A General Guide to Liquefied Natural Gas (LNG) Plant Design

1. Introduction

This guide provides a comprehensive overview of the design principles, technologies, and best practices for modern Liquefied Natural Gas (LNG) plants. It covers large-scale onshore facilities, with specific considerations for floating LNG (FLNG). While it cannot replace detailed project-specific engineering, it serves as a foundational reference for understanding the complex systems involved in liquefying natural gas for transport.

2. Design Basis and Specifications

2.1 Feed Gas Composition

The feed gas composition is the single most critical design input. Because gas sources vary over the life of a field, a composition envelope (covering lean to rich cases) must be defined. Key contaminants that must be removed to prevent freezing in the cryogenic sections include:

• Carbon Dioxide (CO₂): Freezes at approx. -56.6°C.
• Water (H₂O): Forms ice and hydrates, blocking equipment.
• Mercury (Hg): Causes catastrophic liquid metal embrittlement (corrosion) of aluminium heat exchangers.
• Heavy Hydrocarbons (C5+): Can freeze, causing blockages. Benzene is a particular concern.
• Sulphur Compounds (H₂S, mercaptans): Must be removed to meet sales gas specifications and prevent corrosion.

2.2 LNG Product Specifications

LNG is traded globally, and specifications are often set by long-term sales contracts. Key parameters include:

• Higher Heating Value (HHV) & Wobbe Index: Determines the energy content. Markets like Japan often prefer "rich" LNG (higher heating value), while North America and Europe may prefer "lean" LNG.
• Nitrogen (N₂): Typically limited to < 1 mol% to prevent stratification ("rollover") in storage tanks at the receiving terminal.
• Sulphur: H₂S typically < 5 mg/Nm³; Total Sulphur < 30 mg/Nm³.
• Mercury: Typically < 10 ng/Nm³ to protect downstream customer equipment.

3. Liquefaction Technologies

Liquefaction is the heart of the LNG plant, cooling natural gas to approximately -162°C (-260°F). The choice of technology depends on plant capacity, efficiency requirements, and specific project constraints (e.g., floating vs. onshore).

3.1 Major Technologies

• Propane Precooled Mixed Refrigerant (C3MR): The most widely used technology (e.g., by Air Products - APCI). It uses a pure propane cycle for precooling and a mixed refrigerant (MR) cycle for liquefaction and subcooling. Known for high efficiency and large capacity (up to ~5 MTPA per train).
• Optimised Cascade Process (OCP): Developed by ConocoPhillips. Uses three pure refrigerant cycles: propane, ethylene, and methane. Known for reliability and ease of operation, typically using brazed aluminium heat exchangers (BAHX).
• Dual Mixed Refrigerant (DMR): Uses two mixed refrigerant cycles. Offers flexibility, especially for cold climates where propane precooling is less efficient. Used by Shell (e.g., Sakhalin, Prelude FLNG).
• AP-X (APCI): Adds a third, nitrogen refrigeration cycle to the C3MR process for subcooling. Allows for very large train sizes (e.g., 7.8 MTPA trains in Qatar).
• Nitrogen Expander Cycles: Use nitrogen as the sole refrigerant. Lower efficiency but inherently safer (non-flammable refrigerant) and simpler. Often preferred for small-scale or floating LNG (FLNG) where safety and motion insensitivity are paramount.

3.2 Main Cryogenic Heat Exchanger (MCHE)

This is the defining piece of equipment in the liquefaction train.

• Coil-Wound Heat Exchanger (CWHE): Robust, tolerant to rapid temperature changes, and capable of very large capacities. The standard for C3MR and AP-X processes. Consists of thousands of tubes wound around a central mandrel inside a high-pressure shell.
• Brazed Aluminium Heat Exchanger (BAHX) / Plate-Fin: Compact, highly efficient, and lower cost. Used extensively in Cascade and smaller-scale processes. More sensitive to thermal shock and flow maldistribution, especially in two-phase applications.

4. Gas Treatment

Before liquefaction, the feed gas must be rigorously treated to remove freezing components.

4.1 Acid Gas Removal Unit (AGRU)

Removes CO₂ and H₂S using an amine solvent (typically activated MDEA). The CO₂ must be reduced to < 50 ppmv to prevent it from freezing and plugging the main cryogenic heat exchanger.

4.2 Dehydration Unit

Removes water to < 0.1 ppmv using molecular sieve adsorption beds. Typically a 3-bed system (two on adsorption, one on regeneration) is used. Regeneration is done with hot, dry gas (often recycled boil-off gas or treated feed gas).

4.3 Mercury Removal Unit (MRU)

Mercury must be removed to non-detectable levels (< 10 ng/Nm³) because it amalgamates with aluminium, causing catastrophic liquid metal embrittlement in cryogenic exchangers. Non-regenerative adsorbent beds (sulphur-impregnated carbon or metal sulphides) are used. Modern designs often place the MRU *upstream* of the AGRU to prevent mercury from contaminating other plant sections.

5. LNG Storage and Loading

5.1 Storage Tanks

LNG is stored at atmospheric pressure and approx. -162°C. The main tank types are:

• Full Containment: The industry standard for onshore. Consists of a cryogenic steel inner tank (e.g., 9% Nickel steel) and a concrete outer tank. Both tanks are capable of containing the full liquid cargo in case of a leak.
• Membrane: Common in LNG carriers and some modern onshore designs. Uses a thin, flexible metal barrier supported by rigid insulation.

5.2 Boil-Off Gas (BOG)

Heat entering the tanks and loading lines causes a small amount of LNG to continuously evaporate. This BOG is collected, compressed, and either used as fuel gas for the plant or re-liquefied and returned to storage.

5.3 Loading Systems

LNG is loaded onto carriers using specialized cryogenic loading arms equipped with emergency release systems (ERS) to quickly disconnect in case of a ship drift or other emergency. A vapour return line balances the pressure between the ship and the shore tanks during loading.

6. Floating LNG (FLNG) Considerations

Designing an LNG plant on a floating vessel introduces unique challenges: