Apr-2025

Dynamic simulation of an LNG plant fuel gas system

Scenario modelling pinpoints pathways to prevent turbine trips seen with temperature, pressure, and instantaneous fuel gas compositional changes, ensuring reliability.

Harry Z Ha, Cole Beattie and Javeed Mohammed
Fluor Canada Ltd

Article Summary

The global natural gas (NG) market has expanded significantly in recent years, with abundant supply from North America fuelling growing demand in Asia and Europe. Asian and European nations are looking to liquefied natural gas (LNG) as a pathway to pivot away from coal-fired power generation and lower their greenhouse gas emissions. Energy security is also a growing concern for these same nations, and access to a responsible and reliable supply of energy has bolstered demand for North American LNG. With this growing demand, the reliability of LNG production and export facilities in North America is paramount, as any time spent offline could lead to lost revenue and giving up market share to other LNG producers in the Middle East and Asia.

LNG is produced by liquefying NG with a refrigerant, which needs to be compressed as part of the refrigeration cycle. NG turbines are typically used to power the gearboxes driving the refrigerant compressors in LNG facilities. If these turbines are interrupted, entire trains of LNG production can trip offline. Preventing turbine trips is a crucial step in ensuring LNG facility reliability. Given lengthy shutdown and start-up procedures for turbines and compressors within the LNG train, unscheduled downtime on an LNG train costs owners and operators millions of dollars per day.

Gas turbines require a consistent supply of fuel gas (FG), and careful consideration must be taken in the design of the FG system to ensure the turbines can handle expected interruptions to both the gas supply and demand within LNG facilities. Any sudden changes to the FG pressure or the FG composition can lead to a trip in the gas turbines. Accounting for these interruptions ensures the overall reliability of the LNG facility and that it can meet its production targets and commercial obligations.

LNG plant FG system
The FG supply for the gas turbines in an LNG facility is normally sourced from the overhead vapour space in the LNG storage tanks. As the LNG storage tanks are filled or the ambient air temperature rises, the vapour pressure in the tank rises, requiring venting of vapour within the tank. This vapour, known as ‘boil-off gas’ (BOG), is an economical fuel source for LNG facilities. In many LNG facilities, this BOG is compressed using BOG compressors to fuel the gas turbines needed for LNG production.

If the LNG storage tanks are being emptied, or there is any disruption or maintenance impacting the BOG compressors, the BOG supply to the gas turbines will be interrupted. To prevent gas turbine trips in these likely scenarios, a backup fuel supply is provided by NG, typically from the main LNG plant supply.

Changing the fuel source from BOG to NG introduces a compositional change to the fuel supply, which the gas turbines cannot handle instantaneously. To accommodate this, FG mixing drums are installed in LNG facilities to sufficiently mix the FG supply fed to the gas turbines. The composition of the FG is defined with a Modified Wobbe Index (MWI). Typically, the Wobbe Index is used to measure the ratio of a gas heating value (HV) and square root of its specific gravity (SG), relative to air. However, to ensure better consistency between different fuels supplied at different conditions, it is ‘modified’ by controlling for temperature (Tgas) in degree Rankine and uses the lower heating value (LHV) in BTU/scf, as shown in Equation 1:1

                        (1)

The MWI is used to compare the combustion energy output of different fuels at different temperatures. While gas turbine designs vary, typically, the FG composition fed to the gas turbine indicated by the MWI cannot vary by more than ±5% per minute. FG mixing drums are critical to ensure that when the fuel supply is changed, the transition is slowed to prevent the FG composition from changing so quickly that the gas turbines are tripped.

Inlet pressure and temperature of the FG are also key parameters affecting gas turbine performance. Any reduction in temperature or pressure to the gas turbine inlet will reduce the gas turbine efficiency and increase steam consumption in other auxiliary steam turbines. While gas turbine design can vary, the turbines considered in this article are designed to handle a maximum pressure swing of 10 psi per second.

The overall FG system, including its compressors and turbines, is protected from major upsets with a valve that releases excess FG to a flare header. This valve, along with the backup NG valve and pressure control on the compressors, makes up the control scheme for the FG system depicted in Figure 1.

Upset scenario modelling
In line with process engineering design best practice, the previously described FG system must be tested against various upset scenarios to ensure system reliability. A dynamic simulation model was developed according to the configuration shown in Figure 1. The dynamic simulation accounts for transitional changes in the system, reflecting changes in composition, pressure, and temperature during upsets while taking credit for system volumes and elevations. The dynamic simulation also simulates controller actions and effects, which are ignored by steady-state models. Such rigorous simulations offer accurate predictions of system response and provide a reliable basis for engineering design.

Two scenarios are considered in the FG system dynamic simulation. The first considers how backup NG will balance the system if the BOG supply to the gas turbines is lost. The second considers how the system will handle a pressure increase when a gas turbine trips. In this scenario, the FG system uses valves to send excess FG to the flare header while the FG system adjusts.

Scenario 1: BOG compressors trip
Gas turbines are designed to operate using BOG because it is typically the more economical fuel source available at LNG facilities. However, as outlined, there are several scenarios where BOG may not be available. In these scenarios, NG is used as a substitute, which has a higher energy content and allows the gas turbines to operate more efficiently.

Since BOG is the saturated vapour fraction of the LNG stored in the LNG storage tanks, it typically contains ~16% nitrogen gas. Due to its composition, BOG’s heating value is less than that of the NG used to balance the supply when BOG is not available. A reason for this is NG typically has a small composition of natural gas liquids (NGLs).

NGLs are not present in any meaningful quantity within the BOG. Therefore, when switching from BOG to NG, a lower FG flow rate will be required in the gas turbine due to the higher heating value. If the flow rate to the gas turbine is not reduced, the temperature in the turbine increases, causing it to trip. MWI is used to evaluate both the compositional and temperature impacts on the gas turbines. The trip of the BOG compressors is simulated with the following assumptions:
· BOG has an MWI of 40.
· NG has an MWI of 50.
· BOG compressors have an outlet pressure of 1,073 psig.
· Backup FG supply has a pressure of 1,044 psig.
· The gas turbine main header has a normal operating pressure of 967 psig.
· Gas turbine sub-headers have a normal operating pressure of 962 psig.
· The balancing FG line will open automatically and introduce backup FG to the system once the BOG compressor trips.