Oregon LNG Tank Spec

OREGON LNG TERMINAL

RESOURCE REPORT 13—ENGINEERING AND DESIGN MATERIAL

PDX/082670004.DOC Oregon LNG 13-73 FERC NGA Section 3a Application

Once the LNG carrier is unloaded, an LP pump will start and will circulate LNG through the LNG

unloading pipeline and back to the LNG storage tank to maintain the system at cryogenic

temperatures. Once the LNG carrier has departed, commissioning personnel will align the Terminal

such that they may use the vapor return blowers to introduce cold vapor to all equipment and large

diameter piping. Once the Terminal is sufficiently cool, the Terminal will be aligned to provide a

cooling flow of LNG from the LP pumps to the balance of the piping system. At this point, the

Terminal is cold and ready for normal operation.

13.6 LNG Storage Tanks

The following technical description of the proposed LNG storage tanks (T-201A/B/C) includes the

essential features of the tank design and foundation system, piping support systems on the tank and

support between the tank and horizontal ground piping, tank spill protection and instrumentation.

Appendix L.1 contains details of the LNG Storage Tank and Foundation specification 07902-TS-200-

108 that has been used in the preparation of the LNG storage tank design.

13.6.1 General

Appendix R.1 includes a report entitled LNG Storage Tank Alternatives (07902-TS-000-106) that

describes the alternative LNG storage tank design concepts that were considered for the Oregon LNG

Project.

The design concept selected for the LNG Storage Tanks (T-201A/B/C) is a full containment tank,

with a primary inner containment and a secondary outer containment. The tanks are designed and will

be constructed so that the self-supporting primary containment and the secondary containment will be

capable of independently containing the LNG. The primary containment will contain the LNG under

normal operating conditions. The secondary containment is designed to be capable of containing

110 percent of the capacity of inner tank, as documented in Appendix L.8, and of controlling the

vapor resulting from the highly unlikely failure of the primary containment. Each insulated tank is

designed to store a net volume of 160,000 m3 (1,006,000 barrels) of LNG at a design temperature of -

270°F and a maximum internal pressure of 4.3 psig.

Each full containment tank will consist of:

A 9 percent nickel steel open top inner containment;

A pre-stressed concrete outer containment wall with a steel liner;

A reinforced concrete dome roof;

A reinforced concrete outer containment bottom; and

An insulated aluminum deck over the inner containment suspended from the outer containment

roof.

The aluminum support deck is designed to be insulated on its top surface with fiberglass blanket

insulation material. The fiberglass blanket is chosen to minimize the potential of in-leakage of

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Perlite® insulation into the inner containment. The outside diameter of the outer containment is

approximately 270 feet. The vapor pressure from the LNG is designed to be equalized through ports

in the suspended deck and will be contained by the outer containment. The internal design pressure of

the outer containment will be 4.3 psig. The space between the inner containment and the outer

containment will be insulated to allow the LNG to be stored at a minimum temperature of -270°F

while maintaining the outer containment at near ambient temperature. The insulation beneath the

inner containment will be cellular glass, load-bearing insulation that will support the weight of the

inner containment, tank internal structures (including the bottom fill standpipe column), and the LNG.

The space between the sidewalls of the inner and outer containments will be filled with expanded

Perlite® insulation that will be compacted to reduce long term settling of the insulation. The outer

containment will be lined on the inside with carbon steel plates. This carbon steel liner will serve as a

barrier to moisture migration from the atmosphere reaching the insulation inside the outer concrete

wall. This liner also provides a barrier to prevent vapor escaping from inside the tank in normal

operation.

There will be no penetrations through the inner containment or outer containment sidewall or bottom.

All piping into and out of the inner and outer containments will enter from the top of the tank.

The inner containment is designed and will be constructed in accordance with the requirements of

API Standard 620 Appendix Q. The tank system meets the requirements of NFPA 59A (2001 edition

is used as the basis except where the 2006 edition is more stringent) and 49 CFR Part 193. Refer to

Drawing 07902-DG-200-201 included in Appendix L.2 for typical general arrangement details.

TABLE 13.6.1LNG Storage Tanks, General Information

Number of tanks 3

Net capacity of each inner containment 160,000 m3 (1,006,000 barrels)

Internal design pressure 4.3 psig

Operating pressure 0.5 to 3.7 psig

Design wind load 150 mph

Seismic zone See Appendix I.1 of this Resource Report

Inner tank minimum design metal temperature -270!F

Corrosion allowance of inner containment None

Allowable boiloff rate 0.05% per day

Additional typical tank data is provided in LNG storage tank data sheet 07902-TS-200-201 that is

included in Appendix M.3.

13.6.2 Tank Foundation

Each LNG storage tank will be constructed on a reinforced concrete slab base-mat, which in turn will

sit atop seismic isolators. Friction pendulum type isolators will be used to reduce seismic forces to the

LNG tank. The isolators will be placed on an on-ground reinforced concrete slab. This on-ground slab

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will rest upon foundation piles. Drawing 07902-DG-200-251 included in Appendix L.2 illustrates the

arrangement of the slabs, isolators and piles which compose the tank foundation.

13.6.3 Outer Containment

The outer concrete tank contains the product pressure at ambient temperature and contains the

insulation system.

The liner of the outer tank roof is composed of a butt-welded compression ring and welded steel

plates. A deck is suspended from the outer roof with hangers. The deck holds the roof insulation

above the inner tank. The outer tank roof and vapor space above the suspended deck will essentially

be at ambient temperature. A typical cryogenic roof penetration is illustrated on Drawing 07902-DG-

200-205 in Appendix L.2.

The outer tank is designed for the following conditions:

Internal pressure of 4.3 psig;

External pressure of 1.168 ounce per square inch (0.073 psi);

The specified wind design speed of 150 mph with Exposure C and an Importance Factor, I, equal

1.0 per ASCE 7-05 and as specified in 49 CFR Part 193, Section 2067;

Seismic loads in accordance with NFPA 59A and the site specific seismic reports included in

Appendix I.1;

Internal pressure imposed by insulation loads;

Roof and platform dead loads;

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 and the platform global live load; and

Platform live load combined with a crane handling live load (both to be determined during

detailed design) and external pressure load. Roof live load is not combined with platform live

load.

The suspended deck will be composed of B209-5083-0 aluminum or equivalent. The suspended deck

hangers will be Type 304 stainless steel.

Details of a typical outer containment are illustrated on Drawing 07902-DG-200-230 included in

Appendix L.2.

13.6.4 Inner Containment

The inner tank is designed in accordance with API 620 Appendix Q. The inner tank will be “open

top,” consisting of a shell and bottom. The inner tank will not use a roof. Gas and gas pressure

produced by the stored LNG will be contained by the outer tank. The inner tank, therefore, will not be

subjected to differential gas pressure and will be stressed only by liquid head, insulation loads,

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earthquake loads and the effects of thermal gradients. Circumferential stiffeners will be located on the

inside of the inner tank shell to resist external insulation pressure.

The tank liquid levels will provide a net capacity in the cold condition of at least 160,000 m3

(1,006,000 barrels). Tank liquid levels will be as follows:

Design maximum LNG level (DMLL): 118.63 feet

Seismic Design Liquid Level: 115.75 feet

Maximum Normal Operating Level: 115.75 feet

Minimum Normal Operating Level: 5.50 feet

The inner tank is designed for the following conditions:

Product temperatures and resulting thermal gradients due to cooldown and subsequent filling and

emptying operations;

Internal pressure due to liquid head to the Design Maximum Liquid Level;

Seismic loads in accordance with NFPA 59A and the site specific seismic reports included in

Appendix I.1; and

External pressure imposed by insulation loads.

The inner tank will be composed of 9 percent nickel steel A553 Type 1.

The inner bottom will be composed of a lap-welded bottom in the tank interior. Details of a typical

inner containment are illustrated on Drawing 07902-DG-200-201 included in Appendix L.2.

13.6.5 Seismic Loads on Inner and Outer Tanks

For earthquake loading, the inner containment is designed using the methods in API 620. In addition,

the operating base earthquake (OBE) and safe shutdown earthquake (SSE) criteria specified in NFPA

59A will be used. The design assumes that the inner containment is filled with LNG to its maximum

operating level during both OBE and SSE seismic events.

Horizontal and vertical accelerations are considered for both OBE and SSE seismic events.

Appropriate damping factors will consider soil structure interaction effects. The seismic loading on

the base insulation is also considered.

For evaluation of sloshing loads, the tank liquid level height for both OBE and SSE is considered to

be the rated capacity height, which is the normal maximum operating liquid level. No credit is taken

for the fact that the tank levels will generally be below this maximum level throughout the course of

normal terminal operation. This normal maximum operating liquid level is 115.75 feet above the floor

of the inner tank, as indicated in the LNG storage tank data sheet included in Appendix M.3. The

inner tank wall height is 129.823 feet above the tank floor, as noted in the arrangement drawing

07902-DG-200-201 for the tanks shown in Appendix L.2. This allows 14.1 feet for sloshing. Per the

calculation in Appendix L.6, the slosh height is 7.9 feet for OBE. As this calculated slosh height is

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less than the 14.1-foot sloshing allowance, the tank design precludes LNG from sloshing over the

inner tank wall during OBE when the tank is operating at or below its normal maximum operating

liquid level. For SSE, there is no requirement for minimum freeboard height since this full

containment tank has relief systems sized for the potential vapor generated due to LNG overflow

during SSE (see Appendix L.6).

