SYSTEM installed in process areas shall comply with the following area classification and protetction class for the enclosure. Area classification

: Class 1, Division 2, Group C&D

Protection class

: NEMA 4X or equal

Power supply (from UPS)

: VAC, single phase, Hz (TBA)

TANK GAUGING SYSTEM shall be designed in accordance with this specification. Process connection shall be in accordance with piping class and shall be as indicated in this specification. The manufacturer will be responsible for the right performance of TANK GAUGING SYSTEM under the following conditions. Tank details Stored liquid

: LNG

Stored liquid density

: (HOLD) lb/ft3 (TBA)

Design min./max. temperature

: -270deg.F/Ambinet

Design min./max. pressure

: -0.073/4.3psig

Design max. liquid level

: 118.630ft

The manufacturer will give all equipments for TANK GAUGING SYSTEM with ending and necessary coating to resist the environmental conditions mentioned in clause 3.0. It is accepted the epoxy resin like a protective coating against the corrosion. Instrument color shall be the manufacturer's standard unless otherwise specified.

5.0

IDENTIFICATIONS PLATES All instruments shall be provided with an identification plate, with all data clearly and deeply stamped on a corrosion-resistant plate permanently attached to the transmitter by means of rivets or pins. The following information, but not limited to, shall be provided; -

-

Instrument tag number Manufacturer’s name or trade mark Manufacturer’s model number Manufacturer’s serial number Body rating including units Electrical safety “type of protection” and enclosure Range including units of measure Output signal including units JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

4 / 21 E399-008

Notes: 1. Manufacturer’s model number should include type of measuring element material and type of fill fluid and if applicable the range elevation. 2. Electrical safety “type of protection” identification shall be identical to the one specified in this specification. 3. Each transmitter shall be provided with a stainless steel tag plate that shall be fixed with a stainless steel wire to the transmitter. This plate shall show the purchaser’s tag number as stated in the requisition/indent.

6.0

FACTORY ACCEPTANCE TEST Manufacturer will be responsible for procedures and/or tests programs to be followed to guarantee the right performance of the TANK GAUGING SYSTEM. The responsibility for production test rests with the manufacturer. Before TANK GAUGING SYSTEM is delivered to site, satisfactory performance of TANK GAUGING SYSTEM shall be demonstrated to CONTRACTOR and client or their representative. Client or their representative shall witness the test prior to releasing the equipment for shipment. The manufacturer shall be responsible for conducting the tests and providing all necessary facilities, equipment and personnel. Unless otherwise specified, inspection by CONTRACTOR shall be restricted to the following as a minimum: - Visual examination and dimensional check - Verification of hydraulic, functional and electrical test, and characteristic and accuracy checks for each equipment - Verification of functional test for the whole system - Verification of electrical safety “type of protection” certificate or declaration - Verification of material certificate (if applicable) - Verification of calibration certificate The final acceptance, on the part of CONTRACTOR, will be made TANK GAUGING SYSTEM installation place.

7.0

SITE ACCEPTACE TEST The manufacturer shall demonstrate, to CONTRACTOR and company that the scope of work has been accomplished in accordance with the “Site Acceptance Test Procedure” that the requirements of the test shall be defined. The test shall prove that the various systems have not been damaged during transportation and are installed correctly. Communication test between TANK GAUGING SYSTEM and Terminal DCS shall be done as Site Acceptance Test.

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

5 / 21 E399-008

8.0

TECHNICAL INFORMATION (DOCUMENTATION) The manufacturer shall provide the following documentation, as a minimum, including drawings and technical specification where TANK GAUGING SYSTEM design characteristics and manufacturing details are shown; - General arrangement / Dimensioned drawings - Fully detailed termination and wiring diagrams - Software - Installation, operation and maintenance manual - Commissioning spare list, if any - Spare quotation for 2 years operation - Packing list complete with shipping weights and dimensions - Factory and site test procedures - Communication list with terminal DCS In addition to the required “test and inspection documents” the manufacturer shall supply a certificate stating that the TANK GAUGING SYSTEM comply in all respects with this description, the specification and the purchase order including the test requirements, for the complete TANK GAUGING SYSTEM.

9.0

INDIVIDUAL SPECIFICATION

9.1 Level gauging The specification for the level gauge is as follows. Transmitter shall be equipped with threshold contact in addition to serial link. The transmitter shall communicate with data acquisition system with serial link as well as send contact signal to SIS system directly. Vendor brochure is attached as Attachment-1 for reference. Type

: Servo driven displacer gauge

Nozzle Connection

: 6” ANSI 150# RF

Measuring Range

: 0 to 120ft

Accuracy

: Within ±2mm

Material

: Housing

: Cast aluminum

Measuring tape : Stainless steel Displacer

: Stainless steel

Others

: Manufacturer’s standard

Power Cable Entry Thread : Min. 1/2” NPT Signal Cable Entry Thread

: Min. 1/2” NPT JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

6 / 21 E399-008

9.2 Temperature monitori ng 9.2.1 Temperature sensor The specification is as follows.The temperature sensors shall measure the temperature of liquid and vapor contained in LNG tank, consisting of sixteen (16) spot resistance temperature detectors (RTD) spaced for the length of the probe and covering the tank available level. The output shall be transmitted to the multiple temperature interface. Nozzle Connection

: 2”ANSI 150# RF

Overall Length

: (HOLD) ft (TBD at detail engineering stage)

Sensitive Length

: (HOLD) ft (TBD at detail engineering stage)

9.2.2 Multiple temperature interface The specification is as follows. The temperature interface shall transmit temperature data measured by the above temperature sensor to data acquisition system with serial link by means of the level gauge described in clause 9.1. Measuring Range

: -328 to 122deg.F

Accuracy

: Within ±0.2deg.C

Material

: Housing Aluminum

Signal Cable Entry Thread

: Min. 1/2” NPT

9.3 Density monitoring Combined Level, Temperature and Density (LTD) gauge shall be provided to measure level, temperature and density of liquid stored in LNG tank continuously and shall be used to prevent risk of “Rollover”. The specification for the LTD gauge is as follows. Vendor brochure is attached as Attachment-2 for reference.

Nozzle Connection

: 6” ANSI 150# RF

Measuring Range

: 0 to 120ft 25.0 to 31.2lb/ft3 -328 to 32deg.F

Accuracy

Material

: Level

: Within ±2mm

Density

: Within ±0.5kg/m3

Temperature

: Within ±0.1deg.C

: Housing

: Cast aluminum

Measuring tape : Stainless steel LTD sensor

: Stainless steel

Others

: Manufacturer’s standard JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

7 / 21 E399-008

Power Cable Entry Thread

: Min. 1/2” NPT

Signal Cable Entry Thread

: Min. 1/2” NPT

9.4 Level gauging for high -high level protection The specification for the level gauge for high-high level protection is as follows. Transmitter shall be equipped with threshold contact. The transmitter shall send contact signal to SIS system directly. Type

: Servo driven displacer gauge or radar gauge

Nozzle Connection

: 6” ANSI 150# RF

Measuring Range

: 115 to 120ft

Accuracy

: Within ±2mm

Material

: Housing

: Cast aluminum

Measuring tape : Stainless steel Displacer

: Stainless steel

Others

: Manufacturer’s standard

Power Cable Entry Thread : Min. 1/2” NPT Signal Cable Entry Thread

: Min. 1/2” NPT

9.5 Data acquisitio n system Data acquisition system shall consist of computer with windows based program, printer and communication interface unit. The computer and printer shall be installed in control room and communication interface unit shall be mounted in a cabinet installed in cabinet room. The system shall receive all data from the field instruments composing TANK GAUGING SYSTEM except level gauge for high-high level protection and display them. The system shall transfer the required data to terminal DCS with serial link. Typical system configuration fully redundant architecture is shown in Attachment-3.

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

8 / 21 E399-008

At tac hm ent-1 Vendor Br oc hu re f or Level Gauge

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

9 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

10 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

11 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

12 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

13 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

14 / 21 E399-008

At tac hm ent -2 Vendo r B ro ch ur e fo r L TD

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

15 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

16 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

17 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

18 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

19 / 21 E399-008

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

20 / 21 E399-008

At tac hm ent -3 Typic al Syst em Conf igur ati on Ful ly Redundant Ar ch it ect ur e

JOB NO

５０２５－８ＣＤ


DRAWING NO.

REV.

07902-TS-200-204/S7721-9001

IHI Corporation

C

FORM

21 / 21 E399-008


Job No. 07902


M L (A)

B A

21.Apr.08

NO.

DATE

17.Mar.08

DESCRIPTION

CAUTION THIS DOCUMENT CONTAINS CONFIDENTIAL AND PROPRIETARY INFORMATION OF IHI CORPORATION. THE DOCUMENT ALWAYS REQUIRES PRIOR WRITTEN CONSENT OF IHI FOR (1) ITS REPRODUCTIONBY ANY MEANS, (2) ITS DISCLOSURETO A THIRD PARTY,OR (3) ITS USEFOR ANYPURPOSE OTHER THAN THOSE FOR WHICH IT IS SUPPLIED.

EL 81-3-6204-7617

For Review For Review

H.T H.T

T.H T.H

T.K T.K

PREP’D

CHECKED

APPROVED

CH-IV INTERNATIONAL OREGON LNG FERC FILING PROJECT TYPICAL SPECIFICATION FOR TANK CIVIL MONITORING

Civil & Architectural G. Engineering Dept. Environmental & Plants Operations

JOB NO.

５０２５－８ＣＤ DRAWING NO.

07902-TS-200-205

IHI Corporation

REV.

B

1 ／7

TABLE OF CONTENTS

1.0

2.0

3.0

4.0

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

Purpose of Monitoring.............. ........................... ......................... ........................... .......... 3

1.2

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

1.3

Reference Documents .......................... ......................... ........................ .......................... . 3

GENERAL REQUIREMENT ........................ .......................... ............................ ...................... 4 2.1

Survey / Reference Points ......................... ........................ .......................... ..................... 4

2.2

Tilting of the Base Slab............................. .......................... .......................... .................... 4

2.3

Settlement Monitoring .......................... ......................... ......................... ........................... 4

OPERATION OF MONITORING ............................ .......................... ........................... ............ 6 3.1

Settlement Monitoring .......................... ......................... ......................... ........................... 6

3.2

Tilt of Foundation ......................... .......................... ........................ .......................... ......... 6

3.3

Criteria of Differential Settlement ............................ .......................... ........................... ..... 6

FREQUENCY OF MONITORING ............................. ........................... .............................. ...... 7

Civil & Architectural G. Engineering Dept. Environmental & Plants Operations.

JOB NO


07902-TS-200-205

REV.

B

2 ／7

1.0 INTRODUCTION 1.1

Purpose of Monitoring Purpose of the monitoring of foundation is to verify the structural stability and to take corrective action when excessive settlement will be occurred. The needs for monitoring is specified in NFPA 59A.

1.2

Scope This document specifies the requirements for the monitoring system to measure the settlement and gradient of the tank foundation for each tank during construction and hydrostatic test and operation.

1.3

Reference Documents -NFPA 59A “Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG) 2001 Edition” - Federal Energy Regulatory Commission, “Draft Seismic Design Guidelines and Data Submittal Requirements for LNG Facilities”


JOB NO


07902-TS-200-205

REV.

B

3 ／7

2.0 GENERAL REQUIREMENT 2.1

Survey / Reference Points A minimum of 8 measuring anchors (to be used as survey / reference points) shall be installed at equally spaced locations around the outer top edge of the base slab.Figure 2-1 show the plan of arrangement of location for measuring anchor.

2.2

Tilting of the Base Slab The differential settlements and tilting of the base slab will be monitored and recorded by using horizontal inclinometer. Casing embedded along two perpendicular lines in the base slab. The inclinometer sensor will be furnished complete with control and pull cables plus the storage reels. Figure 2-2 show the plan of arrangement of location for horizontal inclinometer casing.

2.3

Settlement Monitoring During the construction, settlement of the base will be monitored after completion of base slab as initial value. During the hydrostatic test, settlements and base slab tilting will be monitored at appropriate interval.

Fig.2-1 Plan - Arrangement of Measuring Anchor


JOB NO


07902-TS-200-205

REV.

B

4 ／7

Fig.2-2 Plan - Arrangement of Horizontal Inclinometer


JOB NO


07902-TS-200-205

REV.

B

5 ／7

3.0 OPERATION OF MONITORING 3.1

Settlement Monitoring A fixed point will be established as a benchmark in advance, and shall be located so that it will not be affected by the foundation settlement. The construction benchmarks established for this project’s construction can be used as a fixed reference point. After pouring the concrete for the tank foundation, the measuring anchors will be installed, and an initial set of data will be immediately measured and recorded. Each measurement is conducted using a level during the construction stage and the hydrostatic test and operating stage.

3.2

Tilt of Foundation The center of the tank foundation will also be monitored using proper equipments typically an inclinometer. A survey will be performed immediately following the completion of the slab concrete work, and just before the start of the hydrostatic test. During hydrostatic testing operations, the center of the slab will be monitored with the same frequency as established for the periphery monitoring.

3.3

Criteria of Differential Settlement Table 3-1 provides the differential settlement limits. Table 3-1 Differential Settlement Limits Type of settlement

Differential settlement limit

Planar tilt angle of the tank foundation

< 0.002 radian

Tank floor settlement along a radial line from the tank center

1:300

Any 2 points on the tank circumference (not to exceed the tank settlement)

1:500

Source : Section 7.4.1 “Draft Seismic Design Guidelines and Data Submittal Requirements for LNG Facilities.”


JOB NO


07902-TS-200-205

REV.

B

6 ／7

4.0 FREQUENCY OF MONITORING Frequency of monitoring is tabulated below. Table 4-1 Frequency of Monitoring Method of Measurement

Location

Frequency During construction

Criteria Weekly

(1) Just before water filling Settlement Monitoring

Perimeter of bottom slab

During Hydro-testing

(2) At increments of 16.0 ft liquid level during filling

Table3-1

(3) After empting of the tank During operation

Yearly

During construction

After completion of Base sla b (1) Just before water filling

Tilt of Foundation

Center of bottom slab

During Hydro-testing

(2) At increments of 16.0 ft liquid level during filling

Table3-1

(3) After empting of the tank During operation


Yearly

JOB NO


07902-TS-200-205

REV.

B

7 ／7


Job No. 07902


M L (A)

A

21NOV07

NO.

DATE

Issued for Approval DESCRIPTION

CAUTION THIS DOCUMENT CONTAINS CONFIDENTIAL AND PROPRIETARY INFORMATION OF IHI CORPORATION. THE DOCUMENT ALWAYS REQUIRES PRIOR WRITTEN CONSENT OF IHI FOR (1) ITS REPRODUCTIONBY ANY MEANS, (2) ITS DISCLOSURETO A THIRD PARTY,OR (3) ITS USEFOR ANYPURPOSE OTHER THAN THOSE FOR WHICH IT IS SUPPLIED.

-

-

MT

PREP’D

CHECKED

APPROVED

CH-IV INTERNATIONAL OREGON LNG FERC FILING PROJECT AL A L L OY VERIFICATION VERIFICATION PROCEDURE JOB NO.

５０２５－８ＣＤ

Tank Project Dept. TEL 036204-7607

Environmental Environmental & Plant Div.

DRAWING NO.

REV.

07902-TS-200-202/ S4000-3315

A

IHI Corporation

1 ／8

TABLE OF CONTENTS

1.0

Sco pe ....................... ........................... ......................... ......................... ........................... 3

2.0

Referenc e Docu ment s ................ ....................... ............... ................ ................ ............... ............... ................ ............... ............... ................ ............... ....... 3

3.0

Inst rum ents and Metho d .............. ...................... ................ ................ ................ ................ ................ ................ ................ ................ ................ .......... .. 3 3.1

Verification Procedure .......................... ......................... .......................... .................... 3

3.2

Instruments and Method.......................... Method .......................... ........................ ........................... ................. 3

4.0

Ext ent of Verif icatio ic atio n ............... ....................... ................ ............... ............... ................ ................ ................ ............... ............... ................ ................ .......... 4

5.0

Termi nol ogy ............... ....................... ................ ................ ............... ............... ................ ................ ................ ................ ............... ............... ................ ...............5 .......5

6.0

Ac cep tan ce Cr it eri a .......................... .......................... ............................ ........................ 5

7.0

Reject ion io n Crit eria ............... ....................... ................ ................ ............... ............... ................ ................ ................ ............... ............... ................ ............... ....... 5

8.0

Perso nnel ................ ....................... ............... ................ ............... ............... ................ ................ ................ ................ ................ ............... ............... ................ ........... ... 6

9.0

Mark in g ...................... ........................... ......................... ........................... ....................... 6

10.0

Surf ace Treatment ................ ........................ ................ ................ ................ ................ ................ ................ ............... ............... ................ ................ ........... ... 6

11.0

Recor d ............... ....................... ................ ................ ............... ............... ................ ................ ................ ................ ............... ............... ................ ................ ............. ........ ... 7

JOB NO

Tank Project Dept. Environmental Environmental & Plant Div.


