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Summary: The use of liquefied natural gas (LNG) has grown over the last decade owing to an increase in the global energy demand. This work presents a pioneering approach for rigorous simulation of an actual cold section of an LNG plant and provides a potential process optimization to achieve a higher production rate (PR) while reducing the specific power consumption (SPC). The concept of upfront nitrogen removal (UNrem) from the natural gas (NG) feed was introduced, and the impact on the PR and SPC was presented. We considered seven scenarios with varying percentages of UNrem and compared them with the conventional plant design (base case) while maintaining the product specifications (LNG high heating value [HHV] of 1105 Btu/Scf and NGL reid vapor pressure [RVP] of 2042 psia). The results show that UNrem of 87.5% from the NG feed can reduce the total power requirements by 0.24%, increase the production flow rate by 4.4%, and decrease the exergy losses by 0.23% compared with the base case. The UNrem can also have a significant improvement on the plant capacity without the need for structural modifications in the cold section. Future research should focus on the efficiency and feasibility of different UNrem processes as well as examine the use of a large‐scale system. [ABSTRACT FROM AUTHOR]

[Display omitted] • Integration potential between regasification terminals and methylcyclohexane dehydrogenation plants. • Proposed integrated terminal design for cold energy recovery and utility reduction. • 45.4 % reduction in reaction pre-heating and 104 % reduction in external power, based on a case study. • Hydrogen production capacity of 11.1–12.0 tonnes per 100 tonnes of liquified natural gas. • Up to 7.1 tonnes per hour of hydrogen produced without external power input. Methylcyclohexane (MCH) is a promising organic hydride carrier for hydrogen transport and storage. Recovering hydrogen from MCH is an energy intensive process. An innovative idea of integrating this process with liquified natural gas (LNG) regasification is proposed in this study and demonstrated via modelling and simulation to substantially reduce external energy use. The synergistic benefits are twofold. In addition to providing a cold energy source for an effective high recovery cryogenic flash separation, the organic Rankine cycle based electrical power generation potential from LNG cold energy is fully exploited to reduce/eliminate external electricity demand for hydrogen compression to the high (end use) pressure. The results is a major reduction in carbon dioxide emissions. The proposed design for an integrated LNG-H 2 terminal can supply (1) 99.99 mol% pure hydrogen to a Combined Cycle Gas Turbine (CCGT) power plant and (2) commercial-grade natural gas to a gas-grid, both at the desired pressures and temperatures. Subsequently, rigorous simulation-based optimization was performed to minimize external energy inputs. A case study with 100 tph MCH and 100 tph LNG showed that integrating regasification with dehydrogenation produced 6.2 tph of hydrogen while gasifying LNG with a net power generation of 310 kW and a hydrogen recovery cost of 0.282 $/kg H 2. Up to 7.3 tonnes of hydrogen can be produced per 100 tonnes of LNG without the use of external power. On the other hand, using external power, up to 11.3 tonnes of hydrogen can be produced per 100 tonnes of LNG without any external refrigeration. Overall, the superstructure proposed in this manuscript provides a generic initial approach for future MCH hydrogen supply chain projects, when considering integrations with LNG regasification plants. [ABSTRACT FROM AUTHOR]

• A novel inlet air cooling system based on liquefied natural gas cold energy utilization. • The performance of the novel system and the power plant is evaluated. • The novel system produces lower air temperature and higher cooling duty. • It improves the power plant performance under all ambient conditions. • The novel inlet air cooling system is economically viable. The performance of gas turbine-based power plants decreases significantly as ambient temperature increases. For improving power plant performance, this paper proposes a novel inlet air cooling system based on liquefied natural gas cold energy utilization. The novel system consists of two organic Rankine cycles in series and a mechanical vapor compression chiller. A simulation-based optimization method is developed to optimize its design parameters for maximizing the power plant performance. Moreover, the off-design performances of the proposed system and the power plant with and without inlet air cooling are evaluated under different ambient conditions. The results show that the novel inlet air cooling system gives larger air temperature drop (2.1–5.3 °C) and higher cooling duty (6.9–7.3 MW) than a literature design. Furthermore, for 28–40 °C ambient temperatures, the power plant with the novel inlet air cooling produces 1.83–14.4% (6.4–52.6 MW) higher power output than that without inlet air cooling. Importantly, the novel cooling system improves the plant power output by 0.79–3.04% (2.8–11.1 MW) when compared with the literature design. Finally, the economic analysis shows that the proposed system is economically viable with a net present value of $1.6–34.4 million higher than the literature design. [ABSTRACT FROM AUTHOR]

