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Linde Process Plants, Inc.Significant Upgrades to LNG Baseload and Peakshaving Facilities & Associated ChallengesGeorg H. Breuer, LNG Product ManagerGrapevine, TX, May 2015

G. H. Breuer/ 05.15 /LPP AGA Presentation_2015Linde AG Engineering Division – Linde Process Plants , Inc.

Overview

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— Significant Upgrades

— LNG Plant – Typical Installations

— Liquefaction Upgrades

• Process Technology

• Unit Replacement

• Capacity Upgrade

— Operational, Venting and Storage Challenges

— Feed Gas Changes

— References

— Conclusion


Significant UpgradesWhat main types of “voluntary upgrades“ can be found?

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Liquefaction Unit Replacement Liquefaction unit of an existing LNG plant infrastructure to be upgraded/replaced using:

— same or new technology (nitrogen expander versus single mixed refrigerant technology)

— similar or significantly higher capacity

and possibly requiring at least:

— modification to or newly installed gas treatment

— modification to “grandfathered” storage

Capacity IncreaseExisting LNG plant infrastructure receiving an additional liquefaction unit requiring:

— at a minimum significant modification to or newly installed gas treatment

— modification to “grandfathered” storage


Significant UpgradesWhat main types of “forced upgrades“ can be found?

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Feed Gas Composition Change Existing LNG plant infrastructure seeing a concentration increase above existing threshold valuesof the following feed gas components:

— mercury

— carbon dioxide / sulphur

— heavy hydrocarbons (HHC), e.g. ethane

— oxygen

and requiring

— at a minimum significant modifications to the existing or even a newly installed gas treatment

— installation of a strip column or separator in the liquefaction (HHC removal)

Feed Gas Pressure Change Existing LNG plant infrastructure seeing a pressure decrease of the feed gas supply requiring:

— installation of feed gas compression


LNG PlantsOverview – Block Flow Diagram - Typical Installations

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Liquefaction UpgradesWhat type of processes are mainly used in the industry?

— Expander Process (capacity < 0.2 MTPA (MTPA = mio. t/a)*)(capacity < 400,000 gpd)

— Single Cycle Process (capacity < 1 MTPA)(capacity < 2,000,000 gpd)

— Dual Cycle Process (capacity 0.8 - 3 MTPA)(capacity 1,200,000 – 6,000,000 gpd)

— Triple Cycle Process (capacity 3 - 10 MTPA)(capacity 6,000,000 – 20,000,000 gpd)

Peakshaving and Baseload Plants for the Local Supply (Merchant LNG)

LNG processes are characterized by the type and number of refrigeration cycles used to accomplish the pre-cooling, liquefaction and sub-cooling of the natural gas:

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*1 MTPA equals 1,977, 496 gpd (@ 330 days of operation), i.e. roughly 2,000,000 gpd

Baseload Plants


Liquefaction UpgradesSingle Mixed Refrigerant versus N2 Double Expander

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SMR Process N2 Double Expander Process

Comments

CAPEX API versus non- API Machinery, Equipment Count, Piping (p, V)

Energy Efficiency

1.0 1.15 – 1.3Ammonia or Propane Precooling?

OPEX1.0 1.4 – 2.15

Power Consumption and Refrigerant Losses (Machinery Seals)

Complexity Simple Process / Operation

Turn-Down50% 30%

Ease and Efficiency of Expander Turn-Down

Plot Area Compact SMR, MRC Storage vs. Non-Flammable Refrigerant

Recommended

Application

Larger Production Capacities

Significance of Low OPEX

Base Load

Smaller Production Capacities

No HC Make-Up, Lower Hazard Profile

Varying Load Operation


Liquefaction UpgradesReplacement / Capacity Increase - Main Considerations

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Technological

Process

— N2 Double Expander versus Single Mixed Refrigerant (SMR)

• Capacity, OPEX (Power, Refrigerant), Operation Regime, Plot Area

Heat Exchange

— Plate-Fin (PFHE) versus Coil-Wound Heat Exchanger (CWHE)

• Capacity, Operating Pressure (PFHE < 870 psi), Temperature Gradients( i.e. start-up duration)

Operational

Operation Regime

— Peak Shaving (Intermittent) Operation

— Base Load Operation (Peak Shaving + Continuous Merchant LNG Production)

Operation Team Education / Training


Liquefaction UpgradeOverview – Unit Replacement

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Liquefaction UpgradesUnit Replacement - Main Challenges

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— Available Plot Area based on Hazardous Area Classification versus latest Siting Requirements (i.e. safety distances with regard to changes in 49 CFR 193 and NFPA 59A, especially at plant battery limits)

— Venting Duration and Amount at Start-Up / Shut-Down (due to different technology)

— Integration into Infrastructure (existing and possibly “grandfathered“)

• Control System (technology)

• Power Supply and Distribution (voltage level, power demand)

• LNG Storage (grandfathered and/or not allowing for additional connections)


Liquefaction UpgradeOverview – Capacity Increase

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Liquefaction UpgradesCapacity Increase - Main Challenges

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— Available Plot Area based on Hazardous Area Classification versus latest Siting Requirements (changes in 49 CFR 193 and NFPA 59A)

— Additional Vent Gas Amount at Start-Up / Shut-Down

— Gas Treatment (significant modification or new-built)

— Flash and Boil-Off Gas Handling (compressor, flash-drums, LNG pumps, etc.)