Seismic design analyses for the inner and outer tanks are provided in Appendices L.6 and L.7,

respectively. The complete seismic information is available in the seismic hazard report included in

Appendix I.1.

13.6.6 Wind Loads on Outer Tank

The outer containment is designed to withstand a wind velocity of 150 mph in accordance with

49 CFR Part 193.2067.

13.6.7 Insulation System

13.6.7.1 Tank Bottom

The tank bottom will be insulated with cellular glass block insulation, which is a load bearing

insulation designed to support the tank and product weight. The bottom insulation in the tank interior

will be composed of layers of cellular glass. A concrete bearing ring will be located under the inner

tank shell to distribute the shell loads into an underlying layer of insulation. The cellular glass blocks

will be located between the outer bottom and inner bottom and laid on a concrete leveling course on

top of the outer tank bottom. Inter-leaving material will be placed over the concrete leveling course

and between bottom insulation layers to fully develop the strength of the load bearing bottom

insulation and help avoid breakdown should the blocks move slightly. A layer of dry sand or leveling

concrete will be placed over the cellular glass block bottom insulation prior to installation of the inner

tank bottom.

Details of a typical bottom corner insulation system are illustrated on Drawing 07902-DG-200-217

included in Appendix L.2.

13.6.7.2 Tank Sidewalls

The annular space between the inner and outer tanks will be approximately 48 inches wide. The

annular space will be filled with loose fill expanded Perlite® and resilient glass wool blanket

insulation. Expanded Perlitey insulation is hard, granular material that readily settles, consolidates

and builds up lateral pressure in a space that changes dimensions. Expanded Perlite® density is

between 2-5 lb/ft3. The glass wool blanket acts as a spring cushion to accommodate the dimensional

changes without compacting the Perlite® and causing excessive external pressure on the inner shell.

An important consideration for the installation of the Perlite® in the annular space is the Perlite®

vibration after filling. Vibration will be used to settle the Perlite® to eliminate potential voids or

pockets in the Perlite® volume and maximize the insulating value of the system. A reservoir of

Perlite® will be placed at the top of the annular space to compensate for future, long-term settlement

of the Perlite®.

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Typical shell insulation configuration is illustrated on drawing 07902-DG-200-215 included in

Appendix L.2.

13.6.7.3 Suspended Deck

The outer tank roof will support a suspended deck at the top of the inner tank. The suspended deck

will be insulated with glass wool blankets with a density of minimum 0.75 lb/ft3. At each penetration

through the suspended deck there will be a flexible shroud fitted to prevent fiberglass material from

falling into the inner tank. Drawing 07902-DG-200-205 included in Appendix L.2 illustrates the

typical shroud configuration.

The suspended deck will be composed of aluminum plate with a series of stiffeners. Hanger bars will

attach to the deck stiffeners and roof framing to suspend the deck above the inner tank. The

suspended deck and hangers are designed for product temperatures. The deck hangers will be

composed of stainless steel.

13.6.8 Tank Instrumentation

Typical tank instrumentation requirements are illustrated on the tank P&ID Drawings 07902-PI-200-

107-01 through 03 included in Appendix U.4 and specifications 07902-TS-200-203 and 07902-TS-

200-204 in Appendix L.3.

13.6.8.1 Cooldown Sensors

To assist in cool down and subsequent temperature measurement during commissioning and

decommissioning of the tank, resistance temperature detector (RTD) elements will be installed on the

inner tank shell, the inner tank bottom and the suspended deck. All cabling from RTDs will be

terminated at one or more junction boxes external to the tank roof. Typical setup of these sensors can

be seen in Drawing 07902-DG-200-247 in Appendix L.2.

13.6.8.2 Temperature Sensors

RTDs will be installed on the bottom surface of the annular space between the inner and outer tanks

to monitor for leakage of the inner tank. The RTDs will be installed at four equally spaced locations

around the circumference of the annular space. Because this location in the tank is not accessible for

maintenance, two RTDs will also be installed at each location to provide for redundant indication.

These typical sensors are illustrated in drawing 07902-DG-200-247 in Appendix L.2.

13.6.8.3 Liquid Level Instruments

Each LNG tank will include two liquid level gauges installed in stilling wells, using a same level

sensing technology. The gauges will include field indicators and a data transmitter to allow

information to interface with the Terminal DCS system.

13.6.8.4 Tank Gauging and Overfill Protection Requirements

Two level gauges will be installed in each tank to provide remote reading and high-level alarm

signals in the control room. Each gauge will be equipped with a transmitter and threshold contact,

allowing the reading of low-low level, low level, high level and high-high level.

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An independent third servo-instrument for high-high level alarm only with trips will be provided in

each tank. The trip switches from this third instrument, along with the other two automatic gauges,

will be wired to the Safety Instrumented System (SIS) that is described in Section 13.10 of this

Report.

This typical instrumentation is further described in technical specification 07902-TS-200-203 and

07902-TS-200-204 provided in Appendix L.3.