07902-TS-200-202 / S4000-3315

REV.

A

2 ／8

1.0

Scope This document specifies the basic requirements for carrying out the Positive Alloyed Material Identification (PAMI) for equipment and piping material for determining the nominal composition of the mechanical components. The extent of the parts to be checked, sampling requirements, approved testing methods, acceptance/rejection criteria, and marking requirements is also covered in this document.

2.0

Reference Reference Document s ASME Section II (2004 Edition), Part A, Ferrous Materials Part B, Non-Ferrous Materials Part C, Welding rods, Electrodes and Filler Materials ASTM Standard Test Methods A751 – Chemical Analysis of st eel products E353 – Chem. Analysis of Stainless, Heat-Resisting, Mar aging and other Similar Chromium-Nickel-Iron alloys. E354 – Chemical Analysis of High-Temperature, Electrical, Magnetic and similar Iron, Nickel and Cobalt Alloys.

3.0 3.0

Instruments and Method Method

3.1 Verification Procedure (a)

The components of 9%Ni steel shall be checked by metascope, handy type X-Ray fluorescence alloy analyzer or equivalent appropriate analyzer. The X-ray emission analysis with calibrated portable instrument shall be used. The applicable equipment shall be demonstrated and operation procedure, sample removal (as applicable), identification and traceability to original material shall be submitted for approval.

(b)

An alternative chemical analysis for the above analytical method (as per ASTM ASTM A751, E353, E354) shall be used to establish conformance to the original material specification.

3.2 Instruments and Method (a)

Calibrated portable Instrument: TEXAS NUCLEAR 9266, TEXAS NUCLEAR 9277, PRINCETON GAMMA 840, PRINCETON GAMMA TECH 880 or PITCHFORD PORTA SPEC.ANALYSER 4000

(b)

After fabrication or where X-ray device is not possible, metascope may be utilized for PAMI. The selection of instrument to be used for PAMI shall take into the account, material type/ thickness/hardness requirements and surface finishes.

(c)

Spectroscopic analysis by recognized ASTM ASTM or approved equivalent method.

JOB NO

Tank Project Dept. Environmental Environmental & Plant Div.


07902-TS-200-202 / S4000-3315

REV.

A

3 ／8

(d)

As an alternative to the methods specified above, a chemical analysis, as outlined in ASTM A751, ASTM E353, and ASTM E354, shall be used to establish conformance to the original material specification.

(e)

Alternate analytical methods or instrument other than those listed above shall be utilized with the prior review and approval of the Company.

4.0

Extent of Verific ation a) Alloy verification of all alloy (9% Ni or 304 SS) primary components as defined by API 620, the secondary containment, welds, and any components in cryogenic service is required. b) Requirement of PAMI: (1) Pressure containing materials / mechanical components in critical 100% PAMI unless otherwise specified.

services shall

undergo

(2) Pressure containing and non-pressure containing components shall meet the requirement specified in Table I – "Extent of PAMI". c) Alloy elements covered in the Identification includes Chromium (Cr), Cobalt (Co), Columbium or Niobium (Cb or Nb), Copper (Cu), Iron (Fe), Molybdenum (Mo), Nickel (Ni), Titanium (Ti) and Vanadium (V) d) PAMI may be performed by the mill material manufacturer, fabricator, supplier (or mill stockist) or by authorized third-party representative. The implementation and the conduct of the PAMI will be in accordance with this document. e) The test method will be used only to identify the nominal composition of alloy materials and not for conforming a material to a particular alloy specification. PAMI of the weld material (weldment) and base metal shall be performed in the same method. f)

PAMI shall be performed to ensure that proper materials have been used in the fabrication at the supplier’s shop or at the project site for field welds and for field-assembled item not previously positively identified.

g) The mill test reports listing chemical composition shall neither be a substitute for PAMI nor be considered as a conforming alloy verification. h) One electrode or wire sample from each lot shall be positively fabricated piping. As an alternative the PAMI of undiluted weld metals carried out immediately prior to welding. The color coding wires/electrodes shall be compared with the sample. Dissimilar weld at shop & site shall be done.

identified for shop/site in button welds shall be and identification of deposits actually made

i)

Mill stockist materials shall apply 100% PAMI except for the bolting components.

j)

PAMI verification of base metal composition shall be performed for auto generous welded pipe and fittings only on base metal composition.

JOB NO

Tank Project Dept. Environmental & Plant Div.


07902-TS-200-202 / S4000-3315

REV.

A

4 ／8

5.0

Terminology Alloy Material – Any measurable quantity alloying materials other than carbon, manganese, silicon and niobium or vanadium. Steels with carbon only up to 2% are not considered as alloy steels and silicon and manganese are limited to 0.60 and 1.65 % respectively. Mill Material Manufacturer – An organization that performs or supervises and directly controls one or more of the operations that affect the chemical composition of an alloy material Pressure containing component – The component, which lies within the limits of pressure containing equipments. Non-pressure containing component - The component, which does not lies within the limits of pressure containing equipments and therefore do not affect the pressure retaining capacity in any way.

6.0

Acc eptance Criteri a Items

Standards Specifi ed

Ferrous materials

Same as materials chemical composition specified in the ASME Section IIA

Non-Ferrous material

Same as materials chemical composition specified in the ASME Section IIB (or equivalent ASTM specification for Non-ferrous materials.

