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LNG FPSO MPDS (Multi-Purpose Dynamic Simulator) PROJECT (1) – General & Acid Gas Removal Unit

The process is designed for the MPDS (Multi-Purpose Dynamic Simulator) development of the LNG (Liquefied Natural Gas) FPSO (Floating Production Storage and Offloading) topside process. The design concept, engineering data and information included in this document and “Basic and Engineering Design Package ....

1. General

The process is designed for the MPDS (Multi-Purpose Dynamic Simulator) development of the LNG (Liquefied Natural Gas) FPSO (Floating Production Storage and Offloading) topside process. The design concept, engineering data and information included in this document and “Basic and Engineering Design Package (Doc. No. KOMERI-MPDS-DSG-0001)” shall be used only for the development of KOMERI MPDS system and not be applied for a construction of actual topside process of LNG FPSO.

As described in the specifications, the MPDS will be developed not for an actual LNG FPSO project, but for a virtual LNG FPSO topside process which will be designed in this project. The Basic and Engineering Design Package (Doc. No. KOMERI-MPDS-DSG-0001) includes all design information which is essential for the MPDS development, for example Process Description, PFD, P&ID, equipment/instrument datasheets, C&E chart, control narrative, etc.

The MPDS will be developed for KOMERI to apply the dynamic simulator for the purpose of R&D as well as operator training for the LNG FPSO topside process and the following is a summary for the key application areas of the LNG FPSO MPDS. This document aims to design and develop an LNG FPSO topside process which is adequate for the following MPDS applications.

  • Engineer and operator training who are associated with LNG FPSO topside process
  • Familiarization for the LNG FPSO topside process
  • Process/equipment design and optimization
  • HAZOP analysis
  • Development of operation procedure
  • Process/safety control design and analysis
  • APC (Advanced Process Control) design

The basic concept and idea of this process design is to configure the topside process of LNG FPSO in general with publicly proven and published gas treatments, liquefaction and fractionation processes and to feed the input data and design information which are required for the development of LNG FPSO MPDS system. This basic and engineering design will contain all information enough to develop the MPDS system and help engineers and operators associated with LNG FPSO understand the process design and operation of natural gas liquefaction process.

The topside process is designed to produce 120 kg/s (3.5 MTPA) LNG with the following feed gas conditions which are assumed that the natural gas comes from pressure boundary replacing the pressure control unit of natural gas wellhead in an actual natural gas production system. The feed gas conditions are assumed to give a design basis of the process and can be changed by instructor and/or end-user in the MPDS system so that they can simulate various operating conditions in accordance with the change of feed gas conditions.

To produce 3.5 MTPA LNG with the conditions of feed natural gas in Table 1, the process consists of the following six (6) units.

  • Unit A-1000 : Acid Gas Removal Unit
  • Unit D-2000 : Dehydration Unit
  • Unit M-3000 : Mercury Removal Unit
  • Unit L-4000 : Liquefaction Unit
  • Unit F-5000 : Fractionation Unit
  • Unit U-6000 : Fuel Gas Unit

The MPDS dynamic model shall be constructed such that each unit is integrated into one (1) model as they share both process and control interactions.

In an actual LNG production plant, the initial operation will be purging and defrosting operation and in general, this operation is carried out by field operator. As this process design is to target the MPDS development and control room operator training, the purging and defrosting equipments and pipelines are not included. The process is assumed that dry out and defrosting operations are completed prior to the plant startup.

 Figure 1 shows the schematic block diagram for the process units and material and heat flow.

Figure 1. Schematic Block Diagram for Process Overview

Table 1. Feed Gas Design Conditions
[table id=36 /]

2. Acid Gas Removal Unit (A-1000)

2.1 Design Concept and Basis

The removal of acid gases such as hydrogen sulphide (H2S) and carbon dioxide (CO2) from process gas streams is required in LNG plants. There are many treating processes available. However, no single process is ideal for all applications. The initial selection of a particular process may be based on feed parameters such as composition, pressure, temperature and the nature of the impurities, as well as product specifications. Final selection is ultimately based on process economics, reliability, versatility and environmental constraints. Clearly the selection procedure is not a trivial matter and any tool that provides a reliable mechanism for process design is highly desirable.

Acid gas removal processes using absorption technology and chemical solvents are popular, particularly those using aqueous solutions of alkanolamines. In this project, the absorption/desorption processes to remove CO2 from feed natural gas are designed with DEA (diethanolamine) aqueous solution which is generally used in the oil & gas industries. The thermodynamic physical property and absorption/desorption processes with DEA aqueous solution are fully supported by UniSim which is used for the process design and dynamic model development of this project.

The conventional process configuration for a gas treating system that uses aqueous alkanolamine solutions consists of absorption and desorption (amine regeneration) processes. The sour gas feed is contacted with amine solution counter-currently in a trayed or packed absorber. Acid gases are absorbed into the solvent that is then heated and fed to the top of the regeneration tower. Stripping steam produced by the reboiler causes the acid gases to desorb from the amine solution as it passes down the column. A condenser provides reflux and the acid gases are recovered overhead as a vapour product. Lean amine solution is cooled and recycled back to the absorber.