13.6.8.5 Level, Temperature and Density (LTD) Monitoring

An independent LTD system monitor, with density difference alarm, will be installed in each tank.

The system will monitor the level versus temperature versus density profile. This device will be used

to monitor for liquid stratification and potential rollover situations. This typical instrumentation is

further described in technical specification 07902-TS-200-203 and 07902-TS-200-204 provided in

Appendix L.3.

13.6.8.6 Liquid Temperature Measurement

Two temperature assemblies will be installed in each tank to measure temperature of the tank internal

contents at predetermined elevations. These temperature signals will be transmitted to the control

room via the level system serial link. This typical instrumentation is further described in technical

specification 07902-TS-200-203 and 07902-TS-200-204 provided in Appendix L.3.

13.6.9 Pressure and Vacuum Relief Systems

Each LNG tank has been designed to be ultimately protected against over- and under-pressure by the

provision of pressure and vacuum relief valves.

13.6.9.1 Over-pressure Protection

The Terminal design includes a BOG handling system that is designed to prevent the LNG storage

tanks from over-pressurizing. In the unlikely event that this system should fail to provide sufficient

protection, the ultimate over-pressure protection for each LNG tank is provided by diaphragm type,

remote sensing pilot operated relief valves. These valves relieve cold LNG vapor from the inner tank

to atmosphere, which ensures that cold gas is not drawn into the dome space in a relief event.

However, discharge through these relief valves to atmosphere is expected to occur only during

emergency situations when all other protective features of the terminal are insufficient to protect the

tanks from over-pressurization. The LNG storage tanks are full containment tanks with a high design

pressure and a large vapor volume combined for the three tanks, which minimizes the potential for

actuation of these relief valves.

Each 12-inch by 16-inch valve will have a capacity of approximately 220,000 lb/hr with respect to the

design pressure of the tank. The required relieving rate is dependent on a number of factors, but

sizing will be based on the NFPA 59A Section 7.8.5.3 (2006 edition) requirement that: “The

minimum pressure relieving capacity in pounds per hour (kilograms per hour) shall not be less than

3 percent of full tank contents in 24 hours.” This corresponds to about 230,000 lb/hour. Therefore, a

minimum of two on-line valves will be required to meet this requirement. Two on-line valves have

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been included within the front end engineering design. NFPA 59A 7.8.4.B (2006 edition) requires:

“Pressure and vacuum relief valves shall be installed on the LNG container to allow each relief valve

to be isolated individually while maintaining the required relieving capacity.” Therefore, an

additional spare valve is provided for each tank to allow one valve to be taken out of service while

maintaining two valves in service to provide the required relieving capability. Accordingly, a total of

three pressure relief valves are provided for each LNG tank. Each valve is provided with an inlet

isolation valve.

NFPA 59A Section 7.8.2 (2006 edition) requires: “Relief valves shall communicate directly with the

atmosphere.” Accordingly, each valve discharge is independently routed to atmosphere. Each relief

valve discharges to atmosphere at a safe location via its 16-inch vertical tailpipe. The concrete tank

roof has inherent passive fire protection, and the pipework and structures are passively fire protected.

To protect against the ingress of foreign matter, each tailpipe will be provided with a rain flapper to

protect against rain ingress and a small-bore piped low point drain will be provided. To protect

against snow and ice, each tailpipe will be provided with appropriate winterization. A monorail crane

will be positioned for relief valve service.

These valves are illustrated the tank P&IDs 07902-PI-200-107-01 through 03 in Appendix U.4. A

typical arrangement of the relief valves and nozzles is illustrated on drawings 07902-DG-200-210 and

07902-DG-200-236 included in Appendix L.2. Typical relief valves are positioned as illustrated on

drawing 07902-DG-200-257 included in Appendix L.2.

13.6.9.2 Under-Pressure Protection

The Terminal design includes a BOG handling system that is designed to prevent the LNG storage

tanks from dropping below the design minimum tank pressure. In the unlikely event that this system

should fail to provide sufficient protection, the ultimate under-pressure protection is provided by

weight-loaded, pallet-type vacuum relief valves installed on each tank. These valves relieve from

atmosphere to the dome space. This ensures, 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.

However, lifting of these relief valves to atmosphere is expected to occur only during emergency

situations when all other protective features of the terminal are insufficient to protect the tanks from

under-pressurization. The BOG make-up vaporizer and large vapor volume combined for the three

tanks minimize the potential for actuation of these relief valves.

Each 12-inch valve will have a capacity of about 210,000 standard cubic feet per hour (scfh) of air

with respect to the design vacuum of the tank. The required relieving rate is dependent on a number

of factors, but the front end engineering design basis is 640,000 scfh of air. Therefore, a minimum of

four on-line valves will be required to meet this requirement. Four on-line valves have been included

in the front end engineering design. NFPA 59A Section 7.8.4.B (2006 edition) requires: “Pressure

and vacuum relief valves shall be installed on the LNG container to allow each relief valve to be

isolated individually while maintaining required relieving capacity.” Therefore, an additional spare

valve is provided for each tank to allow one valve to be taken out of service while maintaining three

valves in service to provide the required relieving capability. Accordingly, a total of five vacuum

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relief valves are provided for each tank. Each valve is provided with a dedicated tank-side isolation

valve. Valve inlets draw independently from the atmosphere.

To protect against the ingress of foreign matter, the inlet will be provided with coarse screen; and to

protect against rain and snow ingress, a protective cowl will be provided. To protect against ice, the

valves may be provided with winterization. A monorail crane will be positioned for relief valve

service.

These valves are illustrated the tank P&IDs 07902-PI-200-107-01 through 03 in Appendix U.4. A

typical arrangement of the relief valves and nozzles is illustrated on drawings 07902-DG-200-211

included in Appendix L.2. Typical relief valves are positioned as illustrated on drawing 07902-DG-

200-257 included in Appendix L.2.

13.6.10 Fittings, Accessories, and Tank Piping

13.6.10.1 Roof Platform

The roof platform is sized to provide sufficient working space around the pump columns and piping.

Drawing 07902-DG-200-236 in Appendix L.2 illustrates a typical arrangement of the roof platform.

13.6.10.2 Cranes/Hoists

The pump handling system will consist of a hydraulic jib crane or a monorail-type hoist. Explosion

proof electric motors or pneumatic drives and components will be provided to meet hazardous rating

requirements. For further details on typical cranes and hoists, refer to drawing 07902-DG-200-224

included in Appendix L.2.

13.6.10.3 In-tank Pump Columns

Three in-tank pump columns will be installed per tank. LP pumps will be installed in two of these

columns; the third column is a spare and will not have a pump installed at this time. The pump

columns will be provided with electrical seals, supports, instrumentation, piping, etc., for a complete

system. The columns are designed to ASME pressure vessel codes, as they operate at higher pressures

than the LNG storage tanks. The arrangement of a typical pump column is illustrated on Drawing

07902-DG-200-227 included in Appendix L.2.

13.6.10.4 Tank Internal Pipework

All LNG tank internal piping will enter the tank through the concrete outer tank roof. The tank

internal piping is illustrated on the P&IDs 07902-PI-200-107-01 through 03 included in

Appendix U.4.

Typical roof connection details are illustrated on Drawings 07902-DG-200-205 and typical internal

pipe work details are illustrated on Drawings 07902-DG-200-202, 07902-DG-200-208, 07902-DG-

200-209, 07902-DG-200-210, 07902-DG-200-211, 07902-DG-200-226 and 07902-DG-200-227.

These drawings are included in Appendix L.2.

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13.6.10.5 Tank External Pipework and Supports

The LNG tank external piping is illustrated on P&IDs 07902-PI-200-107-01 through 03 included in

Appendix U.4.

All piping systems are designed in accordance with ASME B31.3 and NFPA 59A.

The pipes running down the vertical side of the tank wall will be supported from the top of the tank

structure and guided by supports along the vertical run in at least two elevations along the vertical

wall. The supports in the vertical section are attached directly to the tank wall; therefore no structure

from grade for these supports is required.

Imbedded and extended pipe supports installed on the LNG storage tanks will be insulated to protect

the support structure from exposure to cryogenic temperatures in the event of an LNG jet leak or spill.

The interconnecting rack will contain a pipe support strategically located to account for the

expansion/contraction of the pipework in the vertical leg and any estimated pipe movement due to

seismic-induced tank motion or settlement of the supporting structure.

13.6.10.6 Provisions for Tank Isolation

As illustrated on P&IDs 07902-PI-200-107-01/02/03 (included in Appendix U.4), LNG Storage

Tanks T-201A/B/C can each be isolated with an isolation system that has been designed in

accordance with Section 17.0 of the Engineering Design Standard 07902-TS-000-001 (included in

Appendix C.1).

In accordance with the above referenced Engineering Design Standard, all efforts have been made in

the proposed design to meet the intent of NFPA 59A-2006 Section 9.3.1.4, which requires that the use

of flanges in cryogenic piping be minimized. The use of flanges for isolation purposes shall be further

considered during detailed engineering design.

13.6.11 Stairways and Platforms

13.6.11.1 Access to Platform and Roof

Platforms will be provided on the LNG tank roof for access to the pump columns, nozzles and

instrumentation.

A stairway with intermediate landings attached to the outer tank will be provided for access to the

roof platform for the LP Pumps and instrumentation. A staircase with galvanized steel handrails will

be provided to provide access from the LP Pump platform to the tank roof.