Welding consumables

±10% of the amount of each alloying element specified in ASME IIC.

For casings

within ±10% of the minimum and maximum values permitted by ASTM Material specification

For deposited weld metals within ±12.5% of the ranges allowed by ASME Section IIC for each or undiluted weld metal element. deposits

7.0

Rejecti on Criteri a a) In case of any materials were found outside the acceptable range, a “referee” method shall be referred by the material specification shall be used. Otherwise an appropriate chemical analysis method specified as per standard shall be used and the analysis results shall be considered. b) In case of failure of PAMI in material component or weld all other represented materials, components and welds, the following decision will be taken (1) Materials, Components and welds representing the rejected sample shall be scrapped and replaced by new materials. (2) 100% PAMI will be conducted on the represented materials and items failing the PAMI tests will be replaced. c) If a filler metal lot is found to be unacceptable, the next lot or lots from the same supplier shall be 100% examined. If both the lot or the successive lots are acceptable, the sampling percentage as in section 4 shall be followed. d) The rejected items shall be quarantined and properly identified to prevent their unauthorized use or removal.

JOB NO



07902-TS-200-202 / S4000-3315

REV.

A

5 ／8

8.0

Personnel PAMI performed by supplier or a third party agency shall be certified by the fabricator or supplier (mill stockist) that all the PAMI tests have been performed by qualified personnel in accordance with the approved procedure. The personnel performing PAMI shall be competent in performing verification method to be used, and also familiar with the requirements/ period during when verification will be conducted of this specification along with the method of marking the verified materials.

9.0

Marking Acceptable components and material shall be marked "AV". The items, covered by percentage verification (same batch), but have not been tested, shall be marked with the letters “AV-B”. All components of an approved heat/lot shall be stamped "AV" or "AV-B", as appropriate at the time of testing. The method of marking shall be by low-stress stamp stencil or vibro-etching, The marking shall be placed as follows. a) Pipe - Two marks, 180 degrees apart, 75mm (3 in.) from each end of each length on the outer surface of the pipe. b) Welds - Adjacent to the welder's mark on the weld. c) Fittings and Forgings - Adjacent to the supplier's markings. d) Valves - Adjacent to the supplier's markings on bodies and other pressure parts. e) Plates - Adjacent to the heat / lot numbers. f) Castings - Adjacent to the supplier's markings and heat / lot numbers. g) Bolting - On one end. h) Nuts - On one flat. If the material or item is too light, too small, or cannot otherwise be stamped, vibro-etching or color coding shall be applied in conjunction with supplier's standards and noted on the alloy verification reports. When heat treating is performed after material verification, the identification marking must be recognizable after the heat treatments. Materials that are found unacceptable and pending the resolution shall be marked with a circled red cross ( ).

10.0

Surface Treatment After PAMI the tested (intended) surface shall be smoothly finished by grinding or by filling with emery paper or with smooth files.

JOB NO



07902-TS-200-202 / S4000-3315

REV.

A

6 ／8

11.0

Record Results of examinations shall be recorded on examiner’s report forms, which shall, as a minimum, indicate for each lot examined:

•

Name and Address of Manufacturer

•

P.O./Contractor Number

•

Item Number and Name of the Fabricated Equipment and Piping

•

Location where the test was taken

•

Date of Examination

•

Name and Signature of Examiner

•

Description of Method/Instrument Number used in the analysis

•

Result of all examinations

•

Type of alloy examined per location

•

Conclusion (i.e. ”Accept” or “Reject”)

•

Mill certificate/Heat Number

•

Lot size as per/ASTM Materials standard

•

Number of places, items examined

•

Description of Material Marking

JOB NO



07902-TS-200-202 / S4000-3315

REV.

A

7 ／8

Table I — Extent of PAMI Item LNG Tank

Piping system after assembly Pressure containing alloy components

Non-pressure containing alloy components

Fabrication at Vendor's shop

Site fabrication and Erection

Remarks

9% Ni plate and their attachment

100%

100% (Note (1))

Welds

10% of all welds

10% of all welds

Pipe, flanges, fittings, forgings

5% of each heat / lot (Note (2))


Welds

10% of all welds

10% of all welds

Pipe, flanges, fittings, forgings


—

Minimum 4 pcs.

Minimum 4 pcs.

Valve body and bonnet

10% of each heat / lot

—

Alloy body and bonnet valves shall be alloy verified. Minimum 5 pcs.

Bolts, studs, nuts

1% of each alloy heat / lot (Note (3))

—

Minimum 4 pcs.

Weld consumables

One electrode or wire sample from each lot of weld rod.

One electrode or wire sample from each lot of weld rod.

Bolts, studs, nuts

1% of each alloy heat / lot (Note (3))

—

Piping Bulk Components

Note: (1) Alloy component which has been alloy verified in the Supplier's shop need not be re-verified in the field. made to modify prefabricated assemblies, shall be alloy verified.

Minimum 4 pcs.

However, any additional materials, and welds

(2) Component parts that can not be identified as originating from an approved heat/lot shall be 100% virified. (3) A193 B7(M) and A320 L7(M) exempted from PAMI requirement.

JOB NO



REV.