A partially stripped, semi-lean amine stream may be withdrawn from the regenerator and fed to the absorber in the split-flow modification to the conventional plant flowsheet. A three-phase separator or flash tank may be installed at the outlet of the absorber to permit the recovery of dissolved and entrained hydrocarbons and to reduce the hydrocarbon content of the acid gas product.

2.2. Process Theory

The CO2 in the feed gas reacts with the DEA and water according to the reactions shown below.

The reversible reaction for Carbon dioxide and DEA is as follows.

CO2 + 2R2NH « R2NCOO + R2NH2+

The reversible reaction for Carbon dioxide, Water and DEA is as follows.

CO2 + H2O + R2NH « HCO3 + R2NH2+

Note:     In the overall reaction equations, R denotes the ethanol group (CH2-CHOH)

The chemical equilibrium of these reactions shifts to the right-hand side of the equations at lower temperatures and higher pressures resulting in the CO2 being removed from the feed gas and an increase in the concentration of CO2 in the Amine solvent.  This is an exothermic reaction.

At higher temperatures and lower pressures (as applied in regenerator A-C-1002) the chemical equilibrium is shifted to the left-hand side of the equations resulting in the removal of the CO2 from the solvent.

2.3 Process Description

The purpose of this acid gas removal unit (A-1000) is to remove CO2 from the natural gas feed to the liquefaction unit to prevent it from freezing out at low temperature and to meet the LNG product specification.

Basically, the Unit A-1000 consists of absorption (A-C-1001) and regeneration (A-C-1002) columns. The feed to the unit A-1000 is natural gas from the pressure boundary replacing a plant pressure control station downstream of natural gas wellhead in an actual plant. The feed gas enters the unit at 62 bara and 15 ℃ and is fed to the feed gas knock-out vessel (A-V-1001), where liquid hydrocarbons or other contaminants will be dropped out to avoid contamination and foaming of the amine solution. Any liquids from A-V-1001 are sent to the atmospheric pressure boundary which is a battery limit of this project and has no more process to treat the liquids. The gas is then pre-heated in the feed gas heater (A-E-1006) to 25 ℃ with heating medium coming from the pressure boundary. This project does not include the heating medium production process and treats as a battery limit.

The feed gas flows into the absorber (A-C-1001) entering the column below tray 1. Lean solvent enters the top of the absorber and flows counter-currently to the feed gas, thereby absorbing the acid gas.

The treated gas leaving the top of the absorber flows through the treated gas cooler (A-E-1005) which cools the gas to 45 ℃. The treated gas then flows through the Drier Pre-cooler (L-E-4015) in the Liquefaction Unit (L-4000) which cools more to 22 ℃  and passes to the feed gas separator (D-V-2003) in the molecular sieve dehydration unit (D-2000).

The treated gas from Unit A-1000 must meet a CO2 specification of 50 ppmv maximum.  The normal CO2 content of the treated gas exiting Unit A-1000 is expected to be 20-40 ppm, or less.

The rich amine solution (acid gas loaded) leaves the bottom of the absorber A-C-1001 and is reduced in pressure to 9 bara through level control valve (A-LCV-1002) before entering the rich amine flash drum (A-V-1003) to flash off hydrocarbons which are entrained and dissolved in the solution. The flashed vapours are vented to the flare system which is assumed as pressure boundary in this process design.

The CO2 rich solvent is then heated in the Rich/Lean Amine Exchanger (A-E-1001A/B) to about 100 ℃where it is counter-currently contacted with hot solvent from the regenerator A-C-1002 before it enters A-C-1002 near the top of the column.

In the regenerator A-C-1002, the acid gas components (CO2) are stripped from the solvent at elevated temperature (120 ℃ at the bottom) and low pressure (1.8 bara) using steam generated in the Regenerator Re-boilers (A-E-1002). The duty of the re-boiler is delivered via the heating medium coming from the pressure boundary.

The regenerated lean amine solvent is withdrawn from the bottom of the regenerator (A-C-1002) and flows through A-E-1001A/B and pumped (A-P-1003A/B) to the Lean Amine Cooler (A-E-1004) which is a trim cooler to regulate  the regenerated lean amine temperature (~ 53 ℃) in a narrow temperature range before storage . The lean solvent exiting A-E-1004 is stored at the atmospheric pressure in the Amine Storage Tank (A-T-1001). The regenerated lean amine is then pumped from A-T-1001 to A-C-1001 by Amine charge pump (A-P-1001 A/B).

The Acid gas and steam are water-washed by the sour water reflux from the Reflux Pump (A-P-1002 A/B) on the top trays in the regenerator A-C-1002. This stream is then cooled to 45.5 Deg C in the Regenerator Overhead Condenser (A-E-1003) before the condensed sour water is separated in the Regenerator Reflux Drum (A-V-1002). The water is pumped back to A-C-1002 by A-P-1002 A/B while the acid gas is sent to the pressure boundary to control the pressure at 1.5 bara and the pressure boundary is a battery limit of this project. The control valve (A-PCV-1004 A/B) on the acid gas outlet from V-1102 is used to control the Regenerator pressure. The continuous demineralised water make-up stream also feeds A-V-1002 through the flow control valve (A-FCV-1007).

This project does not include amine cleaning, anti-forming, hydrocarbon skimming and make-up systems which are required for an actual acid gas removal process.

Figure 2 shows the overall process of the acid gas removal unit (A-1000).

Figure 2 Overall Process of the Acid Gas Removal Unit


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