Boil-off gas (BOG) generation in liquefied natural gas (LNG) regasification terminals is substantial and unavoidable. Most terminals employ a cost-intensive BOG reliquefaction process using the send-out LNG. In this work, we study the preliminary design of this process with the objective of minimizing its total annualized cost (TAC). We present a comprehensive superstructure for the reliquefaction process that incorporates several process options for cooling BOG using LNG at different pressures, and allows recondensation in multiple stages. Then, we develop custom simulation/sizing modules for the process units in our superstructure, and implement a procedure to reduce explicit constraints during optimization. Considering realistic design specifications and operational constraints, we optimize a case study terminal for various BOG rates and conditions. While the TAC increases substantially with BOG rate, two-stage recondensation is always optimal. A 2-recondenser scheme with BOG cooling by the high-pressure LNG before the first recondenser is optimal for most cases. [ABSTRACT FROM AUTHOR]

LNG is expected to play a major role in global natural gas trade. Implementing a heating value adjustment unit within regasification terminal allows importing of LNG from diverse sources around the world, thus increasing the energy security of the importing country. In this study, we focus on heavy hydrocarbons removal (HHR) as a strategy to reduce heating value of LNG to meet desired specifications. We have developed a superstructure for the HHR process, which is optimized using a particle swarm optimization algorithm to maximize profitability of the HHR process. The optimal process configuration not only meets heating value specification but also utilizes LNG's cold energy to liquefy the methane-rich stream before pumping to send out pressure and produces ethane and LPG as co-products. Our technoeconomic analyses show that at the current prices of co-products, the HHR process configuration yields 7-10% profit depending on the heating value of the LNG feed. [ABSTRACT FROM AUTHOR]

Liquefied natural gas (LNG) has been the fastest increasing fossil fuel in the world energy market due to its low carbon dioxide emission, high energy density, and ease of transport. However, the liquefaction of natural gas is one of the most energy-intensive industrial processes. Thus, it is very important to design new liquefaction processes and optimize the existing ones in order to reduce the energy consumption. In this paper, we present a state-of-the-art review of the recent progress on the design and optimization of NG liquefaction processes for onshore and offshore applications. The current onshore processes include the cascade, mixed refrigerant, and expander-based processes, of which the mixed refrigerant process has received the most attention. The common objective function of the onshore LNG process optimization is the minimization of the energy consumption. However, for the offshore applications, the single mixed refrigerant and nitrogen expansion processes have been considered to be the promising options. For these, deck space and sensitivity to platform waving need be considered apart from energy consumption. Finally, we propose several potential developments for NG liquefaction process design and optimization. [ABSTRACT FROM AUTHOR]