07902-TS-200-202 / S4000-3315

IHI Corporation

A

FORM

8 ／8 E399-008


Job No. 07902

Resource Report 13 18 CFR 380.12(o)


Job No. 07902


Oregon LNG Warrenton, OR LNG Storage Tank Rollover Assessment

Job No. 07902 Doc No. 07902-TS-200-206 Rev 0 Page 1 of 8

LNG Storage Tank Rollover Assessment

By H H

C H

R EV NUMBER : ISSUE PURPOSE:


H


0 Draft for Client Review 6/3/08 MS MHD RCT

1 Bi-Directional Facility 8-1-12 MS AAR AAR


Section


Page

1

INTRODUCTION ..................................................................................................... 3

2

INDUSTRY GUIDELINES ...................................................................................... 4

3

MONITORING, PREVENTION AND MITIGATION OF STRATIFICATION AND ROLLOVER .................................................................................................... 5 3.1

Monitoring for Stratification ..................................................................................... 5

3.2

Prevention of Stratification.............................................. .......................................... 6

3.3

Mitigation of Rollover ................................................................................................ 7


1


INTRODUCTION Rollover is a phenomenon that can result in a rapid pressurization of an LNG storage tank, caused by heat leak into a tank containing two layers of LNG with differing densities. To illustrate the concept of rollover, first consider the condition of a well-mixed, homogenous LNG storage tank, as shown in Figure 1. In this homogenous tank, the convective flow driven by heat leak into the LNG creates a natural circulation. The “warm” fluid moves up the tank walls and across the liquid surface where excess heat is released to generate boiloff gas. This evaporation of LNG reduces the liquid temperature, and the cooler liquid then drifts downward completing the cycle. Normal Rate of Boiloff Gas Generation

Reduced Rate of Boiloff Gas Generation

Rapid Rate of Boiloff Gas Generation

Evaporation

Evaporation

Rapid Flashing

Lighter Convection Cell

Layer Rapid Mixing of Two Layers

Convection Cell Heavier

Homogenous LNG

Layer

Stratified LNG

Tank Experiencing Rollover

Figure 1: Comparison of Homogenous and Stratified LNG Storage Tanks

In the stratified tank shown in Figure 1, the less dense upper layer convects normally and releases heat by flashing boiloff into the tank vapor space. The convective boundary in the dense lower layer, however, is unable to penetrate the upper layer and it forms its own convection pattern. Heat leak into the lower layer cannot be removed by surface evaporation, so the thermal energy is trapped. As the temperature of the lower layer increases, its density decreases. When both layers achieve virtually the same density at the interface, there is a near immediate, very rapid mixing and release of the “postponed” boiloff , resulting in a rollover. There is not actually a flip-flop of the LNG layers as the name infers; however, the speed at which the heat transfer occurs can cause substantial turbulence in the tank. Rollovers can be



relatively small and insignificant to the vapor handling system or they can evolve tremendous quantities of boiloff gas in a very short period of time. There has only been one significant rollover recorded at an operating LNG facility. This occurred at the La Spezia, Italy facility in 1971. The LNG carrier Esso Brega had been in the harbor for about a month before unloading its load of “heavy” LNG into the storage tank. Eighteen hours after the tank was filled, the tank developed a sudden increase in pressure causing LNG vapor to discharge from the tank safety valves and vents over a period of a few hours. The roof of the tank was also slightly damaged. It is estimated that about 100 1 mmscf of LNG vapor flowed out of the tank. No ignition took place. Stratification does not occur in an LNG tank filled with a homogeneous liquid. However, the introduction of LNG with a different density into a partially filled LNG tank can lead to the temporary formation of stratified layers. Further, stratification may occur over long periods of time in an idle tank. The rollover phenomenon can be of sufficient consequence to the operator and owner of the LNG facility to warrant serious consideration on the methods of detection, prevention, and mitigation. There are a variety of techniques and equipment to accomplish these objectives. This assessment will discuss the techniques and equipment used at the Oregon LNG terminal.

2

INDUSTRY GUIDELINES Stratification and rollover prevention requirements have been addressed in industry codes and standards such as NFPA 59A and BS EN 1473. Section 6.8.1 of BS EN 1473 (1997) states the following requirements for anti-rollover devices: In order to avoid rollover at least the following measures shall be taken …: 

filling systems as defined in 6.9.2;



a recirculation system;



monitor boil off rate;



temperature/density measurements throughout LNG depth.

Other preventive measures can be used, such as: 

avoiding storing significantly different qualities of LNG in the same tank,



appropriate filling procedure considering the respective densities of the LNG;



1

nitrogen content of LNG at filling below 1 mol %.

Million standard cubic feet



These measures lead to the practical elimination of stratification of LNG. Section 6.9.2 of BS EN 1473 (1997) states the filling system piping requirements: Filling shall be able to be carried out, as a function of the LNG quality, either from the roof or at the lower part by a line going to the bottom of the tank. For the bottom filling, at least one of the following features shall be provided (except for tanks used for peak shaving): 

jet nozzles placed at the bottom of the tank and oriented toward the surface;



a vertical pipe perforated for part or for all of its length;



a jet breaker, located at the extremity of a pipe for spray filling.

Section 4.1.2.4 of NFPA 59A (2001) states the filling requirements: All LNG containers shall be designed to accommodate both top and bottom filling unless other positive means are provided to prevent stratification. (See 11.3.7 ) Section 11.3.7 of NFPA 59A (2001) states the product transfer requirements: Where making bulk transfers into stationary storage containers, the LNG being transferred shall meet either of the following requirements: 



3

(a) The LNG shall be compatible in composition or temperature and density with the LNG already in the container. (b) Where the composition or temperature and density are not compatible, means shall be taken to prevent stratification, which might result in “rollover” and an excessive rate of vapor evolution. If a mixing nozzle or agitation system is provided, it shall be designed to have sufficient energy to accomplish its purpose.