An emergency escape ladder will also be provided opposite the main roof platform and will be

accessible via a walkway equipped with handrails. The emergency escape ladder will be of the caged

ladder type with side stepping platforms. It will be attached to and supported by the outer concrete

tank.

Typical arrangements of the stairways and ladder are illustrated on drawings 07902-DG-200-238 and

07902-DG-200-240, included in Appendix L.2.

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13.6.11.2 Internal Tank Ladder

Internal LNG tank access will be provided through roof man-ways. A stairway will be provided to the

inner tank bottom.

Typical LNG tank access details are illustrated on drawing 07902-DG-200-239 included in

Appendix L.2.

13.6.11.3 Walkways and Handrails

Handrails for exterior stairways and platforms will be galvanized.

13.6.12 Cryogenic Spill Protection

Spill protection of the LNG tank roof is designed to comply with the requirements of NFPA 59A. To

avoid spills, the number of flanges used on the tank top will be minimized. Should a spill occur then

gas detectors located on the tank will trigger an alarm and the emergency shutdown system will be

activated either automatically or manually to shut off the flow of LNG.

A reinforced concrete bund beneath the tank top platform will be provided to ensure that discharge is

controlled and directed to a spillage down-pipe. This down-pipe directs the spill to the base of the

tank, where the spill is discharged into a reinforced concrete channel and directed away from the tank

into a spill containment trough. Drawing 07902-DG-200-235 in Appendix L.2 illustrates plan and

elevation views of a typical tank top platform spill containment and down-pipe arrangement.

The tank top protection will extend to the edge of the roof dome. Any structural carbon steel on the

roof will be protected from potential spills.

13.6.13 Anchorage

The concrete outer tank wall and base connection is monolithic and does not require anchors.

Since the seismic isolators will reduce the forces to the inner tank, anchor straps will not be necessary

for the inner tank.

13.6.14 Painting

Carbon steel stairs, platforms, and pipe supports will be galvanized. Stainless steel, aluminum, and

galvanized surfaces will not be painted.

13.6.15 Tank Lighting and Convenience Receptacles

General LNG tank lighting systems will be provided. Lighting levels will be as defined per

Illuminating Engineering Society of North America (IESNA) recommendation.

Emergency escape lighting will be provided using self-contained battery fittings.

A dual aircraft warning light will be provided at the highest point on each LNG tank if required in

accordance with Federal Aviation Administration (FAA) directives. Outdoor convenience receptacles

will be provided at the tank, with a minimum of two at the top platform.

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The electrical system is designed in accordance with the National Electrical Code (NEC). Drawing

07902-DG-200-229 provides a typical lightning protection for a full containment tank.

13.6.16 Electrical Grounding

The LNG tanks will be provided with a grounding system. The grounding grid will consist of

stranded copper wire. Grounding electrodes will be spaced such that the overall grounding resistance

does not exceed 10 Ohms.

13.6.17 Welding

LNG tank welding procedure qualifications and welder qualifications will be in accordance with

ASME Section IX C13. The guidelines of API 620 Appendix Q will be followed for the quantity of

tests. Test plates will be welded on a test stand.

Visual inspection will be performed in accordance with API 620.

The shell plate to annular plate joint will be smoothly finished to avoid undercuts and overlaps,

provided that any undercut will be within the tolerances allowed by API 620.

13.6.18 Testing and Inspection

Testing and inspection of the welding, completed work and the completed structure will be performed

under the direct supervision of a qualified welding supervisor inspector. Both visual inspection and

radiographic inspection will be used. An inspection and quality assurance procedure applicable to

LNG tanks will be used.

13.6.18.1 Alloy Verification

All alloy material used in the construction of the inner and outer tanks will be subject to alloy

verification. All alloy material external to the tank and in cryogenic service will be subject to alloy

verification.

Alloy verification will be performed in accordance with specifications. Technical specification

07902-TS-200-202, included in Appendix L.5 summarizes typical requirements.

13.6.18.2 Radiography

The radiographic techniques and acceptance criteria will be in accordance with API 620. The extent

of radiography will be in accordance with API 620 and NFPA 59A Section 4.2.1 (2001 edition). The

radiographic test may be substituted with the ultrasonic test in accordance with API 620 Appendix U.

13.6.18.3 Liquid Penetrant Examination

Liquid penetrant examination will be performed in accordance with API 620, with the exception that

the water-washable method may be used.

13.6.18.4 Vacuum Box Testing

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

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13.6.18.5 Hydrotesting of Inner Tank

The LNG storage tanks will be hydrostatically and pneumatically tested in compliance with the

applicable codes that govern the tank design. Hydrotesting will be performed on the inner container

of each LNG storage tank. Hydrostatic testing of the inner containment will be in accordance with

API 620 Appendix Q.8 (partial hydrotest).