Conventional natural gas (NG) liquefaction processes remove N2 near the tail of the plant, which limits production capacity and decreases energy efficiency and profit. Engineering calculations suggest that upfront N2 removal could have substantial economic benefits on large-scale liquefied natural gas (LNG) processes. This article provides an overview of the most promising technologies that can be employed for upfront N2 removal in the LNG process, focusing on the process selection and design considerations of all currently available upfront N2 removal technologies. The literature review revealed that although adsorption has proven to be a huge success in gas separation processes (efficiency ≥ 90%), most of the available adsorbents are CH4-selective at typical NG conditions. It would be more encouraging to find N2-selective adsorbents to apply in upfront N2 removal technology. Membrane gas separation has shown growing performance due to its flexible operation, small footprint, and reduced investment cost and energy consumption. However, the use of such technology as upfront N2 removal requires multi-stage membranes to reduce the nitrogen content and satisfy LNG specifications. The efficiency of such technology should be correlated with the cost of gas re-compression, product quality, and pressure. A hybrid system of adsorption/membrane processes was proposed to eliminate the disadvantages of both technologies and enhance productivity that required further investigation. Upfront N2 removal technology based on sequential high and low-pressure distillation was presented and showed interesting results. The distillation process, operated with at least 17.6% upfront N2 removal, reduced specific power requirements by 5% and increased the plant capacity by 16% in a 530 MMSCFD LNG plant. Lithium-cycle showed promising results as an upfront N2 chemical removal technology. Recent studies showed that this process could reduce the NG N2 content at ambient temperature and 80 bar from 10% to 0.5% N2, achieving the required LNG specifications. Gas hydrate could have the potential as upfront N2 removal technology if the is process modified to guarantee significant removals of low N2 concentration from a mixture of hydrocarbons. Retrofitting the proposed technologies into LNG plants, design alterations, removal limits, and cost analysis are challenges that are open for further exploration in the near future. The present review offers directions for different researchers to explore different alternatives for upfront N2 removal from NG. [ABSTRACT FROM AUTHOR]

Boil-off Gas (BOG) generated at the liquefied natural gas (LNG) export terminal causes negative economic and environmental impacts. Thus, the objective of this study is to develop and evaluate various handling schemes to minimize and/or recover the generated BOG from an actual baseload LNG export terminal with a capacity of 554 million standard cubic feet per day (MMSCFD) of natural gas feed. The following three main scenarios were assessed: JBOG re-liquefaction, LNG sub-cooling, and lean fuel gas (LFG) reflux. For the LNG subcooling, two sub-cases were considered; standalone subcooling before LNG storage and subcooling in the prevailing liquefaction cycle. Steady-state models for these scenarios were simulated using Aspen Plus® based on a shortcut approach to quickly evaluate the proposed scenarios and determine the promising options that should be considered for further rigorous analysis. Results indicated that the flow of attainable excess LNG is 0.07, 0.03, and 0.022 million metric tons per annum (MTA) for the standalone LNG sub-cooling, LNG sub-cooling in the main cryogenic heat exchanger (MCHE), and both LFG-refluxing and jetty boil-off gas (JBOG) liquefaction, respectively. This in turn results in a profit of 24.58, 12.24, 8.14, and 7.63 million $/year for the LNG price of 7$ per Metric Million British Thermal Unit (MMBtu) of LNG. [ABSTRACT FROM AUTHOR]

• Comprehensive, efficient, industrially useful spatiotemporal dynamic model for simulating state transients in an energy fluid storage system. • The storage system may have arbitrary initial conditions, feed/product and recirculation flows, multicomponent evaporation/condensation, heat leaks, and boil-off gas removal. • Novel, adaptive, spatially moving grid for tracking sharp and moving vapor-liquid interface. • Rigorous expressions for multicomponent evaporation/condensation in storage systems near saturation conditions. • Complete model validation and demonstration on industrial storage terminals for hydrogen, LNG, and liquid air. As the world adopts cleaner and/or renewable energy sources, energy fluids (e.g. hydrogen, ammonia, liquefied natural gas, liquid air, etc.), their transport, and their storage are becoming increasingly important. Feed/product flows, flashing recirculation flows, evaporation, condensation, heat leak, and boil-off gas removal lead to state transients in their storage systems with significant mechanical, safety, environmental, and efficiency implications. This study presents a comprehensive simulation model based on a novel stretchable and spatially moving grid for predicting spatiotemporal transients in a cylindrical storage tank. The model is fully validated under limiting scenarios and then applied to several industrial storage terminals involving liquid hydrogen, liquid air, and liquefied natural gas. In addition to its novel grid formulation, the model offers significant advances over simpler lumped-parameter and complex fluid dynamics models in the literature and commercial process simulators. It gives useful practical insights into boil-off gas removal, pressure management, evaporation/condensation, and compressor sizing/operation. [ABSTRACT FROM AUTHOR]