MONITORING, PREVENTION AND MITIGATION OF STRATIFICATION AND ROLLOVER 3.1

Monitoring for Stratification

In order to monitor the LNG tanks for stratification, a combined Level, Temperature and Density (LTD) gauge shall be provided to continuously measure level, temperature and density of liquid stored in each LNG tank. The LTD will be capable of monitoring the density at any given level and shall also monitor the level and temperature at any given density measurement point. The LTD is used to monitor for the onset of product stratification which can lead to rollover. The specification for the LTD gauge is listed in Typical Specification for



Level/Temperature/Density Monitoring, Liquid Level Gauging and Overfill Protection System, Document No. 07902-TS-200-204/S7721-9001. A PC based system shall be provided as data acquisition system to collect and manage the data measured by the LTD gauge and shall be provided with hardware and software to permit data transfer to the plant control system by means of serial communication. Provisions for such unit have been made for the Oregon LNG plant as is documented in the plant’s Control System Block Diagram, Drawing No. 07902DG-700-001. The operator will also monitor tank pressure and the run cycles for the boiloff gas compressor and determine if the rate is unexpectedly low for the given plant 2 operating mode. Additionally, pitot flow meters (FE-201* ) are installed on the boiloff gas lines (NG-201*-24-01SS-7.5CC) of each LNG tank for boiloff gas flow measurements. Refer to P&IDs 07902-PI-200-104, 105 and 106. 3.2

Prevention of Stratification

Avoiding stratification is a priority for LNG terminals. Accordingly, standard terminal operating procedures will be provided to prevent stratification. These procedures will be part of the operating procedures manual. Per procedures, operators will: 





Analyze the composition and density of incoming LNG and compare it to the contents in the on-shore tanks; based on this comparison, operators will decide which on-shore tank(s) will receive the incoming LNG, and whether the incoming LNG will be added to the tank via the top-fill or bottom-fill lines. Monitor the tank density profiles to determine whether conditions leading to stratification are occurring. Take action as necessary to prevent stratification, such as circulating liquid from the bottom to the top of a tank, or transferring LNG selectively from the bottom of one tank to the bottom or top of adjacent storage tank(s).

Accordingly, the following provisions are made at the terminal: 

2

The terminal is provided with an LNG sample point, SL-200, on the LNG transfer line from the marine facility (as shown on P&ID 07902-PI-200-104). This allows the operators to monitor the composition of LNG being unloaded at the terminal. In addition, the terminal is provided with LNG sample points, SL230*, on each in-tank pump discharge header (as shown on P&ID 07902-PI-

Indicates FE-201A, B and C



200-104, 105 and 106). These sample points allow the operators to monitor the composition of the LNG pumped out of each tank. 









The LNG tanks are equipped with both top and bottom-fill lines, as shown in P&IDs 07902-PI-200-107-01, 02 and 03. Top filling will be used when introducing LNG with higher density than the liquid in the tank. Bottom filling will be used when introducing LNG with lower density than the liquid in the tank. The vertical bottom-fill column is slotted on its bottom end with slots arranged to disperse the bottom-fill LNG toward the center of the tank. The LNG tanks are equipped with equipment to monitor for stratification and reduction of boiloff gas flow, as described above in Section 3.1. If instrumentation indicates that stratification may be incipient or occurring, the liquid in the bottom of the tank can be circulated to the top or bottom of the tank using the in-tank LNG pumps (P-202*). To accomplish this, the HV-221* and HV-230* valves are closed, and the in-tank pump discharge is routed to the tank fill line through valve HV-222*. Refer to P&IDs 07902-PI-200-104, 105 and 106. LNG can also be transferred from bottom of one tank to the top or bottom-fill line of a different tank. To accomplish this, the HV-222* valve in the pumping tank is opened, allowing LNG to enter the tank fill line; and the top and bottom fill line valves are closed, forcing LNG into the LNG-200-36 unloading line through the open HV-221* valve. Once in the LNG-200-36 line, the LNG can be routed to the top or bottom-fill line of the other tanks. Refer to P&IDs 07902-PI-200-104, 105 and 106.

As noted in EN1473, nitrogen concentrations on the order of 1 mole% or higher in LNG at filling may also lead to stratification. Per the Oregon LNG Design Basis (Doc No. 07902-TS-000-002), the range of nitrogen content expected to be received at the Oregon LNG terminal is between 0.54 mole% and 0.30 mole% and is not expected to reach 1 mole%, thus reducing the likelihood of stratification resulting from high nitrogen concentration in the incoming LNG. 3.3

Mitigation of Rollover

In addition to all above considerations, the tank pressure relief valves are sized in accordance with NFPA 59A (2001 Edition, section 4.7.3 .2): “The minimum pressure relieving capacity in pound per hour (Kilograms per hour) shall not be less than 3 percent of the full tank contents in 24 hours.”



Based on the tank contractor’s previous calculations, this capacity is almost identical (less than 1 % difference) to the vapor flow rate during a theoretical rollover scenario. In addition to the pressure relief valves, pressure in each LNG tank can be controlled using a remotely operated discretionary vent provided in the design for each tank (refer to P&IDs 07902-PI-200-107-01, 02 and 03, Note 10). Further, the terminal is equipped with Discretionary Flare Stack L-210 (see P&ID 07902-PI-200-113) to 3 which the BOG Header is connected through PIC-290; this pressure control valve opens on high pressure in the BOG system and discharges BOG to the stack.

