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Optimize LNG boil-off gas systems for regasification terminals

01.01.2013  |  Zolfkhani, M. ,  Ranhill WorleyParsons, Kuala Lumpur, Malaysia

Depending on LNG composition, N2 content and plant operating mode, an operating pressure of 7 barg to 8 barg was found by the study to be the optimum pressure range.

Keywords: [boil-off gas] [LNG] [regasification] [natural gas] [terminals] [engineering and design]

Boil-off gas (BOG) generation is an inherent part of natural gas liquefaction, transportation and gasification. It varies depending on site temperature, climate condition, integrity of insulation and plant operating mode.

Optimization of a BOG system focuses on the optimum operating pressure of the BOG handling system, which affects BOG compressor configuration, process and flare systems design, operating philosophy, startup procedures, line sizes and plant performance. In this examination, different case studies were performed to minimize hydrocarbon loss, flaring and energy consumption.

To generalize the results, two extreme compositions (lean and rich) were considered in the case studies. Three scenarios for regasification terminal send-out pressure were considered (40 barg, 70 barg and 100 barg). Two BOG generation scenarios were assumed:

  1. Simultaneous gas send-out and liquefied natural gas (LNG) unloading
  2. Gas send-out without LNG unloading.

These scenarios resulted in maximum and minimum BOG generation, respectively. Operating expenditure (OPEX) increased slightly at higher operating pressures; however, BOG recondensation capacity improved significantly.

Depending on LNG composition, nitrogen (N2) content and plant operating mode, an operating pressure of 7 barg to 8 barg was found to be the optimum pressure range at which minimum hydrocarbon loss would occur.


Regasification terminals can receive LNG with different compositions and specifications. A range of hydrocarbon components, plus N2, exists in LNG. Due to heat absorption by piping, tanks and equipment, a part of the LNG is continuously turned into vapor. The amount and composition of BOG varies over time.

Vaporized LNG is mainly methane (CH4) and N2. The hydrocarbon content of BOG varies between 75 mol% and 95 mol%, depending on the mode of operation and the LNG composition. Therefore, vaporized hydrocarbons should be recovered to minimize hydrocarbon loss and BOG flaring.

The amount of BOG generated in terminals depends on the capacity of the plant and can be as high as 100 million standard cubic feet per day (MMscfd). Thus, recovery of BOG is a crucial operation in every LNG receiving terminal.

Process scheme

Different process schemes are applied in LNG receiving terminals around the world. The regasification process on which this study was based uses seawater and a circulating medium (propane) to warm up and vaporize the LNG. Fig. 1 shows a schematic of the system. Regardless of the process applied, the concept of BOG recondensation remains the same.

  Fig. 1. Process schematic of a regasification
  facility (as used in case studies). 

During front-end engineering and design (FEED), a survey was conducted to select the appropriate BOG handling configuration. Using lessons learned from existing plants, a combination of heat exchangers and direct LNG BOG contactors was applied to maximize BOG condensation. Fig. 2 illustrates the details of the system that was designed.


  Fig. 2. Proposed configuration of BOG
  recondensation system. 

Simulation model

A simulation platform was used to run case study scenarios, and the Peng-Robinson equation of state was utilized as a base correlation for the fluid package. The rest of the options in the fluid package were maintained at default values.

Case studies

In LNG receiving terminals, generated BOG can be recondensed using high-pressure LNG before being regasified. The dewpoint of BOG is a function of its composition. In turn, the N2 content of BOG has the greatest impact on dewpoint, as N2 is the most volatile component in BOG composition.

The nitrogen mole fraction in BOG is directly related to the N2 content of LNG. The higher the N2 content in the LNG, the more the N2 vaporizes with BOG. In the performed case studies, the N2 mole fraction in BOG is in the range of .05–.25. (LNG N2 mole percentage is a maximum of 2%; most LNG specifications contain less than 2 mol% N2.) Higher N2 content in BOG shifts the multiphase area to the left in a phase-envelope diagram—i.e., full condensation can be achieved at higher BOG pressures.

Keeping this fact in mind, at certain LNG compositions, greater BOG generation will result in a lower concentration of N2 in the vapor phase. It is, therefore, common to see maximum N2 mol% in lean LNG BOG compositions, along with minimum BOG generation in a facility, as can be inferred from Figs. 4–6. The higher the N2 content, the more energy is required to recondense the BOG. Two phase-envelope diagrams are shown in Fig. 3, wherein the phase-change behaviors of different compositions and BOG generation rates are compared.


  Fig. 3. BOG phase envelope charts for
  two extreme cases. 


  Fig. 4. High-high pressure (LNG pressure
  of 100 barg) condensation performance
  for different cases. 


  Fig. 5. High-pressure (LNG pressure of
  70 barg) condensation performance
  for different cases. 


  Fig. 6. Low-pressure (LNG pressure of
  40 barg) condensation performance
  for different cases. 


Although BOG condensation can start from BOG pressures as low as 3 barg, the majority of the BOG will be turned into liquid only at pressures higher than 6 barg (Figs. 4–6). Setting BOG operating pressure at the highest possible level will ensure full condensation, but it may not be a cost-effective or energy-efficient option.

An OPEX study was performed to discern the optimum operating pressure range. The main items considered in the OPEX calculations were electricity and fuel gas cost (Table 1 and Fig. 7).


  Fig. 7. OPEX comparison for different
  operating scenarios in high-pressure case. 

From Fig. 7, it can be seen that, during normal operation (no LNG cargo unloading), a pressure range of 7 barg to 8 barg minimizes OPEX. A clearer prospective of the operating scenarios for high-pressure LNG can be derived from Table 1. Here, the most credible scenario is shown as a lean composition with minimum BOG generation, and OPEX and BOG flaring results are tabulated.



It is advisable to design a BOG handling system for a maximum operating pressure of 8 barg. At an operating pressure of 7 barg to 8 barg, both BOG flaring and OPEX are kept to a minimum.


I would like to take the opportunity to express my thanks to the entire project team at Ranhill Worley-Parsons, which supported me during this study—especially Jag Ghantala (project manager) and Viren Vartak (process lead), who reviewed this article and encouraged me to publish the study results. HP

The author 

Majid Zolfkhani holds degrees in chemical engineering from Sharif University of Technology (BSc) and Iran University of Science and Technology (MSc), both in Tehran. Mr. Zolfkhani is a chartered member of the Institution of Chemical Engineers (IChemE), as well as a chartered member of Engineers Australia, with 12 years of process engineering experience. He has worked with Ranhill WorleyParsons since March 2008 as a senior process engineer, accepting technical and leadership roles for a variety of brownfield, greenfield, offshore and onshore projects. 

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