Despite heavy insulation, the unavoidable heat leak from the surroundings into an LNG (Liquefied Natural Gas) storage tank causes boil-off-gas (BOG) generation. A comprehensive dynamic CFD simulation of an onshore full-scale LNG tank in a regasification terminal is presented. LNG is approximated as pure methane, the axisymmetric VOF (Volume of Fluid) model is used to track the vapour-liquid interface, and the Lee model is employed to account for the phase change including the effect of static pressure. An extensive investigation of the heat ingress magnitude, internal flow dynamics, and convective heat transfer gives useful insights on the boiling phenomena and a reliable quantification of the BOG. Surface evaporation is the governing boiling mechanism and nucleate boiling is unlikely with proper insulation. The critical wall superheat marking the transition from surface evaporation to nucleate boiling is estimated as 2.5–2.8 K for LNG. [ABSTRACT FROM AUTHOR]

The generation of boil-off gas (BOG) is inevitable in liquefied-natural-gas (LNG) regasification terminals. It can be a safety concern and, in most cases, demands BOG reliquefaction before regasification. This study presents a fundamental thermodynamic analysis of the BOG reliquefaction-LNG regasification process, which consumes significant power. We propose an evolving series of schemes that exploit the cryogenic energy of the send-out LNG to reduce the total power consumption. We synergistically integrate options such as BOG precooling, recompression, interstage cooling, and recondensation in our proposed schemes. We develop a nonlinear programming (NLP) formulation to minimize the power required for each scheme for a given amount of BOG. Under some idealistic assumptions, the optimal solutions to these NLPs give lower bounds on the total power consumption, which can be used to evaluate the cost-effectiveness of terminal operations. A novel scheme consisting of BOG precooling before compression and two-stage recondensation by direct mixing has the least power consumption. For a case-study terminal, it offers 11.9% lower power consumption than the best-reported design in the literature for 15% BOG. [ABSTRACT FROM AUTHOR]

• Systematic procedure to develop physics-based empirical models for predicting gas flow and power for reciprocating compressors with suction valve unloaders. • Embedding proposed models within commercial process simulators like Aspen HYSYS or Unisim. • Demonstrating utility of our empirical models for simulating steady state and dynamic operations of reciprocating compressors. • Illustrating the full range application of our contribution using real data from a BOG compression train in an LNG regasification terminal. • Usefulness of our empirical models for real life applications is elucidated by comparing them with popular machine learning approaches. Major countries are installing Liquefied Natural Gas (LNG) terminals worldwide, as they transition towards carbon-free economies. Compressors are energy-intensive equipment in LNG import/export terminals. While reciprocating compressors are in wide use, models to estimate volumetric and energetic efficiencies do not exist, especially for those with suction valve unloaders. Furthermore, commercial process simulators such as Aspen HYSYS or Unisim are not equipped to simulate them rigorously. This paper presents a procedure to develop empirical models for predicting flow and power based on process insights and real operational data. It also demonstrates how these models can be embedded inside simulators to simulate compressor operations in both steady and dynamic modes. Real data from a BOG compressor train in an LNG regasification terminal are used to illustrate the full range of their applications. Finally, the suitability and efficacy of data-driven machine learning approaches are evaluated to show the superiority of proposed empirical models. [ABSTRACT FROM AUTHOR]