The inner containers will be made of 9 percent nickel. Hydrotest water will be filtered to prevent the

ingress of coarse materials. The test water will be sampled and tested for compliance with API 620,

Section Q.8.3 requirements for test water quality prior to use. In addition to the API620 requirements,

the test water will meet the following requirements.

pH: between 6 and 8;

The electric conduction ratio: below 500 s/cm @25°C;

Chloride content (Cl): below 500 ppm;

Water soluble sulphate (SO32-) content: below 200 ppm;

Iron content (Fe) targeted: below 1.0 ppm;

Ammonium ion content (NH4+): nearly 0 ppm; and

The chemical oxygen demand of the test water (CODMn): below approx. 15 ppm.

Approximately 28 million gallons of water per tank will be required to perform the test. The

hydrostatic test water is proposed for diversion from the Lower Skipanon River through a large-

diameter intake pipe equipped with a fish screen designed to comply with National Marine Fisheries

Service (NMFS) and ODFW fish screen design requirements to prevent the uptake of juvenile salmon

species. The water will be treated using a mobile RO treatment facility to improve the water quality

prior to introduction into the LNG storage tanks. The intake facilities will be designed to function

properly through the full range of hydraulic conditions and will account for debris and sedimentation

conditions that may occur. Intake velocities are expected to be approximately 600 gpm resulting in a

fish screen of approximately 3 square feet in area if an active pump is used, and 6 square feet in area

if a passive pump is used. A Limited Water Use License will be required for withdrawal of the

hydrostatic test water, and Oregon LNG will work with the Oregon Department of Water Resources

(ODWR), ODFW, and other interested agencies to design the appropriate hydrostatic water diversion

during the Limited Water Use License application process.

Upon completion of hydrostatic testing of the first LNG storage tank, the test water will be transferred

to the second tank for hydrotesting and subsequently to the third tank, so that no additional water is

required. The pumping rate between tanks is expected to be 4,200 gpm.

As extraction of the water is taking place through the RO system, two water streams will be produced,

permeate and concentrate waters. The permeate water will be used for the hydrostatic testing of the

tanks, and it will constitute approximately 80 percent of the volume of water passed through the RO

system. The concentrate water will be discharged back into the lower Skipanon River, and it will

constitute approximately 20 percent of volume of water passed through the RO system. The

concentrate water will have approximately five times the salinity of the source water, and the

permeate water will be salt-free for use in the hydrostatic testing of the tanks. The concentrate water

will be discharged back to the Skipanon River at the same location from where it was withdrawn, at a

OREGON LNG TERMINAL



rate of 120 gpm. Once hydrostatic testing of the third tank is completed, the permeate water will be

drained into the Skipanon River via the submerged intake structure. The hydrostatic test water will be

discharged in accordance with the FERC Procedures and state and Federal requirements for

discharge. Water extraction from, and discharge to, the Skipanon River will not cause any measurable

changes in river flow, stage, or water quality.

Each tank will be equipped with a settlement monitoring system to measure and record inner and

outer tank movements during hydrotest. The settlement monitoring system consists of

survey/reference points equally spaced around the tank and will be capable of measuring differential

settlement between inner and outer tanks. During hydrotest, settlements, rotation and base slab tilting

will be monitored at approximately each 16.4-foot increment of water fill height. Measurements will

also be recorded when the tank is emptied.

The LNG storage tank construction schedule will be developed such that water used to hydrotest the

first storage tank may be reused to test subsequent tanks. After each tank hydrotest, the test water will

be pumped out of the tank, tested, treated (if necessary) and discharged to the river in a location and

manner in accordance with applicable permits and regulations.

Following hydrotesting, the inner tank inside wall, floor and internal structures will be rinsed with

fresh water. Typical rinse water flow rate is about 3-5 gpm. The rinse water will be pumped out of the

tank and discharged to the river in a location and manner in accordance with applicable permits and

regulations. The quantity of rinse water to be discharged is approximately 7,200 to 12,000 gallons for

each tank. Detailed procedures for rinse and final drying of the tanks will be prepared and

implemented.

13.6.18.6 Pressure and Vacuum Testing

A pneumatic test of the outer containment will be performed in accordance with API 620

Appendix Q.8.

13.6.18.7 Settlement Monitoring

A settlement monitoring system will be provided to measure and record inner and outer tank

movements during construction and hydrotest.

A minimum of 16 survey/reference points will be equally spaced around the outer edge of the base

slab. In addition, settlement of the inner tank will be monitored at the same reference points used for

the base slab/outer tank. Measurement will be made from the inner tank annular plate. Also a

reference point will be established on the outer tank wall to measure differential settlement between

inner and outer tanks. Differential settlement and tilting of the base slab will be monitored and

recorded.

During hydrotest, settlements, rotation and base slab tilting will be monitored at approximately each

16.4-foot increment of water fill height. Measurements will also be recorded when the tank is

emptied. During construction, the settlement of the base slab and inner tank will be monitored on a

weekly basis.