— Integration with existing and possibly “grandfathered“ Infrastructure

• Control System (technology)

• Power Supply and Distribution (voltage level, power demand and availability)

• LNG Storage (grandfathered and/or not allowing for additional connections)


Liquefaction UpgradesOperational Challenges

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“Back Then“

— small liquefaction capacity, large storage capacity

— typical “cold season“ peak shaving operation

— start-up at low LNG storage tank level, continuous filling operation, no topping-up

Capacity /

Technology

Upgrade

“Now“

— different heat exchanger technology and/or increased liquefaction capacity, same storage capacity

— “all seasons“ peak shaving operation plus merchant LNG production

— start-up at higher LNG storage tank levels, intermittent filling operation (driven by feed gas and energy pricing), continuous topping-off

Installation of additional equipment, e.g. separator for start-up, etc. or replacement ofequipment with increased capacity required.


Liquefaction UpgradesVenting Challenges

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— Existing operating permit might generally limit venting (amount, duration, etc.)

— Future legislation might regard methane as Volatile Organic Compound (VOC) and require incineration

— Latest changes in API 521, Sixth Edition, January 2014 and possible consequences

• vent versus flare

• plot area versus stack height

API 521-14, Section 5.8.10 “Vent Stacks“Dispersion:“The height and location of the vent stack shall be selected so that the concentration of vapor at a point ofinterest is below the lower flammable limit of the vapor. The lower threshold for flammability concerns can besatisfied by ensuring the concentration at potential sources of ignition, personnel location, or other vulnerableareas does not exceed 0.1 times to 0.5. times the lower flammable limit.“

API 521-14, Section 5.8.4 “Ignition of a Relief Steram at the Point of Emission“Radiation:“In any case, the radiant heat intensity for vent stacks shall be evaluated for ignitable vapor. This shall be doneby the same means as used for flare stacks, and the same limits of radiant heat intensity shall apply. Radiant heatlevels rather than dispersion can sometimes govern the vent stack design in determining stack height.“


Liquefaction UpgradesLNG Storage Challenges

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— “Grandfathered“ Tank

• does not allow for changes at all

— Tank Modfifications

• steel-steel tank design sensitive to additional roof mounted loads

• modifications to tank, e.g. additional nozzle installation, might require tank to be taken out of service (emptying out, warm-up, purging, renewed cool-down and filling)

— Siting Requirements

• changes to tank might could trigger updates to latest 49 CFR 193 and NFPA 59A requirements, e.g. impoundment area sizing, dike design, etc.

§ 193.2181 Impoundment capacity: LNG storage tanks.

Each impounding system serving an LNG storage tank must have a minimum volumetric liquid impoundment capacity of:

(a) 110 percent of the LNG tank’s maximum liquid capacity for an impoundment serving a single tank;

(b) 100 percent of all tanks or 110 percent of the largest tank’s maximum liquid capacity, ……; or

(c) If the dike is designed to account for a surge in the event of catastrophic failure, then the impoundment capacity may be reduced to 100 percent in lieu of 110 percent.


Feed Gas ChangesImpurities - Typical Limits

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Component Unit Design Data Remark

Glycols MEG/TEG mg/Nm³ 0 Malfunction

Mercury Hg ng/Nm³ 10 PFHE Damage / Safety and Environment

Carbon Dioxide CO2 ppmv 50 Product Quality / Avoidance of Freezing

(higher values up to 100 ppmv acceptable dependingon storage pressure, i.e. temperature)

Hydrogen Sulfide H2S ppmv 4 Product Specification / Corrosion Prevention

Carbonyl Sulfide COS mg/Nm³ ??? Corrosion Prevention

(in the presence of H2O forms H2S and CO2)

Total Sulphur Content S mg/Nm³ 30 Product Specification / Corrosion Prevention

Mercaptans R-SH mg/Nm³ ??? Corrosion Prevention/ Avoidance of Freezing

Moisture H2O ppmv 0.1 Avoidance of Freezing

Nitrogen N2 mol-% 1 - 2 Roll-Over Prevention / Product Specification

Ethane C2H6 mol-% 6 Product Specification

(to allow use as truck fuel)