Liquefied Natural Gas (LNG) is the best mode to transport natural gas from producing locations to importing countries when pipeline transport is not feasible. LNG industry has seen a phenomenal growth due to the widespread adoption of natural gas as a clean fuel. There is an ongoing effort to develop new technologies that can utilize LNG cold energy which is mostly being wasted at the LNG regasification terminals around the world. This work presents a novel conceptual design for a clathrate hydrate based desalination (HyDesal) process by utilizing LNG cold energy (ColdEn-HyDesal). This ColdEn-HyDesal process overcomes the high energy consumption of the traditional HyDesal process by using the cold energy of LNG to replace the external refrigeration cycle. An optimal heat exchanger network for the ColdEn-HyDesal process is obtained by employing mathematical programming based heat integration methodology for the LNG flow rate of 1000 kg/h in an LNG regasification terminal. The results indicate that the specific energy consumption (SEC) of the HyDesal process is 65.29 kWh/m 3 of potable water, while that of the ColdEn-HyDesal process is only 0.60 kWh/m 3 when the hydrate former is not recycled. When the hydrate former is recycled, then the specific energy consumption of the HyDesal process is 65.13 kWh/m 3 , while that of the ColdEn-HyDesal process is only 0.84 kWh/m 3 . In addition, the effects of recovery pressure, water recovery rate, and NaCl concentration in seawater on SEC and the volumetric rate of potable water are also analyzed and discussed. The results show that the SEC decreases substantially (27.42%) with the increase of water recovery from 40% to 70% in one hour. Further, the NaCl concentration in the feed has a small impact on the SEC, which only increases by 2.81% when the NaCl concentration increases from 3.5 wt% to 7.0 wt%. Thus, the ColdEn-HyDesal process is an energy efficient desalination process and can be a potential technology to desalinate seawater, and high concentration brines in an LNG regasification terminal. [ABSTRACT FROM AUTHOR]

A comprehensive dynamic model for an LNG storage tank in a typical regasification terminal, operating in holding mode, is presented. The model incorporates LNG recirculation for cooling the transfer lines for loading/unloading. It assumes a hypothetical thin vapour interface in equilibrium with the liquid to compute LNG evaporation, which allows the boil-off gas to be hotter than the tank LNG, as observed in practice. A numerical procedure based on the secant method is implemented in MATLAB for solving the governing ordinary differential equations. For the special case of N 2 -free LNG, a semi-analytical solution is proposed to solve the dynamic model for this relatively complex system and compute the amount of boil-off gas (BOG). The semi-analytical solution is subsequently used to optimize the LNG storage tank and recirculation loop designs. [ABSTRACT FROM AUTHOR]

• Techno-economic analysis of upfront nitrogen removal (UNR) in the LNG plant is presented. • The lithium cycle as a UNR technology is retrofitted with the cold section of the LNG plant. • Revenue generated by ammonia sale, produced as a byproduct in the lithium cycle. • Lithium cycle retrofitted with cold section yielded significant improvements in the profit. As the world's energy demand grows, the LNG industry is gaining popularity as a cleaner fossil fuel source. Studies on process enhancement have proposed that retrofitting upfront nitrogen removal (UNR) technologies like the lithium cycle to the cold section, increases the process efficiency, and plant capacity and decreases power consumption. In this paper, an economic evaluation is conducted for varying percentages of UNR to study its profitability compared to the conventional cold section (base case) by calculating the grass-root capital expenditure (CGR) and cost of manufacturing (COM). The cost incurred to produce one million BTU LNG (COE) is used as a basis to compare the cases and calculate the increment in profit. While the techno-economic impact was studied for a range of UNR percentages, the specific results for 87.5 % UNR are as follows. The CGR and COM for the cold section alone decrease by 3.2% and 2.3% respectively compared to the base case. The CGR and COM of the lithium cycle increase linearly with the UNR percentage. The total annual cost (TAC) and LNG energy content increased by 12.3% and 4.5% respectively over the base process. This leads to a 7.4% COE increment over the base case for 87.5% UNR. The profit calculation for LNG price of 15$/MBTU showed a 4.27% or 101.74 million $/year increase in profit for 87.5% UNR case as compared to the base case. [ABSTRACT FROM AUTHOR]