OREGON LNG TERMINAL



Refer to specification 07902-TS-200-205 included in Appendix L.4 for a description of a typical

settlement monitoring system.

13.6.18.8 Translation and Rotation Movement Indicators

Refer to drawing 07902-DG-200-243 in Appendix L.2 for details of typical movement indicators

provided for the inner tank.

13.6.19 Procedures for Monitoring and Remediating Stratification

An LNG Storage Tank Rollover Assessment (07902-TS-200-206) has been prepared and included in

Appendix L.9 of Resource Report 13. This document summarizes design and procedural provisions to

avoid, monitor and remediate stratification, These provisions include:

Each LNG tank will be equipped with density monitoring instrumentation to indicate

stratification and potential rollover problems to allow early operator action.

The LNG storage tanks will be capable of top or bottom filling from an LNG ship to avoid

stratification.

Provision is made to circulate the stored product so that if stratification begins to develop, the

tank contents can be thoroughly mixed. This will involve pumping LNG from the bottom of the

tank and returning it to either the top or the bottom as needed.

13.6.20 Tank Secondary Bottom and Corner Protection

Each LNG tank will be equipped with a typical 9 percent nickel steel secondary bottom and corner

protection system. Drawing 07902-DG-200-204 included in Appendix L.2 illustrates a typical

arrangement for this corner protection.

13.6.21 Drawings

The following LNG storage tank general arrangement and construction drawings are included in

Appendix L.2.

TABLE 13.6.21LNG Storage Tank Drawings

Drawing Number Description

07902-DG-200-201 General Arrangement of 160,000 M3 Full Containment LNG Storage Tank

07902-DG-200-202 Typical Detail at Top of Bottom Fill Column Including Heat-break

07902-DG-200-204 Typical Details of 9% Ni Bottom Corner Protection

07902-DG-200-205 Typical Details of Heat-break and non-heat break Roof Nozzle

07902-DG-200-208 Typical Detail of Top Inlet Nozzle Termination

07902-DG-200-209 Typical Details of Cooldown Ring

07902-DG-200-210 Typical Pressure Relief Assembly

07902-DG-200-211 Typical Vacuum Relief Assembly

07902-DG-200-212 Typical Details of Suspended Deck Vents

OREGON LNG TERMINAL



TABLE 13.6.21LNG Storage Tank Drawings

Drawing Number Description

07902-DG-200-215 Typical Shell Insulation Details

07902-DG-200-216 Top Corner Insulation Typical Details

07902-DG-200-217 Typical Details of Bottom Corner Insulation

07902-DG-200-219 Typical Outer Tank Wall Embedment Details (Vapor Barrier)

07902-DG-200-220 Typical Outer Tank Wall Liner Plating Details (Vapor Barrier)

07902-DG-200-222 Pump Platform Typical Piping Arrangement

07902-DG-200-223 General Arrangement of Typical Piperack to Outer Concrete Tank Wall

07902-DG-200-224 Typical Arrangement of in Tank Pump Hoist

07902-DG-200-225 Typical Access Through Suspended Deck

07902-DG-200-226 Typical Detail of Inter Purge Pipe

07902-DG-200-227 Typical Pump Column Arrangement

07902-DG-200-228 Arrangement and Details of 36-inch Manway and 52-inch Manway

07902-DG-200-229 Typical Lightning Protection Details

07902-DG-200-230 Arrangement of Outer Concrete Tank of LNG Storage Tank

07902-DG-200-231 Sectional Plans and Buttress Details

07902-DG-200-232 Typical Wall Post Tensioning Details Sheet 1 Quadrant 1

07902-DG-200-233 Typical Wall Post Tensioning Details Sheet 2

07902-DG-200-234 Temporary Access Opening—Typical Diagrammatic and Explanatory

07902-DG-200-235 General Arrangement of Tank Roof Spill Collection Area

07902-DG-200-236 General Arrangement of Roof Platforms

07902-DG-200-237 General Arrangement of Suspended Deck

07902-DG-200-238 General Arrangement of External Stairway

07902-DG-200-239 General Arrangement of Internal Ladders

07902-DG-200-240 General Arrangement of External Ladder

07902-DG-200-241 General Arrangement of Internal Suspended Deck Access Platform

07902-DG-200-243 Typical Arrangement of Inner Tank Horizontal Movement Monitoring Nozzle

07902-DG-200-245 Tank Foundation Detail Drawing for Cathodic Protection

07902-DG-200-247 Typical Cooldown Detection RTD Blocks on Inner Tank

07902-DG-200-251 Tank Foundation

07902-DG-200-257 Tank Roof Nozzle Layout

07902-DG-200-258 Tank Roof Structure Support Plinths

07902-DG-200-259 Typical Upper Slab Circumferential Post Tensioning Details

Oregon LNG Tank Spec

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