Oxygen O2 ppmv 10 - 20 Degradation / Destruction of Molecular Sieve

Methanol CH3OH mg/Nm³ 0 Avoidance of Freezing


Feed Gas ChangesTypical Changes and Gas Treatment Upgrades

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Mercury (Hg) - Removal

— content in feed gas is rising over depleting lifetime of gas field

— other fields with higher content coming on-stream

— extremely low content required in recovered ethane product

Ethane (C2H6)

— content in feed gas is rising (due to shale gas quality and reverse pipeline flow)

— LNG product specification for truck fuel requires low ethane content

Oxygen (O2)

— pipeline operator changed content in pipeline gas specification due to possible ingress at flanges, leaks, etc.


Gas Treatment UpgradesOverview

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Gas Treatment UpgradeMercury Removal – Why and How?

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Why?

— severe corrosion of aluminum heat exchangers (amalgam corrosion, liquid-metal embrittlement)

— poisoning of precious metal catalysts (e.g. platinum, palladium, etc.)

— exposure hazard to mercury vapor during equipment maintenance

— emissions to environment

How?

— Non-Regenerative Absorbent Technology

• sulfur-promoted activated carbon (only for dry gas)

• metal-sulfide systems (upstream of AGRU and dryers)

— Regenerative Molecular Sieve Technology

• silver-promoted molecular sieve (part of dehydration molecular sieve)

— Molecular Sieve plus Non-Regenerative Absorbent


Gas Treatment UpgradeMercury Removal –Where and How?

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Where and How?

Option 1: Non-Regenerative Absorbent at Inlet

removes all Hg, no Hg contamination in the rest of the plant large volume of feed gas (including acid gas) requires large Hg removal unit

Option 2: Non-Regenerative Absorbent downstream of AGRU, upstream of Dehydration

reduces size of Hg removal unit poses risk of Hg contamination in the AGRU solvent system

Option 3: Regenerative Molecular Sieve within Dehydration

removes water, mercaptan and Hg at the same time, avoids a separate Hg removal bed

high Hg content in regeneration water posing operating hazard unless treated high Hg content in regeneration gas might require non-regenerative absorbent

Option 4: Absorbent or Molecular Sieve after Dehydration

yields good mercury removal performance due to dry and clean feed gas Hg contamination of AGRU and Dehydration may pose operating hazard

Life cycle costs, adsorbent disposal methods, mercury levels, environmental limits, operatinghazards and plant operation are to be considered as well.


Gas Treatment UpgradeHHC Removal and C2+ Extraction – Why, How and Where?

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Why?

— avoidance of freezing of heavy hydrocarbons (HHCs) or NGL (C2+) in downstream cryogenic plantunits

— achievement of LNG specification (Heating Value, Wobbe Index, Methane Number)

— monetizing on NGLs

How?

— HHC Separator

— Strip Column

Where and How?

NGL Extraction tied into Heat Exchanger of the Natural Gas Liquefaction


Gas Treatment UpgradeHHC Removal and C2+ Extraction – Where and How?

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HHC Separator

“Rule of Thumb“, atmospheric LNG storage

C6 > 250 ppmv or

C7 > 50 ppmv or

C8 > 1 ppmv or

Benzene > 1 ppmv requires removal

Strip Column

LNG specification requires C2+ removal


ReferencesHands-On Experience – Montreal, Canada

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Operator and OwnerGaz Métro

ProcessStarLNGTM Nitrogen Double Expander with PFHE

Capacity215,000 gpd (330 tpd)

Storage Capacityusing already existing facilities

Loading Facilitiestwo additional truck loading stations

ScopeEPC and commissioning


ReferencesHands-On Experience – Bintulu, Malaysia

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Operator and OwnerMLNG (Petronas)

ProcessLIMUM® (mixed refrigerant cycle) with CWHE

Capacity1,200,000 gpd (1,840 tpd)

Storage Capacityusing already existing facilities

Loading Facilitiesnone

ScopeEPC and start-up supervision


ConclusionSignificant Upgrades – What is the best approach?

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Significant Upgrades

— are mostly complex

— impact multiple units and systems in an existing LNG plant

— carry specific risks with regard to process and operation

— require typically substantial investment

Recommended Best Approach to Significant Upgrades

— uses an experienced and knowledgeable process design company with an unbiased approach regarding technology

— considers the complete LNG plant as a system (process related as well as economically), holistic and no split approach

— evaluates “off-the shelf” units versus customized approach

— considers specific existing and future operational conditions

— takes into consideration future merchant LNG market development

— uses experienced contractors (EPC)

Thank you for your attention.

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