3

Boiloff Gas


Job No. 07902


LNG STORAGE TANK BERM CAPACITY FOR THE OREGON LNG TERMINAL ~ Calculation ~

Prepared for ~

Prepared by ~

H | — C—H H | H

LNG LNG

H H C H H


Baltimore Office 1341A Ashton Road Hanover, MD 21076 410-691-9640

Houston Office 1221 McKinney, Suite 3325 Houston, TX 77010 713-964-6775

CH·IV International Document: 07902-CA-000-001 Rev 2 Issued April 30, 2012

H H C H H


LNG Storage Tank Berm Capacity for the Oregon LNG Terminal

Table of Contents Section

Page

1

Purpose

1

2

Approach

1

3

Calculation

2

3.1

Available Containment within Berm

2

3.2

Volume of Spilled LNG

4

4

Conclusion

5

5

References

5

H H C H H



List of Figures Figure

Page

Figure 1: LNG Storage Tank Berm – Plan View (Reference 1) ...................................................2 Figure 2: LNG Storage Tank Berm - Sectional View (Reference 2) ............................................2 Figure 3: LNG Storage Tank Berm - Area Approximation ..........................................................3

H H C H H



List of Tables Table

Page

Table 1: Calculation Summary........................................................................... ..........................5

H H C H H



1

PURPOSE

The purpose of this calculation is to verify that the berm surrounding the LNG storage tanks designed for the Oregon LNG Terminal will contain the contents of a full LNG storage tank in the highly unlikely event that it fails. 2

APPROACH

The following steps were taken to perform this evaluation: 1. The area surrounded by the berm wall, the sloped portion of the berm, and the area occupied by one of the two LNG tanks were calculated. 2. The net volume available to contain the contents from a single, full LNG storage tank was obtained by subtracting the volume occupied by the “un-failed” LNG tank within the berm from the gross available volume. For simplicity and conservatism purposes, no credit was taken for the open space partially filled with the concrete pedestals below the tank base mats or the Tank Area Spill Containment Basin (S-606). 3. In order to verify that the net volume available within the berm wall is sufficient to contain the potential LNG spill from a full LNG tank, the maximum volume of the LNG inside a tank was calculated using the inside diameter of the inner shell at operating temperature and the design maximum LNG level. 4. Ultimately, the volume required to contain an LNG spill from a full LNG tank was compared to the net volume available inside the berm wall.

07902-CA-000-001 Rev 2

Page 1 of 5

April 30, 2012

H H C H H


LNG Storage Tank Berm Capacity for the Oregon LNG Terminal 3

CALCULATION 3.1

Available Containment within Berm

Figures 1 and 2 illustrate the dimensions of the LNG storage tank berm.

550 ft

5 8 0 f t

f t 7 0 2

4 8 0 f t

2 9 0 f t

990 f t

Figure 1: LNG Storage Tank Berm – Plan View (Reference 1)

3:1

El. 22.0 ft

El. 9.5 ft SECTIONAL VIEW

Figure 2: LNG Storage Tank Berm - Sectional View (Reference 2)

The total bermed area is an irregular shape. To estimate this area at the base elevation, the area is approximated using the AutoCAD LT Area calculation from the plot plan drawing

07902-CA-000-001 Rev 2

Page 2 of 5

April 30, 2012

H H C H H


LNG Storage Tank Berm Capacity for the Oregon LNG Terminal (Reference 1). The area measured at base elevation is outlined in red in Figure 3 and is 2 estimated to be 505,000 ft . The total area available to contain LNG is calculated from the total bermed area less the area of one LNG storage tank (i.e., the intact tank, diameter=269 ft, Reference 3). 2

Atank = π*(270 ft / 2) = 57,000 ft 2

2

2

Ainternal = 505,000 ft – 57,000 ft = 448,000 ft

Figure 3: LNG Storage Tank Berm - Area Approximation

The available volume to contain LNG is calculated by multiplying the available area by the change in elevation of the berm wall. As shown in Figure 2, the base elevation around the tanks is 9.5 ft (Reference 2). For conservatism, the 2% grade away from the tanks is not

07902-CA-000-001 Rev 2

Page 3 of 5

April 30, 2012

H H C H H


LNG Storage Tank Berm Capacity for the Oregon LNG Terminal considered. The total internal volume inside the berm (V berm) equals the area within the berm multiplied by the total height of the berm, 12.5 ft (22.0 ft elevation – 9.5 ft elevation): 2

3

V internal = 448,000 ft × 12.5 ft = 5,600,000 ft

The inclined wall of the berm (between el. +9.5 ft and el. +22 ft) is additional space for the LNG to be contained. The volume of the sloped portion of the berm is calculated by multiplying the cross-sectional area of the sloped berm by the perimeter of the berm. As shown in Figure 2, the berm has a height of 12.5 ft and a slope of 3:1, meaning the length is 37.5 ft. The cross-sectional area of the sloped berm can be calculated as a triangle: 2

Across = (1/2) × 37.5 ft × 12.5 ft = 234 ft

The internal perimeter of the berm, shown in red in Figure 3, is calculated to be 3,000 feet using the AutoCAD LT Measurement calculation from the plot plan drawing (Reference 1). Therefore, the total available volume of the sloped berm equals the cross-sectional area multiplied by the total berm perimeter. 2

3

V slope = 234 ft × 3000 ft = 700,000 ft

The total volume available to contain an LNG spill is the volume internal to the berm plus the volume contained in the sloped portion of the berm: 3

3

3

V total = 5,600,000 ft + 700,000 ft = 6,300,000 ft

3.2

Volume of Spilled LNG

The volume of LNG that may spill into the bermed area occupies a volume equal to the area of the inner shell of the storage tank (diameter = 256 ft, Reference 4) multiplied by the maximum design level of LNG in the tank (118.6 3 ft, Reference 4). 2

3

V spill = (3.14 × (256) /4 × 119) = 6,100,000 ft

07902-CA-000-001 Rev 2

Page 4 of 5

April 30, 2012

Appendix 13L-Storage Tanks

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